A nn* Unfed Slatss
^ Environmental Protectran
I Agency
Mandatory Greenhouse Gas
Reporting Rule: EPA's Response
to Public Comments
Volume No.:15
Subpart C - General Stationary Fuel
Combustion Sources
-------
September 2009
Subpart C - General Stationary Fuel
Combustion Sources
U. S. Environmental Protection Agency
Office of Atmosphere Programs
Climate Change Division
Washington, D.C.
-------
FOREWORD
This document provides EPA's responses to public comments on EPA's Proposed Mandatory
Greenhouse Gas Reporting Rule. EPA published a Notice of Proposed Rulemaking in the
Federal Register on April 10, 2009 (74 FR 16448). EPA received comments on this proposed
rule via mail, e-mail, facsimile, and at two public hearings held in Washington, DC and
Sacramento, California in April 2009. Copies of all comments submitted are available at the
EPA Docket Center Public Reading Room. Comments letters and transcripts of the public
hearings are also available electronically through http://www.regulations.gov by searching
Docket ID EPA-HQ-OAR-2008-0508.
Due to the size and scope of this rulemaking, EPA prepared this document in multiple volumes,
with each volume focusing on a different broad subject area of the rule. This volume of the
document provides EPA's responses to the significant public comments received for 40 CFR Part
98, Subpart C — General Stationary Fuel Combustion Sources.
Each volume provides the verbatim text of comments extracted from the original letter or public
hearing transcript. For each comment, the name and affiliation of the commenter, the document
control number (DCN) assigned to the comment letter, and the number of the comment excerpt is
provided. In some cases the same comment excerpt was submitted by two or more commenters
either by submittal of a form letter prepared by an organization or by the commenter
incorporating by reference the comments in another comment letter. Rather than repeat these
comment excerpts for each commenter, EPA has listed the comment excerpt only once and
provided a list of all the commenters who submitted the same form letter or otherwise
incorporated the comments by reference in table(s) at the end of each volume (as appropriate).
EPA's responses to comments are generally provided immediately following each comment
excerpt. However, in instances where several commenters raised similar or related issues, EPA
has grouped these comments together and provided a single response after the first comment
excerpt in the group and referenced this response in the other comment excerpts. In some cases,
EPA provided responses to specific comments or groups of similar comments in the Preamble to
the final rulemaking. Rather than repeating those responses in this document, EPA has
referenced the Preamble.
While every effort was made to include the significant comments related to 40 CFR Part 98,
Subpart C — General Stationary Fuel Combustion Sources in this volume, some comments
inevitably overlap multiple subject areas. For comments that overlapped two or more subject
areas, EPA assigned the comment to a single subject category based on an assessment of the
principle subject of the comment. For this reason, EPA encourages the public to read the other
volumes of this document with subject areas that may be relevant to 40 CFR Part 98, Subpart C -
- General Stationary Fuel Combustion Sources.
in
-------
The primary contacts regarding questions or comments on this document are:
Carole Cook (202) 343-9263
U.S. Environmental Protection Agency
Office of Atmospheric Programs
Climate Change Division
Mail Code 6207-J
1200 Pennsylvania Avenue, NW
Washington, D.C. 20460
ghgreportingrule@epa.gov
iv
-------
TABLE OF CONTENTS
Section Page
1. DEFINITION 01 SOURCE CATEGORY 1
2. REPORTING THRESHOLD 87
3. GIIGS TO REPORT 93
4. SELECTION OF PROPOSED GHG EMISSIONS CALCULATION AND
MONITORING METHODS 105
5. DETAILED GHG EMISSION CALCULATION PROCEDURES/EQUATIONS IN THE
RULE 265
6. MONITORING AND QA/QC REQUIREMENTS 357
7. PROCEDURES FOR ESTIMATING MISSING DATA 427
8. DATA REPORTING REQUIREMENTS 437
9. RECORDS THAT MI ST BE RETAINED 492
10. COST DATA 493
11. OTHER SUBPART C COMMENTS 506
12. CALCULATION OF BIOGENIC EMISSIONS 508
1
-------
1. DEFINITION OF SOURCE CATEGORY
Commenter Name: Karen St. John
Commenter Affiliation: BP America Inc. (BP)
Document Control Number: EPA-HQ-OAR-2008-0508-0631.1
Comment Excerpt Number: 34
Comment: Continuous Emissions Monitoring System §98.6 (p. 16618): EPA's definition of
CEMS includes a requirement for "readings every 15 minutes" which is not appropriate for a
definition.
Response: See the Preamble and separate comment response document volumes for the
response on the general monitoring approach and general recordkeeping requirements.
The commenter does not claim that the frequency of readings by equipment qualifying as a
CEMS should be different than at least once every 15 minutes, but rather claims that a
requirement for readings every 15 minutes is "not appropriate" to include in a definition. EPA
rejects this comment because it is certainly reasonable to include, in the definition of a term
(CEMS) that, on its face, includes the concept of "continuous" monitoring, a performance
specification concerning frequency of monitored readings. Moreover, this performance
specification has been used in defining "CEMS" in the Acid Rain Program since the program
began in 1995 and, in conjunction with other elements of the monitoring requirements in that
program, has resulted in a high level of data quality and consistency.
Commenter Name: Randall R. LaBauve
Commenter Affiliation: Florida Power & Light (FPL) Group
Document Control Number: EPA-HQ-OAR-2008-0508-0624.1
Comment Excerpt Number: 12
Comment: Proposed §§98.30 and 98.40 would exempt portable equipment and emergency
generators from GHG emission reporting requirements. Due to the minimal GHG emissions
expected from such equipment, FPL Group supports the equipment's exemption from the
proposed reporting requirements. However, we believe that EPA has crafted the proposed
exemption too narrowly. Under proposed §§98.30 and 98.40, only portable equipment and
emergency generators that are designated as emergency generators in a permit issued by a state
or local air pollution control agency would be exempt from the reporting requirements of the
regulation. FPL Group believes that the permit designation restriction is unnecessary. Because
GHG emissions from such equipment are generally minimal, and because exempt emergency
generators would already be required to meet the specifications listed in the definition of
"emergency generators" under proposed §98.6, there is no reason to add a further restriction that
the equipment be listed in a permit. Some states exempt emergency generators from
construction or operating permits if certain operating criteria are met. For example, in Wisconsin
an emergency electric generator means "an electric generator whose purpose is to provide
electricity to a facility if normal electrical service is interrupted and which is operated no more
than 200 hours per year." Wis. ADMIN. CODE NR 400.02(56). An emergency electrical
generator fitting this definition is exempt from construction or operating permit requirements
1
-------
provided it is "powered by internal combustion engines which are fueled by gaseous fuels,
gasoline or distillate fuel oil with an electric output of less than 3,000 kilowatts." Wis. ADMIN.
CODE NR 406.04(l)(w) and 407.03(l)(u)). As a result of such state exemptions, emergency
generators may be designated as emergency generators by the state, but not included in the state
or local air pollution control agency permit. For these reasons, FPL Group believes that
proposed §§98.30 and 98.40 should be revised to simply state that portable equipment and
emergency generators that meet the definition of "emergency generators" under §98.6 are
excluded from the proposed reporting requirements of applicable source categories. At a
minimum, EPA should expand the exemption to apply not only to emergency generators that are
exempted by permit but also to emergency generators that are exempted from permitting.
Response: EPA has maintained the exclusion of emergency generators, and has excluded other
emergency equipment from reporting. EPA has also revised the rule language to exclude the
prerequisite for a state or local permit. Please refer to the full definitions of emergency generator
and emergency equipment in §98.6.
Commenter Name: Edward N. Saccoccia
Commenter Affiliation: Praxair Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-0977.1
Comment Excerpt Number: 1
Comment: The proposed rule appropriately excludes minor combustion sources from the
definition of the Stationary Fuel Combustion source category, in particular process safety flares.
Praxair supports this effort to minimize the burden on regulated facilities, as these units typically
have very low emissions, typically do not have measured flow rates, and do not make a
substantial impact on the total greenhouse gas inventory. Where flaring operations are a routine
operating control of a facility, such as in refineries, EPA has explicitly included emission
estimation and reporting requirements. Clarify that flare emissions should only be included in
the calculations of Subpart C of the rule if another subpart of the rule explicitly requires such
emission calculation and reporting. Flare emissions should be otherwise excluded categorically
or as a de minimis source.
Response: EPA has revised the language of the final rule to expand the list of exempted source
categories to include flares as defined in §98.6, except where required to report by provisions of
another subpart of Part 98 (see §98.30(b)).
Commenter Name: See Table 5
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0480.1
Comment Excerpt Number: 41
Comment: Section §98.30(b) excludes emergency generators from the Subpart C source
category. However, §98.30(b) indicates that the generators need to be designated as emergency
generators in a permit issued by a state or local air pollution control agency. The permitting
requirement should be removed from this provision. Requirements differ for different
2
-------
jurisdictions. For example, units with a rating below a certain size may not be included in a
permit. Thus, the small emergency units that EPA is attempting to exempt are exactly the type
that is most likely to not be in a permit, because states are more likely to not require permits for
small units. Section §98.30(b) should simply exempt portable and emergency units and delete
the qualifying phrase related to permitting. Additional clarification on engine classification may
be warranted, but the permit requirement must be deleted from the rule to avoid applicability for
many small, emergency engines.
Response: EPA has maintained the exclusion of emergency generators, and has excluded other
emergency equipment from reporting. Without further elucidation of what clarification on
engine classication is sought, EPA is unable to respond to such a general comment. EPA has
also revised the rule language to exclude the prerequisite for a state or local permit. Please refer
to the full definitions of emergency generator and emergency equipment in §98.6.
Commenter Name: Rich Raiders
Commenter Affiliation: Arkema Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-0511.1
Comment Excerpt Number: 40
Comment: Some facilities using liquid or solid fuels only track fuel usage on an as-delivered
basis. These facilities collect fuel data upon receipt of each shipment of fuel oil or coal, and
assume that all purchased fuel is consumed in the year of purchase. This step occurs because
these facilities, some of whom will likely become subject to Part 98, have not needed to install
accurate liquid or solid fuel measurement systems. Also, operators of emergency generators
sometimes track fuel usage as a function of run time, where the fuel usage is estimated by the
total run time multiplied by the maximum hourly rated fuel usage. EPA should authorize this
approach for emergency generators, portable temporary generators used for short time periods at
a facility, and smaller internal combustion engines not equipped with Subpart C fuel
measurement systems. Many of these systems are used by a facility during maintenance events,
emergencies, or other short-term purposes, and are shipped as packaged units without the
customer/report being able to modify the system. If EPA does not exempt emergency generators
or small internal combustion engines from reporting, EPA should allow these standard emission
estimation methods to be used for portable generators or similar units. Also, EPA should defer
to the September 6, 1995 emergency generator guidance describing EPA's approach to
emergency generator use. http://www.epa.gov/ttn/oarpg/t5/memoranda/emgen.pdf EPA's
policy, which can be adjusted by the local permitting authorities as required, recommended 500
hours per year as an appropriate threshold for the appropriate operating time for emergency
generators. Part 98 should not seek to overturn this memo, where the permitting authorities have
made a series of decisions based on this historic EPA decision. EPA should presumptively
exempt emergency generators properly authorized by the appropriate permitting authority from
this reporting rule.
Response: See the Preamble, Section II. K., and response to comment EPA-HQ-OAR-2008-
0508-0423.2 excerpt 40 for the response on de minimis reporting for small emission points.
EPA has maintained the exclusion of emergency generators, has excluded other emergency
equipment, as defined in §98.6, and has revised the language to remove the prerequisite for a
3
-------
state or local permit. Portable equipment, as defined in §98.6, is also exempt from reporting.
Other small stationary combustion sources may use the calculation methods provided in Tier 1 or
Tier 2, and stationary combustion sources using homogenous fuels like natural gas and diesel oil
may use Tier 2. Both of these tiers allow facilities to determine fuel use based on company
records, and do not require the direct measurement of fuel flow.
Commenter Name: Rich Raiders
Commenter Affiliation: Arkema Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-0511.1
Comment Excerpt Number: 39
Comment: EPA should explicitly state that facilities do not need to report fuel use for comfort
heating and hot water heater (for personal use) purposes. Some facilities may not have accurate
flow meters measuring domestic hot water heaters and comfort heaters, and compliance with the
Subpart C provisions are not appropriate for these types of units. Smaller facilities should also
have the option of using site-wide gas consumption meters in lieu of individual commodity fuel
metering.
Response: See the Preamble and separate comment response document volume for the response
on monitoring and QA/QC requirements, and de minimis reporting for small emission points.
In preparation of the final rule, EPA has revised many sections of the rule that may be relevant to
this comment. First, in order to reduce the burden of compliance, EPA has explicitly allowed for
the use of company records to determine fuel consumption. EPA has also removed the
cumulative 250 mmBtu/hr restriction on unit aggregation, and has clarified the common pipe
reporting option. In §98.30, EPA has expanded the list of sources excluded from coverage;
however, this expansion does not include comfort heating and hot water (for personal use)
purposes, and as such, these activities would be included under Subpart C for facilities that are
required to comply with Part 98.
Commenter Name: Michael DiMauro
Commenter Affiliation: Massachusetts Municipal Wholesale Electric Company (MMWEC)
Document Control Number: EPA-HQ-OAR-2008-0508-0580
Comment Excerpt Number: 4
Comment: EPA should re-consider its decision to not exempt small and/or low utilization
stationary combustion units from GHG Reporting. Rather it is proposed that a DeMinimus
category be established that would include combustion units with a design heat input < 20-5 0
MMBtu/hr and/or units that have limited utilization (e.g. < 25%). Alternatively this Deminimus
category could be defined by a CO2 emission restriction of perhaps 100 tons/year, to be
demonstrated by simple estimation methods. Units satisfying these Deminimus criteria would be
exempt from GHG Reporting.
Response: See the Preamble and separate comment response document volume for the response
on de minimis reporting for small emission points.
4
-------
EPA has expanded the list of exempted source categories to include portable equipment,
emergency generators, other emergency equipment, irrigation well devices, and flares. EPA has
also removed the cumulative 250 mmBtu/hr restriction on unit aggregation and clarified the use
of the common pipe alternative reporting provision, and believes that the expanded availability
of these options, which would allow site-wide gas consumption meters, will reduce the reporting
burden on facilities.
Commenter Name: Karen St. John
Commenter Affiliation: BP America Inc. (BP)
Document Control Number: EPA-HQ-OAR-2008-0508-0631.1
Comment Excerpt Number: 37
Comment: Emergency generator §98.6 (p. 16620): The definition of'Emergency generator'
states "the hours of operation per calendar year for performance testing shall not exceed 100
hours." BP requests that the specification of hours be removed from the definition of emergency
generators. It is not reasonable to limit the number of hours.
Response: EPA has maintained the exclusion of emergency generators, and has excluded other
emergency equipment from reporting. The final rule eliminates the 100 hour limitation for
emergency generators. Please refer to the full definitions of emergency generator and emergency
equipment in §98.6. ""
Commenter Name: Sarah E. Amick
Commenter Affiliation: The Rubber Manufacturers Association (RMA)
Document Control Number: EPA-HQ-OAR-2008-0508-0647.1
Comment Excerpt Number: 4
Comment: RMA opposes the requirement that facilities report electricity generated from
portable and emergency generators. Portable and emergency generators are operated during a
limited time per year. In fact, EPA's proposed National Emissions Standards for Hazardous Air
Pollutants for Reciprocating Internal Combustion Engines (RICE MACT) would reduce the
regulatory burden based on the limited operation of these emergency generators to 100 hours per
year. (74 Fed. Reg. 9698). Requiring data regarding electricity generated from these types of
engines is burdensome and creates no environmental benefit.
Response: EPA agrees with the commenter, and the final rule maintains the exclusion of
emergency generators, eliminates the 100-hour limitation for emergency generators, has
excluded other emergency equipment, as defined in §98.6, and has revised the rule language to
remove the prerequisite for a state or local permit. Portable equipment, as defined in §98.6, is
also exempt from reporting. This exemption applies to both Subpart C and Subpart D.
5
-------
Commenter Name: See Table 5
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0480.1
Comment Excerpt Number: 34
Comment: INGAA supports the aggregation approaches for unit-level reporting identified in
§98.36(c). §98.36(c)(1) allows aggregate reporting for up to 250 MMBtu/hr of combustion
sources at a facility and §98.36(c)(3) allows multiple gas-fired or oil-fired units fed through a
common fuel line to report insignificant affect on facility emissions. Affected sources are faced
with significant implementation challenges due to the breadth and timing of the Proposed Rule,
and the additional burden associated with reporting trivial emissions is not warranted. INGAA
recommends that a 10 MMBtu/hr exemption threshold be included in the rule for combustion
sources.
Response: See the Preamble and separate comment response document volume for the response
on de minimis reporting for small emission points.
EPA appreciates the commenter's support of the reporting alternatives provided in §98.36(c).
The final rule includes further clarification and flexibility regarding aggregation and common
pipe provisions that will reduce the burden on sources. First, in order to reduce the burden of
compliance, EPA has explicitly allowed for the use of company records to determine fuel
consumption. EPA has also removed the cumulative 250 mmBtu/hr restriction on unit
aggregation, and has clarified the common pipe reporting option. In §98.30, EPA has expanded
the list of sources excluded from coverage. These sources would be included under Subpart C
for facilities that are required to comply with Part 98.
Commenter Name: Fiji George
Commenter Affiliation: El Paso Corporation
Document Control Number: EPA-HQ-OAR-2008-0508-0398.1
Comment Excerpt Number: 33
Comment: Addressing flares in Subpart C would ensure consistent treatment of this equipment
in each industry segment and would be a step toward streamlining the regulation.
Response: EPA has revised the language of the final rule to exclude flares as defined in §98.6
from reporting under Subpart C, except where required to report by provisions of another subpart
of Part 98 (see §98.30(b)). EPA believes that this revised language is appropriate because it will
require emissions to be reported for major flare sources (such as refinery flares), while sparing
the expense of reporting emissions for small miscellaneous flare sources.
6
-------
Commenter Name: Patrick J. Nugent
Commenter Affiliation: Texas Pipeline Association (TPA)
Document Control Number: EPA-HQ-OAR-2008-0508-0460.1
Comment Excerpt Number: 25
Comment: TPA recommends the use of two separate thresholds. TPA supports the inclusion of
a MMBtu/hr threshold for combustion sources, but we recommend that there be two such
thresholds: (1) a 50 MMBtu/hr threshold for sources combusting natural gas only, and (2) the 30
MMBtu/hr threshold for all other combustion sources. The proposed 30 MMBtu/hr threshold is
evidently based on the combustion of utility coal based on data from a July 7, 2008
memorandum from Leif Hockstad on "Maximum rated heat input capacity compared to 25,000
MMTC02e threshold." See docket item EPA-HQ-OAR-2008-0508-0049. Using the same data
from that memorandum for natural gas combustion, a 50 MMBtu/hr threshold would equate to
23,240 MMTC02e, which is less than the 25,000 threshold.
Response: See the Preamble and separate comment response document volume for the response
on selection of the threshold See the Preamble, Section II. E., and response to comment EPA-
HQ-OAR-2008-0508-0350.1 excerpt 3 for additional explanation of the selection and form of
thresholds..
EPA acknowledges the concerns of the commenter, but will continue to use the 25,000 metric
ton CC^e threshold for facilities that only include stationary combustion equipment. The 30
mmBtu/hr provision, as described in §98.2(a)(3)(ii) of the general provisions, is not a separate
threshold, but was given to provided guidance to smaller facilities that might not be subject to
applicability determinations.
Commenter Name: Ron Downey
Commenter Affiliation: LWB Refractories
Document Control Number: EPA-HQ-OAR-2008-0508-0719.1
Comment Excerpt Number: 25
Comment: 40 C.F.R. 98.33 and Table C-l require sources to include biomass fuel emissions in
the emissions calculation for stationary fuel combustion sources. LWB believes that biomass
should be excluded from the emissions calculation for stationary fuel combustion sources
because biomass offsets carbon emission from fossil fuel combustion and is also considered
carbon neutral. See link: http://www.eia.doe.gov/oiaf/1605/coefficients.html. NLA proposes
that biomass (which does not encompass municipal solid waste) be excluded from the emissions
calculation for stationary fuel combustion sources because use of biomass fuel reduces GHG
emissions and biomass emissions are not included in determining whether a source meets the
emissions threshold. 40 C.F.R 98.33.
Response: See the response to comment EPA-HQ-OAR-2008-0508-0690.1 excerpt 1
corresponding to Section II. of the Preamble, and the response to comment EPA-HQ-OAR-2008-
0508-0631.1 excerpt 71 corresponding to Subpart C for additional explanation of the reporting of
biogenic CO2 emissions.
7
-------
While EPA has decided to track biogenic emissions separately, they still must be included in the
total CO2 emissions reported. EPA believes that it is clear in the revised §98.2 that CO2
emissions from biogenic fuels do not count toward the 25,000 metric ton threshold for reporting
for stationary combustion units, although CH4 and N2O emissions from biogenic fuels must be
considered. In this rule, EPA does not assess carbon neutrality or offsets.
Commenter Name: Sam Chamberlain
Commenter Affiliation: Murphy Oil Corporation
Document Control Number: EPA-HQ-OAR-2008-0508-0625
Comment Excerpt Number: 25
Comment: "EPA is proposing to not require reporting of emissions from portable equipment or
generating units designated as emergency generators in a permit issued by a state or local air
pollution control agency. We request comment on whether or not a permit should be required
for these emergency generators." (Preamble, p. 174) The exclusion should be not just for
permitted emergency generators, but for non-permitted emergency equipment (such as fixed
firewater pumps or non-permitted emergency generators). During Murphy turnarounds, or
emergency situations after hurricanes along the Texas/Louisiana Gulf Coast, there is a priority
need to get these generators on line as soon as possible in order to provide for the safety and
well-being of the citizens of the USA. In these crisis situations, getting fuel supplies to the
consumer is critical. Taking the time, energy, effort and resources to determine if specific
generators are permitted or not, seems to be an overzealous action that removes the protection
and welfare of our citizens, while trying to respond to an emergency. EPA should not require the
reporting of emergency generators under any circumstances.
Response: EPA has maintained the exclusion of emergency generators, and has excluded other
emergency equipment from reporting. EPA has also revised the rule language to remove the
prerequisite for a state or local permit. Please refer to the full definitions of emergency generator
and emergency equipment in §98.6.
Commenter Name: See Table 7
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0412.1
Comment Excerpt Number: 24
Comment: GPA opposes requiring the reporting of GHG emissions from temporary or portable
equipment. Temporary or portable equipment is generally used for such limited periods during
the year that the burden of monitoring, recordkeeping and reporting data from temporary or
portable equipment is disproportionate to the value of the data collected.
Response: EPA agrees with the commenter, and has exempted from reporting portable
equipment, as defined in §98.6 in the final rule language.
8
-------
Commenter Name: Fiji George
Commenter Affiliation: El Paso Corporation
Document Control Number: EPA-HQ-OAR-2008-0508-0398.1
Comment Excerpt Number: 38
Comment: El Paso supports the exclusion of emissions associated with emergency generators,
portable and temporary emissions units as defined under §98.6 from the proposed emissions
requirements under §98.30. However, the exclusion should be expanded beyond equipment
designated as emergency in air permits issued by state or local air pollution control agencies. It
should be noted that some emergency equipment may not require air permitting. It would take
considerable amount of effort and time from the regulated facilities and air pollution control
agencies to modify existing air permits to include these small units. El Paso recommends that
the exclusion be expanded to include any units represented as emergency units in the air permit
applications or correspondence to air pollution control agencies providing that these units are
operated as emergency units and the companies maintain adequate operating records to prove
emergency status of these units. The level of effort undertaken to document these emissions if it
were to be reported is unwarranted.
Response: EPA has maintained the exclusion of emergency generators, and has excluded other
emergency equipment from reporting. EPA has also revised the rule language to remove the
prerequisite for a state or local permit. Please refer to the full definitions of emergency generator
and emergency equipment in §98.6.
Commenter Name: Jack Gehring et al.
Commenter Affiliation: Caterpillar Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-0499.1
Comment Excerpt Number: 8
Comment: Caterpillar supports EPA's proposal (Section V (C), "General Stationary
Combustion Sources") to not require reporting of GHG emissions from already-permitted (by
state/local authorities) portable equipment or generating units designated as emergency
generators, but requests that EPA broaden the scope of this exemption to include manufacturers'
families of such emergency engines. Existing EPA regulations (the NSPS for Stationary
Combustion-Ignition Engines) already required emergency engine certification when Tier 4
begins. Use of these engines will be limited by the NSPS to emergency service and associated
testing only, and have specific emissions limits and unique labeling requirements. Because of
the certification requirements, specific emissions limits and use restrictions in existing EPA
regulations, Caterpillar requests that eligibility for this EPA exemption not depend upon
state/local authority permit coverage, especially since the exemption thresholds in non-major
source state permitting schemes vary widely, and eligibility for the exemption would be difficult
for both manufacturers and customers to determine. Accordingly, Caterpillar requests that EPA
broaden the scope of this exemption to include manufacturers' families of affected emergency
engines. At minimum, however, EPA should retain the proposed exemptions for engines
permitted by state/local authorities.
Response: EPA has maintained the exclusion of emergency generators, and has excluded other
emergency equipment from reporting. EPA has also revised the rule language to remove the
9
-------
prerequisite for a state or local permit. Please refer to the full definitions of emergency generator
and emergency equipment in §98.6.
Commenter Name: Anonymous
Commenter Affiliation: None
Document Control Number: EPA-HQ-OAR-2008-0508-0166
Comment Excerpt Number: 6
Comment: Consider excluding all diesel generators if they operate under a 500 hour per year
threshold, regardless if whether they are classified as "emergency only" gensets. Note the 500
hour limit is based on EPA guidance for PTE on emergency generators.
Response: See the Preamble for the response on de minimis reporting for small emission points,
which includes a discussion on small combustion devices that are not emergency generators.
Because of the need for comprehensive, national greenhouse gas emissions data, the final rule
provides only limited exclusions from the reporting requirements. In light of this need for
comprehensive data, EPA has instead taken the approach of limiting the exclusions but allowing
reporting methods that provide data of a sufficient level of quality and consistency for the
purposes of this rule but that reduce the reporting burden on reporters. For example, in the final
rule, EPA has maintained the exclusion of emergency generators, has removed for such
generators the 100-hour limitation and the requirement of designation in a state or local permit,
and has excluded other emergency equipment from reporting. See §98.6, which includes
definitions of emergency generator and emergency equipment. Diesel generators that operate
under 500 hours per year are not necessarily for emergency use only but may operate for other
purposes, and, particularly since the generators can be of widely varying sizes, the GHG
emissions from these generators cannot be assumed to be, and treated as, insignificant. While
this category of sources is, for the above-discussed reasons, not excluded from reporting, the
final rule allows the use of an aggregation of units method found in §98.36(c)(1) for reporting
multiple combustion devices individually rated at 250 mmBtu/hr or less that reduces the burden
to the reporter in accounting for small combustion devices that are not emergency generators.
Other small stationary combustion sources may use the calculation methods provided in Tier 1 or
Tier 2 in the rule. In particular, stationary combustion sources using homogenous fuels like
natural gas and diesel oil may use the calculation methods provided in Tier 2.
Commenter Name: Andrew C. Lawrence
Commenter Affiliation: Department of Energy (DOE)
Document Control Number: EPA-HQ-OAR-2008-0508-0612.1
Comment Excerpt Number: 12
Comment: Many complex facilities subject to the reporting rule under §98.2(a)(1), (a)(2), or
(a)(3) will be required to inventory a large number of small combustion units covered by the
rule. DOE believes a size threshold is needed in the stationary combustion source category to
reduce undue cost burden while still achieving the goal of obtaining GHG data of sufficient
quality that it can be used to support a range of future climate change policies and regulations.
DOE recommends that the source definition in Subpart C be aligned to match the intent of the
rule to focus on large emitters and to clarify the sources subject to the rule. In particular, this
10
-------
should include definitions for commercial and residential fuel combustion sources; exclude
residential units from the source category; and set a capacity threshold for commercial-size units,
such as 10 million British Thermal Units, (the current exemption from the Boiler maximum
achievable control technology (MACT) and for many state Title V programs), that are excluded
from the source.
Response: See the Preamble for the response on de minimis reporting for small emission points.
EPA agrees that residential sources should not be included in the category of stationary fuel
combustion sources and notes that §98.30 does not include residential sources. That section
states that stationary fuel combustion sources are "devices that combust solid, liquid, or gaseous
fuel, generally for the purposes of producing electricity, generating steam, or providing useful
heat or energy for industrial commercial or institutional use, or reducing the volume of waste by
removing combustible matter" (emphasis added).
EPA does not agree that a size threshold for reporting for commercial sources is warranted.
Because of the need for comprehensive, national greenhouse gas emissions data, the final rule
provides only limited exclusions from the reporting requirements. In light of this need for
comprehensive data, EPA has instead taken the approach of limiting the exclusions but allowing
reporting methods that provide data of a sufficient level of quality and consistency for the
purposes of this rule but that reduce the reporting burden on reporters. For example, EPA has
excluded from the reporting requirements emergency generators and other emergency
equipment, but has not adopted a 10 mmBtu/hr capacity threshold for commercial units. Such
commercial units may be routinely used, and so the GHG emissions from these units cannot be
assumed to be, and treated as, insignificant. While this category of sources is, for the reasons
discussed above, not excluded from reporting, the final rule removes the cumulative 250
mmBtu/hr restriction on unit aggregation and clarifies the common pipe reporting option. The
rule also explicitly allows for the use of company records to determine fuel consumption.
Commenter Name: Kelly R. Carmichael
Commenter Affiliation: NiSource
Document Control Number: EPA-HQ-OAR-2008-0508-1080.2
Comment Excerpt Number: 11
Comment: NiSource agrees with EPA for proposing to not require reporting of GHG emissions
from portable equipments and generating units designated as emergency generators. However,
EPA should eliminate the state and local permit requirement attached to this exemption.
Requirements differ for different jurisdictions. Based on the experience of NiSource operating in
more than 10 states, the state permit requirements vary considerably within our operations. The
definition of emergency generator also varies in air pollution control programs from state to
state. NiSource requests that EPA should clarify that portable equipments and emergency
generators are exempt from every source category, including electricity generation.
Response: EPA has revised the rule language to remove the requirement for a state or local
permit to be attached to the exemption for portable or emergency generating equipment. Please
refer to the full definitions of emergency generator and emergency equipment in §98.6. This
exemption applies to the electricity generation source category, as well as the general stationary
combustion source category.
11
-------
Commenter Name: Sarah E. Amick
Commenter Affiliation: The Rubber Manufacturers Association (RMA)
Document Control Number: EPA-HQ-OAR-2008-0508-0647.1
Comment Excerpt Number: 10
Comment: Subpart C of the proposed rule excludes emissions reporting from portable
equipment or generating units designated as emergency generators in a permit issued by a state
or local air pollution control agency. EPA requested comment on whether or not a permit should
be required for these emergency generators (74 Fed. Reg. at 16480). RMA believes this
requirement is too restrictive. Many tire industry facilities have pumps that are integral
components of facility fire suppression systems. The pumps are often driven by diesel-fired
internal combustion engines. These engines would typically meet the proposed definition of
emergency generators. However, since they are considered emergency equipment, they are often
excluded from state and local air permit requirements. In fact, typically, these engines need not
even be included in air permit applications. Furthermore, when such equipment is included in an
air permit it is unlikely to be designated specifically as an "emergency generator." Thus, the
proposed requirement that such equipment be designated as emergency generators in an air
permit, would fail to exclude the majority of such equipment. Therefore, RMA recommends that
the proposed requirement be revised to exclude emissions reporting from portable equipment or
generating units that operate in compliance with state or local air pollution control agency
requirements.
Response: EPA has revised the rule language to remove the prerequisite for a state or local
permit for emergency generators. Please refer to the full definitions of emergency generator and
emergency equipment in §98.6.
Commenter Name: Chris Hornback
Commenter Affiliation: National Association of Clean Water Agencies (NACWA)
Document Control Number: EPA-HQ-OAR-2008-0508-0566.1
Comment Excerpt Number: 10
Comment: Additional clarification is needed on the scope of the combustion units that must be
included. Are units that are currently considered insignificant activities under Title V required to
be included? For example, are small boilers or furnaces using natural gas to heat office space
required to be included when calculating total facility emissions for comparison against the
threshold?
Response: See the Preamble for the response on de minimis reporting for small emission points.
EPA has revised the final rule to clarify the definition of the stationary combustion source
category. EPA intends that this source category will capture combustion sources that are not
associated with another source category as defined in the rule. The commenter should consider
§98.2(a)(3) about whether the facility needs to report under the rule, and §98.30 in order to
determine whether specific units should be included in emissions calculations.
12
-------
Commenter Name: Verne Shortell
Commenter Affiliation: NRG Energy, Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-0634.1
Comment Excerpt Number: 2
Comment: This section can be read to mean that only portable equipment and emergency
generators that are included in a site permit (NSR, PSD, Title V) are exempt from the reporting
requirements of the regulation. Since GHG emissions from such equipment should be minimal
and emergency generators are only exempt from reporting if they meet the specifications listed in
the definition (§98.6; page 16620), there is no reason to add a further requirement that the
equipment be listed in a permit. This section should be revised to state that portable equipment
and emergency generators meeting the definition in Section 98.6 are exempt from the GHG
reporting requirements.
Response: EPA has maintained the exclusion of emergency generators, and has excluded other
emergency equipment from reporting. EPA has also revised the rule language to remove the
prerequisite for a state or local permit. Please refer to the full definitions of emergency generator
and emergency equipment in §98.6. Portable equipment, as defined in §98.6, is also exempt
from reporting.
Commenter Name: Kelly R. Carmichael
Commenter Affiliation: NiSource
Document Control Number: EPA-HQ-OAR-2008-0508-1080.2
Comment Excerpt Number: 9
Comment: After review of Part 98.30, it appears that a "combustion source" and a "device" are
synonymous, but then there is no further clarification. EPA needs to explain the difference
between a "combustion source" and a "device."
Response: In response to the comments, EPA does not believe that any additional language is
needed to address the differences between the terms "combustion source," "combustion unit,"
and "device," as they are used in Subpart C. As stated in §98.30 of the final rule, "Stationary
fuel combustion sources are devices that combust solid, liquid, or gaseous fuel, generally for the
purposes of producing electricity, generating steam, or providing useful heat or energy for
industrial, commercial, or institutional use, or reducing the volume of waste by removing
combustible matter." The use of the word "device" is not limited in any way by the definition of
the source category, general stationary fuel combustion. "Source" refers to those devices that do
meet the provisions of the definition of the source category, as presented in §98.30. "Unit"
generally describes a device that could be subject to the reporting requirements (were it to meet
the specifications listed in §98.30).
13
-------
Commenter Name: Thomas Siegrist
Commenter Affiliation: Koch Nitrogen Company LLC
Document Control Number: EPA-HQ-OAR-2008-0508-0351.1
Comment Excerpt Number: 16
Comment: The Proposed Rule would not require reporting of emissions from portable
equipment or generating units designated as emergency generators in a permit issued by a state
or local air pollution control agency (proposed §98.30(b)). KNC strongly agrees that reporting
of GHG emissions from such sources would not significantly improve the accuracy of a GHG
emissions inventory; however the proposed requirement that such units must be included in a
state or local air permit in order for their emissions to be excluded is not warranted. If inclusion
of the entire class of such sources would not significantly affect the accuracy of an emissions
inventory, inclusion of a sub-set of that class would be even less meaningful. Moreover, many
air permitting agencies simply exempt emergency generators from permitting requirements, and
EPA has approved such permitting exemptions in numerous state implementation plans. As
written, the Proposed Rule would require reporting for all emergency generators located in those
states, creating disparate reporting on similarly situated equipment in different states. For these
reasons, EPA should revise the proposed exclusion to include not only equipment designated in
an air permit but also all portable equipment and all equipment used in emergency service that is
exempt from air permit requirements by the rules of the applicable state or local air pollution
control agency.
Response: EPA has maintained the exclusion of emergency generators, and has excluded other
emergency equipment from reporting. EPA has also revised the rule language to remove the
prerequisite for a state or local permit. Please refer to the full definitions of emergency generator
and emergency equipment in §98.6. Portable equipment, as defined in §98.6, is also exempt
from reporting.
Commenter Name: Stephen B. Kemp
Commenter Affiliation: Occidental Chemical Corporation (OCC)
Document Control Number: EPA-HQ-OAR-2008-0508-0644.1
Comment Excerpt Number: 7
Comment: In Section V.C. of the preamble to the proposed rule (74 FR 68, page 16480), the
following is stated: "EPA is proposing to not require reporting of emissions from portable
equipment or generating units designated as emergency generators in a permit issued by a state
or local air pollution control agency. We request comment on whether or not a permit should be
required for these emergency generators." EPA need not require that portable and emergency
equipment and units be authorized by a permit in order to be exempt from the GHG reporting
rule. The use of portable or emergency generators in the State of Texas, for example, is
generally authorized by a Permit-By-Rule, and depending on the capacity of the unit, may not
require the submittal of a state-specific form or document, or any receipt of confirmation from
the Texas Commission on Environmental Quality. While OCC has not undertaken an exhaustive
review of other state rules or requirements, we believe that other similar types of regulatory
authorizations exist. We support the exclusion of portable and emergency generators from the
definition of Stationary Fuel Combustion Sources. However, we believe that the language
proposed at §98.40(b) should read as follows: (b) This source category does not include portable
14
-------
equipment or generating units designated as emergency generators issued as authorized by a
State or local air pollution control agency's rules or requirements.
Response: EPA has maintained the exclusion of emergency generators, and has excluded other
emergency equipment from reporting. EPA has also revised the rule language to remove the
prerequisite for a state or local permit. Please refer to the full definitions of emergency generator
and emergency equipment in §98.6.
Commenter Name: Paul L. Carpinone
Commenter Affiliation: Tampa Electric Company (TECO)
Document Control Number: EPA-HQ-OAR-2008-0508-0717.1
Comment Excerpt Number: 7
Comment: Proposed §93.30 and §98.40 exempt portable equipment and emergency generators
from GHG emission reporting requirements. Due to the minimal GHG emissions expected from
such equipment, Tampa Electric supports the equipment's exemption from the proposed
reporting requirement. Because GHG emissions from such equipment are generally minimal,
and because exempt emergency generators would already be required to meet the specifications
listed in the definition of "emergency generators" under proposed §98.6, there is no reason to add
a further restriction that the equipment be listed in a permit. In summary, for those units that
meet the definition of "emergency generator" under §98.6 should be excluded from the proposed
reporting requirements of applicable source categories due to their minimal GHG emission
contribution.
Response: EPA has maintained the exclusion of emergency generators, and has excluded other
emergency equipment from reporting. EPA has also revised the rule language to remove the
prerequisite for a state or local permit. Please refer to the full definitions of emergency generator
and emergency equipment in §98.6. Portable equipment, as defined in §98.6, is also exempt
from reporting.
Commenter Name: Vince Brisini
Commenter Affiliation: RRI Energy Inc. (RRI)
Document Control Number: EPA-HQ-OAR-2008-0508-0618.1
Comment Excerpt Number: 6
Comment: RRI supports the exemption of portable equipment and emergency generators from
GHG emission reporting requirements, but requests that U.S. EPA expand the exemption to
include "limited-use generators." These generators, or "peaking units," are only used during
times of peak electricity demand. Due to their limited use, minimal GHG emissions should be
expected from such equipment. U.S. EPA has previously established precedence for exempting
limited-use generators from a variety of monitoring and reporting requirements or emission
limits (e.g., 40 CFR 60 Subpart Db NSPS for Industrial-Commercial-Institutional Steam
Generating Units and 40 CFR 63 Subpart ZZZZ NESHAP for Stationary RICE). RRI proposes
that limited-use generators be defined as those with a maximum annual heat input capacity factor
of 5 percent for the purposes of GHG reporting requirements.
15
-------
Response: See the response to comment EPA-HQ-OAR-2008-0508-0516.1 excerpt 10 for
additional explanation of the treatment of load-shedding and peak-shaving units.
EPA has maintained the exclusion of emergency generators, and has excluded other emergency
equipment from reporting. EPA has also revised the rule language to exclude the prerequisite for
a state or local permit. Please refer to the full definition of emergency generator in §98.6:
peaking units are not considered emergency generators.
Commenter Name: John H. Skinner
Commenter Affiliation: Solid Waste Association of North America (SWANA)
Document Control Number: EPA-HQ-OAR-2008-0508-0659.1
Comment Excerpt Number: 5
Comment: We support the exemption for portable equipment and generating units designated
as emergency generators in a permit issued by a state or local air pollution control agency.
Response: EPA appreciates the commenter's support. EPA has maintained the exclusion of
emergency generators, and has excluded other emergency equipment from reporting. EPA has
also revised the rule language to remove the prerequisite for a state or local permit. Please refer
to the full definitions of emergency generator and emergency equipment in §98.6. Portable
equipment, as defined in §98.6, is also exempt from reporting.
Commenter Name: Andrew C. Lawrence
Commenter Affiliation: Department of Energy (DOE)
Document Control Number: EPA-HQ-OAR-2008-0508-0612.1
Comment Excerpt Number: 5
Comment: In section 98.30(b) of Subpart C - General Stationary Fuel Combustion Sources, a
reporting exemption is proposed for portable equipment or generating units designated as
emergency generators, if such equipment is included in a permit issued by a state or local air
agency. DOE recommends that this requirement be modified to include equipment exempted
from state permitting requirements. In many state and local air permit programs, emergency
generators are specifically exempt from new source and Title V permit requirements through
state rules, most of which are part of the State Implementation Plan (SIP). Although new
generator engines may be regulated under a new source performance standard (NSPS), many
sites continue to employ electrical generating equipment exempt from or not regulated by the
NSPS. If necessary, EPA could mirror state rules and develop an exemption level wherein
engines using certain fuels, (e.g., natural gas, fuel oil), are exempt if below a certain horsepower
and restricted to a certain number of hours of use.
Response: See the Preamble for the response on de minimis reporting for small emission points.
EPA has maintained the exclusion of emergency generators, and has excluded other emergency
equipment from reporting. EPA has also revised the rule language to remove the prerequisite for
a state or local permit. Please refer to the full definitions of emergency generator and emergency
equipment in §98.6.
16
-------
Commenter Name: Scott Davis
Commenter Affiliation: Arizona Public Service (APS)
Document Control Number: EPA-HQ-OAR-2008-0508-0639.1
Comment Excerpt Number: 5
Comment: EPA states in the preamble that they are "... proposing to not require reporting of
emissions from portable equipment or generating units designated as emergency generators in a
permit issued by the state or local air pollution control agency." EPA is also requesting
comments on whether or not a permit should be required for emergency generators. APS fully
supports the exclusion of portable equipment and emergency generators from the applicability
determinations and subsequent reporting requirements of this rule. It is APS's position that not
only should emergency generators be excluded, but that they should be excluded regardless of
whether it is identified in a state or local air pollution control permit. In many situations
emergency generators are broadly addressed in air quality control permits, but are not
specifically identified. They are identified only as insignificant activities or even trivial activities
in the Technical Support Documents.
Response: EPA has maintained the exclusion of emergency generators, and has excluded other
emergency equipment from reporting. EPA has also revised the rule language to remove the
prerequisite for a state or local permit. Please refer to the full definitions of emergency generator
and emergency equipment in §98.6.
Commenter Name: William Yanek
Commenter Affiliation: Glass Association of North America (GANA)
Document Control Number: EPA-HQ-OAR-2008-0508-0586.1
Comment Excerpt Number: 10
Comment: EPA proposes exempting from a facility's annual report all emissions from
emergency backup generators but only if those generators are designated as emergency
generators in the facility's state or local permit. See proposed 40 CFR §98.30. GANA urges
EPA to eliminate this condition and instead exempt measuring and reporting the emissions from
any and all emergency generators or backup engines meeting the EPA definition of "emergency
generator" specified in proposed 40 CFR §98.6. The proposed definition is clear and may be
consistently applied to all sites regardless of whether the backup generator or engine has been
designated as such in a facility permit. Given that definition, their emissions, if any, would be de
minimis under any reasonable measure and thus would not affect the overall quality of the
emissions data for the facility.
Response: EPA has maintained the exclusion of emergency generators, and has excluded other
emergency equipment from reporting. EPA has also revised the rule language to remove the
prerequisite for a state or local permit. Please refer to the full definitions of emergency generator
and emergency equipment in §98.6.
17
-------
Commenter Name: D. Lawrence Zink
Commenter Affiliation: Montana Sulphur & Chemical Company Inc. (MSCC)
Document Control Number: EPA-HQ-OAR-2008-0508-0505.1
Comment Excerpt Number: 3
Comment: We believe that there is no need for portable or emergency equipment, either
permitted or not permitted, to be exempt or excluded from the proposed rule for two reasons. 1)
It is difficult to carve out the emissions related to these specific units; and 2) even if such
equipment were to be exempted on the downstream side, the fuel suppliers would include the
supply used for such equipment. The proposed rule does not provide much discussion on this
topic. What is the rationale for any such exemption?
Response: The Agency disagrees with the commenter's assertion that there is no need for the
portable or emergency equipment to be excluded from reporting, and has exempted portable or
emergency equipment, as defined in §98.6, from reporting in the final rule (see §98.30(b)). The
Agency has concluded that reporting emissions from emergency equipment would be unduly
burdensome in relation to the amount of emissions that would be captured. An explanation is
provided in the Preamble in Section III. C. 3., "General Stationary Fuel Combustion Sources."
However, EPA wishes to clarify that a source may include emissions from these devices if
separating emissions from them would prove onerous. As discussed in Section II. D. 3. of the
Preamble, "Summary of Comments and Responses on Source Categories to Report," the
requirements for upstream and downstream reporting may lead to double reporting in some
cases. It has never been EPA's intention to make upstream and downstream coverage match
exactly, and in fact one of the advantages of upstream coverage is that it is able to provide
information on fuel used in small devices or mobile sources where downstream reporting is
burdensome.
Commenter Name: Karen S. Price
Commenter Affiliation: West Virginia Manufacturers Association (WVMA)
Document Control Number: EPA-HQ-OAR-2008-0508-0475.1
Comment Excerpt Number: 5
Comment: Under the proposed rule, portable equipment or generating units are excluded from
the fuel combustion source category designated, as long as they are used for emergency purposes
only. As proposed, the units must be designated as "emergency generators" in a permit issued by
a state or local air pollution control agency. In addition, the proposed rule does not exempt
engines that serve as back-up power sources under conditions of load shedding, peak shaving,
power interruption pursuant to an interruptible power source agreement, or scheduled
maintenance. While the WVMA is supportive of an exemption for emergency generators, we
believe that the definition of emergency generator should be broadened and should not require
that such engine be permitted as an emergency generator. In addition, we think that emergency
engines used for the reasons cited above should also be exempted from the reporting rule.
Response: EPA has maintained the exclusion of emergency generators, and has excluded other
emergency equipment from reporting. EPA has also revised the rule language to remove the
prerequisite for a state or local permit. In §98.6, however, EPA has specifically excluded from
the definition of emergency generators engines that serve as back-up power sources under
18
-------
conditions of load shedding, peak shaving, power interruptions pursuant to an interruptible
power source agreement, or scheduled maintenance, and as such, from the exemption from
reporting.
Commenter Name: See Table 4
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0455.1
Comment Excerpt Number: 5
Comment: Proposed §§98.30 and 98.40 would exempt portable equipment and emergency
generators from GHG emission reporting requirements, but not other types of stationary
emergency equipment. The Class of'85 believes that this exemption should be expanded to
cover other types of emergency equipment. Specifically, the Class of'85 believes that
emergency diesel-fired firewater pumps and emergency boiler feed water pumps should be
exempted from GHG reporting requirements due to their infrequent use and minor emissions.
These pumps are almost never used, except for emergencies or periodic function tests. However,
they do not fit under the proposed emergency generator and portable equipment exemption
because they are typically permanently mounted in their own small buildings. Thus, the Class of
" 85 urges EPA to expand the proposed emergency generator and portable equipment exemption
to include all emergency equipment that meets the use specifications listed in the definition of
"emergency generators" under proposed §98.6.
Response: EPA has maintained the exclusion of emergency generators, and has excluded other
emergency equipment from reporting. Please refer to the full definitions of emergency
equipment in §98.6 in which emergency equipment means any auxiliary fossil fuel-powered
equipment, such as a fire pump, that is used only in emergency situations. EPA is also excluding
portable equipment from reporting. Please refer to the full definition of portable equipment in
§98.6.
Commenter Name: Gary Moore
Commenter Affiliation: Pensacola Plant of Ascend Performance Materials LLC
Document Control Number: EPA-HQ-OAR-2008-0508-0366.1
Comment Excerpt Number: 4
Comment: Many manufacturing facilities operate "burnout furnaces" whose purpose is to clean
parts of plastics, oil or other residual material prior to the part being used in a subsequent
manufacturing process. These burnout furnaces appear to meet the definition of incinerator in
§98.30. Burnout furnaces typically have relatively low BTU heat inputs, for example less than 3
MMBtu/hr and often under 500,000 Btu/hr and do not operate continuously. Burnout furnaces
would typically be classified as a Parts Reclamation Unit under CIWSI rules (40 CFR 60 Subpart
DDDD or 40 CFR 62 Subpart III). Are the materials burned off of the parts considered fuel
under the proposed rule? It would be burdensome and expensive to weigh and track the parts
before and after cleaning. In addition, the parts may be required to be placed in service in a hot
state. This would involve reheating parts after final cleaning and weighing. The amount of
material is generally small and would not be a significant contributor of Greenhouse Gas
emissions. We propose exempting Parts Reclamation Units as currently defined in the CIWSI
rules.
19
-------
Response: EPA believes that the content of the final rule addresses this comment through the
revision of of the applicability of the tiers in the final rule. It is EPA's intent that Tier 1 and 2
sources, which are allowed for combustion devices rated at 250 mmBtu/hr and less, will only be
required to report emissions from the combustion of fuels for which emission factors are
provided. Units larger than 250 mmBtu/hour heat input GHG that combust miscellaneous, non-
traditional fuels such as refinery gas, process gas, vent gases, waste liquids, and others must
report only if CEMS are used or if these fuels contribute ten percent or more of the annual unit
heat input to the unit. With this exclusion, we have concluded that devices such as thermal
oxidizers, pollution control devices, fume incinerators, burnout furnaces, and other such
equipment would report only GHG emissions from the firing of supplemental fossil fuels.
Commenter Name: Laurie Zelnio
Commenter Affiliation: Deere & Company
Document Control Number: EPA-HQ-OAR-2008-0508-0355.1
Comment Excerpt Number: 4
Comment: As a manufacturer of nonroad engines and mobile equipment, Deere facilities may
also combust fuels for the purpose of nonroad engine and product research, development, and
testing. Sources of these emissions include engine test cells/test stands, equipment on
dynamometers, and our mobile equipment at the end of the assembly line. We submitted a
question to the EPA to clarify whether fuel consumed for testing nonroad engines and nonroad
equipment is included in the reporting. We received a response to our inquiry indicating that
research and development of engines are not exempt from reporting. This conflicts with
information the Outdoor Power Equipment Institute (OPEI), of which we are a member, received
from Katherine Sibold, Program Integration Branch, USEPA - Office of Air and Radiation, that
emissions from engines will be captured under the reporting requirements for engine
manufacturers; therefore reporting of emissions from engines at the facility would not be
required. Further clarification is needed — are we required to report both for affected facilities
and as an engine manufacturer? Furthermore, in the State of Iowa, mobile equipment that vents
through a stationary stack is not considered "mobile" which would normally be exempt from
construction permitting under IAC 567 22.1(2)c. and is normally considered insignificant for
Title V under IAC 567 22.103(l)a. It is not clear in the proposed rule if this same interpretation
applies to the definition of a stationary fuel combustion source at §98.30. Clear segregation of
mobile source emission reporting from stationary source emission reporting is needed. To
eliminate double-reporting and to clarify what this Federal rule includes as a stationary source,
Deere recommends "research, development, and testing of mobile source engines and mobile
source equipment" be added to the exclusion in §98.3(b).
Response: See the individual source category section(s) of the Preamble and the source
category comment response document(s) for the response on the definition of the source
category. EPA is also excluding portable equipment from reporting. Please refer to the full
definitions of portable equipment in §98.6. Stationary combustion devices that do not meet the
definition of portable equipment would be expected to be reported.
EPA has established a clear segregation of mobile source emission rate reporting from stationary
source emission reporting. The determination of coverage under §98 is separate from the
determination of coverage under §86 for emissions rates from mobile sources. See the Preamble
20
-------
section and separate comment response document volume on Mobile Sources for an explanation
of coverage under that Part.
Please refer to the exclusion of research and development activities in §98.2, and the definition
of research and development in §98.6.
Emissions from engine testing that are not R&D activities need to be reported under the
Stationary Combustion source category if the source is fixed (e.g.,to a foundation). However,
the final rule includes additional flexibility on the use of the tier methods. Depending on the size
of the engines being tested, Tier 1 and/or the alternative reporting requirements which allow the
aggregation of small units may be applicable, both of which may reduce the burden of reporting.
Commenter Name: Kathleen Tobin
Commenter Affiliation: Verizon Communications, Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-0575.1
Comment Excerpt Number: 4
Comment: Currently, States track emergency engine use in a variety of ways from simple
notifications through full permitting, depending on local air quality concerns as well as the size
and usage of the generators. Exempting only portable equipment or emergency engines with a
permit could cause a large number of equipment or engines to be covered under this proposal by
the mere fact that permits are not necessarily required. Emergency engines are defined in the
regulation; therefore, it would seem unnecessary to include units that operate in the same manner
simply because they are not required to have a state or local permit. One unanticipated effect of
exempting only emergency engines with a permit would be to increase the number of permit
applications in states where emergency engines are not required to be fully permitted in order to
qualify for this exemption. This may increase requests for permits that would result in an
administrative burden without any substantive environmental gain. Therefore, the exemption
should cover all emergency engines, including non-permitted units under its emergency
generator exemption.
Response: EPA has maintained the exclusion of emergency generators, and has excluded other
emergency equipment from reporting. EPA has also revised the rule language to exclude the
prerequisite for a state or local permit. Please refer to the full definitions of emergency generator
and emergency equipment in §98.6.
Commenter Name: Angela Burckhalter
Commenter Affiliation: Oklahoma Independent Petroleum Association (OIPA)
Document Control Number: EPA-HQ-OAR-2008-0508-0386.1
Comment Excerpt Number: 21
Comment: Under Tier 3, EPA requires direct measurement of the amount of fuel combusted.
Most combustion sources at oil and gas production facilities do not have fuel flow meters
installed. Did EPA account for the cost of adding fuel flow meters into its cost impact analysis?
Response: EPA has considerably revised §98.33(b), describing which tier a reporter is to use.
Tier 2, which allows facilities to determine fuel use from company records, is now applicable to
21
-------
units of any size combusting pipeline natural gas or distillate fuel oil. EPA has defined the term
"company records" in §98.6 of the final rule, and believes that the revised definition provides
appropriate guidance as to what records a facility may use to determine fuel consumption. While
fuel flow meters may be used where company records are required, they are certainly not
mandatory. EPA has also clarified in the final rule that fuel billing meters may be used for the
purpose of directly measuring combustion of liquid and gaseous fuels in Tier 3. Meanwhile,
EPA has retained the provisions in Tier 3 allowing facilities to determine fuel oil consumption
using tank drop measurements and solid fuel combustion using company records for the
purposes of Tier 3 calculations. EPA believes that these provisions provide an appropriate
balance between reducing the reporting burden and gathering accurate data. Taking this into
consideration, EPA has accounted for the cost for the installation of flow meters, where
applicable.
Commenter Name: See Table 4
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0455.1
Comment Excerpt Number: 4
Comment: Proposed §§98.30 and 98.40 would exempt portable equipment and emergency
generators from GHG emission reporting requirements. Due to the minimal GHG emissions
expected from such equipment, the Class of'85 supports the equipment's exemption from the
proposed reporting requirements. However, the Group believes that EPA has crafted the
proposed exemption too narrowly. Under proposed §§98.30 and 98.40, only portable equipment
and emergency generators that are designated as emergency generators in a permit issued by a
state or local air pollution control agency would be exempt from the reporting requirements of
the regulation. The Class of'85 believes that the permit designation restriction is unnecessary.
Because GHG emissions from such equipment are generally minimal, and because exempt
emergency generators would already be required to meet the specifications listed in the
definition of "emergency generators" under proposed §98.6, there is no reason to add a further
restriction that the equipment be listed in a permit. Some states exempt emergency generators
from construction or operating permits if certain operating criteria are met. For example, in
Wisconsin an emergency electric generator means "an electric generator whose purpose is to
provide electricity to a facility if normal electrical service is interrupted and which is operated no
more than 200 hours per year." Wis. ADMIN. CODE NR § 400.02(56). An emergency
electrical generator fitting this definition is exempt from construction or operating permit
requirements provided it is "powered by internal combustion engines which are fueled by
gaseous fuels, gasoline or distillate fuel oil with an electric output of less than 3,000 kilowatts."
Wis. ADMIN. CODE NR §§406.04(l)(w) and 407.03(l)(u)). As a result of such state
exemptions, emergency generators may be designated as emergency generators by the state, but
not included in the state or local air pollution control agency permit. For these reasons, the Class
of'85 believes that proposed §§98.30 and 98.40 should be revised to simply state that portable
equipment and emergency generators that meet the definition of "emergency generators" under
§98.6 are excluded from the proposed reporting requirements of applicable source categories. At
the least, EPA should expand the exemption to apply not only to emergency generators that are
exempted by permit but also to emergency generators that are exempted from permitting.
Response: EPA has maintained the exclusion of emergency generators, and has excluded other
emergency equipment from reporting. EPA has also revised the rule language to remove the
22
-------
prerequisite for a state or local permit. Please refer to the full definitions of emergency generator
and emergency equipment in §98.6.
Commenter Name: Paul Dubenetzky
Commenter Affiliation: KERAMIDA Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-0419.1
Comment Excerpt Number: 7
Comment: Maintain and clarify the exemption for portable equipment (varies, most refer to 40
CFR 98.30(b), portable equipment defined at 40 CFR 98.6 74 FR 16625).
Response: EPA has maintained the exclusion of portable equipment, as defined in §98.6, from
reporting under both Subpart C and Subpart D.
Commenter Name: Randal G. Oswald
Commenter Affiliation: Integrys Energy Group, Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-0569.1
Comment Excerpt Number: 3
Comment: We support EPA's proposal to not require reporting of emissions from portable
equipment or generating units designated as emergency generators. However, the designation of
an emergency generator should be expanded to include those designated as emergency
generation by regulation. EPA's proposal restricts no-reporting to emergency generators that are
so designated by permit. However some states may exempt certain emergency generators from
construction or operating permit requirements. The exemption applies when certain operating
criteria are met. For example, in the Wisconsin Administrative Code (WAC), an emergency
electric generator "means an electric generator whose purpose is to provide electricity to a
facility if normal electrical service is interrupted and which is operated no more than 200 hours
per year." (WAC NR 400.02(56)). An emergency electrical generator is exempt from
construction or operation permit requirements provided it is "powered by internal combustion
engines which are fueled by gaseous fuels, gasoline or distillate fuel oil with an electric output of
less than 3,000 kilowatts." (WAC NR 406.04(l)(w) and WAC NR 407.03(l)(u)). The no-
reporting feature of the proposed rule should be expanded to include emergency units that are
also designated by regulation as emergency generators.
Response: EPA has maintained the exclusion of emergency generators, and has excluded other
emergency equipment from reporting. EPA has also revised the rule language to remove the
prerequisite for a state or local permit. Please refer to the full definitions of emergency generator
and emergency equipment in §98.6.
23
-------
Commenter Name: Angela D. Marconi
Commenter Affiliation: Delaware Solid Waste Authority
Document Control Number: EPA-HQ-OAR-2008-0508-0472.1
Comment Excerpt Number: 2
Comment: Section I of the preamble discusses a variety of greenhouse gases and the difference
between gases that are biogenic and anthropogenic in nature. Section HH-Landfills notes that
the C02 portion of landfill gas (LFG) as well as any C02 created from destruction of CH4, is not
anthropogenic. Section 98.342 of the rule specifically excludes CO2 from flare emissions from
required reporting, and it does not comment on fugitive C02 emissions. However, there is some
confusion as to whether section 98.33(b)(5)(ii) excludes engines that utilize landfill gas from
reporting C02 emissions. Please clarify that engines that utilize LFG are excluded from C02
emissions. DSWA agrees with this characterization and recommends that emissions that are not
anthropogenic should be excluded from the inventory. Including biogenic emissions in the
inventory will cause confusion because these emissions do not contribute to the greenhouse
effect. Additionally, the tracking of these emissions will require additional effort and expense
without gaining useful information.
Response: EPA disagrees with the suggestion that biogenic C02 should not be reported, and in
fact requires facilities to track biogenic emissions separately. Including reporting of biogenic
C02 at facilities that are already reporting for stationary combustion provides EPA with
information on the use of biofuels as they relate to reductions of fossil C02 emissions over time.
This reporting requirement also provides additional data for verification. EPA believes that it is
clear in §98.2, however, that C02 emissions from biogenic fuels do not count toward the 25,000
metric ton threshold for reporting for stationary combustion units, although CH4 and N20
emissions from biogenic fuels must be considered when calculating the threshold and
determining applicability.
EPA has added a provision to §98.33(e) specifying that Tier 1 may be used to calculate
emissions from the combustion of any biogenic fuel (including landfill gas), as long as CEMS
are not used to measure C02 emissions. EPA has added to Table C-l a default biogas (landfill
gas) emission factor. EPA has added language to §98.33(b)(4) to clarify that all of the criteria in
§98.33(b)(4)(ii) or (iii) must be present to require the use of Tier 4. EPA has also specifically
excluded flares from the stationary combustion source category in §98.30, except where
reporting of flare emissions is required by another subpart of Part 98.
Commenter Name: Gary Moore
Commenter Affiliation: Pensacola Plant of Ascend Performance Materials LLC
Document Control Number: EPA-HQ-OAR-2008-0508-0366.1
Comment Excerpt Number: 1
Comment: It is unclear from the definition of Stationary Fuel Combustion Sources in §98.30
whether flares, thermal oxidizers or other thermal control devices are classified as a Stationary
Fuel Combustion Source under the rule. These type of units exist to control off gas emissions
under various Federal and state rules such as the Hazardous Organic NESHAP (HON) in 40 CFR
63 Subparts F, G and H; Miscellaneous Organic NESHAP (MON) in 40 CFR 63 Subpart FFFF
or Prevention of Significant Deterioration (PSD) permitting process. The offgas streams
24
-------
typically do not independently support combustion. The purpose of operation for these control
devices does not fit the "Generally for the purposes of statement in §98.30. Their main control
devices may have waste heat recovery installed but their primary reason for operation is not
steam generation. Greenhouse Gas emission calculation methods for flares appear in other
sections of the proposed rule but not in the proposed Subpart C. Thermal control devices should
be excluded from Stationary Fuel Combustion Sources.
Response: See the General Stationary Combustion source category Preamble section, as well as
the separate comment response document, for the response on the definition of the source
category.
EPA acknowledges the concerns of the commenter and has revised §98.33 to deal with certain
unconventional combustion processes and types of fuel. It is EPA's intent that sources allowed
to use the Tier 1 and 2 methods, which include smaller combustion devices and should be
inclusive of control devices such as thermal oxidizers, will only be required to report emissions
from the combustion of fuels for which emission factors are provided. In the Preamble, EPA has
explained that "EPA believes that the reporting requirements for Tier 1 and Tier 2 would only
require the reporting of GHG emissions from supplementary traditional fossil fuels from devices
such as thermal oxidizers, pollution control devices, fume incinerators, burnout furnaces, and
other such equipment." EPA believes that these provisions satisfy the intent of Part 98, to collect
accurate and consistent GHG emissions data that can be used to inform future decisions.
Commenter Name: Jerry Call
Commenter Affiliation: American Foundry Society (AFS)
Document Control Number: EPA-HQ-OAR-2008-0508-0356.2
Comment Excerpt Number: 4
Comment: The term, "stationary fuel combustion source," should also not include cupolas. A
cupola is a vertical, cylindrical furnace where the principal fuel, coke, is used in conjunction with
metallics and fluxes to produce molten metal. The metallics are melted in the cupola by the
release of heat from the combustion of carbon from the coke. The examples of stationary fuel
combustion sources that are provided in section 98.2(a)(3) of the proposed regulation include:
boilers, combustion turbines, engines, incinerators, and process heaters. While EPA does not
provide a definition of "process heater" in the proposed rule, a review of the vacated National
Emission Standards for Hazardous Air Pollutants for Industrial, Commercial, and Institutional
Boilers and Process Heaters (69 Fed. Reg. 55269) provided the following definition: "process
heater means an enclosed device using controlled flame, that is not a boiler, and the unit's
primary purpose is to transfer heat indirectly to a process material (liquid, gas, or solid) or to a
heat transfer material for use in a process unit, instead of generating steam." Process heaters are
devices in which the combustion gases do not directly come into contact with process materials.
Process heaters do not include units used for comfort heat or space heat, food preparation for on-
site consumption, or autoclaves. The cupola transfers heat directly to the material it is
processing and does not, therefore, meet this definition nor is a cupola similar to any of the other
examples of stationary fuel combustion sources provided in the proposed regulation.
Response: See the individual source category sections of the Preamble and the source category
comment response documents for the responses on source category-specific reporting
requirements.
25
-------
It is EPA's intent that cupola furnaces report GHG emissions according to the requirements for
combustion units discussed in detail in Subpart C of the final rule, as the majority of the GHG
emissions originate from fuel combustion. Applicability of Subpart C reporting requirements is
not limited to the sources identified in the list of examples noted in the comment, as clarified
with the words in the rule text immediately preceding it, "including, but not limited to." The
Preamble section for Subpart Q, Iron and Steel Production, provides a list that identifies the
types of units with similar properties to cupola furnaces for which the Subpart C reporting
requirements apply for estimating C02, CH4, andN20 emissions.
Commenter Name: Jerry Call
Commenter Affiliation: American Foundry Society (AFS)
Document Control Number: EPA-HQ-OAR-2008-0508-0356.2
Comment Excerpt Number: 3
Comment: AFS agrees that the term, "fuel combustions sources," should not include portable
equipment or generating units designated as emergency generators. However, because of state
construction permit exemptions, the requirement that these units be designated as such with a
permit issued by a state or local air pollution control agency is unnecessary and unduly
burdensome and should be deleted from the proposed regulation.
Response: EPA has maintained the exclusion of emergency generators, and has excluded other
emergency equipment from reporting. EPA has also revised the rule language to remove the
prerequisite for a state or local permit. Please refer to the full definitions of emergency generator
and emergency equipment in §98.6.
Commenter Name: Cindy Parsons
Commenter Affiliation: Los Angeles Department of Water and Power
Document Control Number: EPA-HQ-OAR-2008-0508-0228t
Comment Excerpt Number: 3
Comment: Notice that the proposed reporting rule exempts portable equipment and emergency
generators but overlooks other types of emergency backup engines with insignificant emissions,
such as emergency fire pumps and emergency backup water pumps. EPA should consider
expanding the exemption to include all types of emergency backup engines so that all emergency
engines are treated the same.
Response: EPA has maintained the exclusion of emergency generators, and has excluded other
emergency equipment from reporting. EPA has also revised the rule language to remove the
prerequisite for a state or local permit. Please refer to the full definitions of emergency generator
and emergency equipment in §98.6.
26
-------
Commenter Name: Robert J. Martineau, Jr
Commenter Affiliation: Counsel, Waller Lansden Dortch & Davis, LLP
Document Control Number: EPA-HQ-OAR-2008-0508-0414.1
Comment Excerpt Number: 4
Comment: EPA specifically has solicited comment on whether the exclusion for portable or
emergency generators under various provisions of the rule should be contingent on whether they
are so designated in a permit. See e.g. 74 Fed.Reg. at 16,462. (fns. 32 & 33). Nissan urges EPA
not to require that the portable emergency generator unit be designated as such in a permit. State
and local permitting programs have a myriad of detailed permitting requirements. There is
certainly no uniform approach with respect to whether portable generating units are typically
included in a permit. The decision to exclude portable generating units used as emergency
generators in those permitting programs should not be the basis for determining whether or not to
include such units. The basis should be the intended nature of the unit themselves — portable
equipment or emergency generators and the de minimis nature of their emissions.
Response: EPA has revised the rule language to exclude the prerequisite for a state or local
permit. Please refer to the full definitions of emergency generator, portable equipment, and
emergency equipment in §98.6.
Commenter Name: Michael W. Stroben
Commenter Affiliation: Duke Energy Corporation
Document Control Number: EPA-HQ-OAR-2008-0508-0407.1
Comment Excerpt Number: 9
Comment: Duke Energy requests that EPA clarify that the definition of "portable" is not
intended to include small non-road equipment used at a site for various facility support services.
For example, it seems that exclusion for equipment that remains on site for more than 12
consecutive months could require that facilities track and report the emissions from lawnmowers,
pressure washers, and similar small engines that are used for infrequent non-process activities.
Response: See the Preamble for the response on de minimis reporting for small emission points.
We are retaining the existing definition of portable equipment in §98.6, which includes language
that "Indications of portability include but are not limited to wheels, skids, carrying handles,
dolly, trailer, or platform." The definition of portable excludes "equipment or a replacement that
resides at the same location for more than 12 consecutive months. The types of equipment
mentioned by the commenter would typically not be excluded from the definition because while
they reside at the same facility they would very likely not reside at the same exact location for
more than 12 consecutive months because of their intended use.
27
-------
Commenter Name: Chris Hornback
Commenter Affiliation: National Association of Clean Water Agencies (NACWA)
Document Control Number: EPA-HQ-OAR-2008-0508-0566.1
Comment Excerpt Number: 13
Comment: NACWA supports the proposed exclusion of emissions from emergency power
generators. Many emergency units may be permitted by rule in some states or not specifically
permitted by the state. NACWA believes that all emergency power generators should be
excluded, regardless of whether or not they are specifically permitted.
Response: EPA has maintained the exclusion of emergency generators, and has excluded other
emergency equipment from reporting. EPA has also revised the rule language to remove the
prerequisite for a state or local permit. Please refer to the full definitions of emergency generator
and emergency equipment in §98.6.
Commenter Name: Michael Bradley
Commenter Affiliation: The Clean Energy Group (CEG)
Document Control Number: EPA-HQ-OAR-2008-0508-0479.1
Comment Excerpt Number: 16
Comment: The Clean Energy Group requests clarification from EPA that generators of
geothermal electricity do not have to report under the proposed rule. The rule does not directly
address geothermal electricity production, which is a renewable electricity resource. If EPA
determines that geothermal electricity production should be included in the rule as a source
category, the Clean Energy Group requests clarification on the method by which greenhouse gas
emissions would be calculated in order to determine applicability. Greenhouse gas emissions
from geothermal vary widely from well to well and unit to unit, and a single emission factor
would not be accurate. For example, standard California ARB factors substantially overestimate
greenhouse gas emissions from geothermal processes, often by approximately fourfold. The
Clean Energy Group agrees with the exemption that EPA is proposing for portable equipment or
generating units designated as emergency generators in a permit issued by a state or local air
pollution control agency. However, there are variations from state to state regarding the
regulation of these sources including whether a permit is required or what constitutes an
emergency generator. Additionally, designation as an emergency generator has consequences
for regulation under other federal and state air pollution control programs. EPA should eliminate
the permit requirement from this definition, and instead define emergency generator separately
for the purpose of this exemption and make it clear that emergency generators are exempt from
every source category and not only electricity generation.
Response: See the Preamble and separate comment response document volume for the response
on selection of source categories to report. Facilities must report GHG emissions for sources for
which methodologies are provided, and EPA has not provided a methodology for CO2 emissions
from non-combustion geothermal energy generation processes.
EPA acknowledges the concerns of the commenter. Section 98.40 of the final rule clarifies the
definition of the electricity generation source category. Facilities are required to report GHG
28
-------
emissions under Subpart D only if the facility contains one or more electricity generating units
that: 1) are subject to the requirements of the Acid Rain Program; or 2) are required to monitor
and report to EPA C02 emissions year-round according to Part 75.
EPA has maintained the exclusion of emergency generators, and has excluded other emergency
equipment from reporting. EPA has also revised the rule language to remove the prerequisite for
a state or local permit. Please refer to the full definitions of emergency generator and emergency
equipment in §98.6.
A geothermal electricity production facility that has stationary combustion devices emitting
greater than 25,000 tons of C02e would be required to report under Subpart C.
Commenter Name: Kathleen M. Sgamma
Commenter Affiliation: Independent Petroleum Association of Mountain States (IPAMS)
Document Control Number: EPA-HQ-OAR-2008-0508-0521.1
Comment Excerpt Number: 15
Comment: Not all states require permits for emergency generators. In addition to excluding
permitted generators, the exclusion should extend to non-permitted emergency equipment (such
as non-permitted emergency generators or fixed firewater pumps).
Response: EPA has maintained the exclusion of emergency generators, and has excluded other
emergency equipment from reporting. EPA has also revised the rule language to remove the
prerequisite for a state or local permit. Please refer to the full definitions of emergency generator
and emergency equipment in §98.6.
Commenter Name: Robert J. Martineau, Jr
Commenter Affiliation: Counsel, Waller Lansden Dortch & Davis, LLP
Document Control Number: EPA-HQ-OAR-2008-0508-0414.1
Comment Excerpt Number: 15
Comment: Nissan requests clarification as to whether GHG emissions that result from the
testing and inspection process of light-duty vehicle engines, during the engine manufacturing
process, are properly excluded from a manufacturing facility's reporting requirements under the
fuel combustion source category as they will accounted for in the Mobile Sources category.
During the engine manufacturing process, individual engines are placed on a carousel and tested
in operation to ensure proper operation prior to being permanently installed in the vehicle. The
resulting engine emissions are channeled to a central collection location and emitted. Nissan
believes that these emissions are not included in the fuel combustion source category but
requests clarification of the issue. Nissan's position is supported by language in the preamble
discussing the fuel combustion category. The relevant preamble language states: "[stationary
fuel combustion sources are devices that combust solid, liquid, or gaseous fuel generally for the
purpose of producing electricity, generating steam, or providing useful heat or energy for
industrial, commercial, or institutional use, or reducing the volume of waste by removing
combustible matter." 74 Fed. Reg., at 16,480. The consequential GHG emissions resulting from
the combustion of fuel in the test engines on the carousel do not serve any of the purposes
described in the definition of a General Stationary Fuel Combustion source category. Thus,
29
-------
Nissan does not believe the fuel combustion from the test engines should be accounted for in
calculating GHG emissions from its manufacturing facility as a stationary source. As discussed
above, we request clarification as to whether GHG emissions resulting from individual engine
testing processes at the engine manufacturing facility are properly reported under the Mobile
Sources category, or whether such emissions must also be reported in a duplicative fashion under
other source categories, namely the General Stationary Fuel Combustions category.
Response: EPA notes that the mobile source reporting provisions are for reporting emissions
rates and not absolute emissions, and therefore emissions coming from the activities listed by the
commenter would in any case not be reported under the mobile source provision.
See the General Stationary Combustion source category section of the Preamble and the separate
comment response document volume for the response on the definition of portable equipment in
§98.6, which includes language that "Indications of portability include but are not limited to
wheels, skids, carrying handles, dolly, trailer, or platform." EPA's intent is that emissions from
stationary combustion devices that do not meet the definition of portable equipment would be
reported under Subpart C.
Please refer to the exclusion of research and development activities in §98.2 that has been added
to the final rule, and the definition of research and development in §98.6.
If the sources referenced by the commenter do not meet the definition of research and
development, the commenter should note that emissions from engine testing need to be reported
under the Stationary Combustion source category if the source is fixed (e.g., to a foundation).
However, the final rule includes additional flexibility on the use of the tier methods. Depending
on the size of the engines being tested, Tier 1 and/or the alternative reporting requirements which
allow the aggregation of small units may be applicable, both of which may reduce the burden of
reporting.
Commenter Name: Kathleen M. Sgamma
Commenter Affiliation: Independent Petroleum Association of Mountain States (IPAMS)
Document Control Number: EPA-HQ-OAR-2008-0508-0521.1
Comment Excerpt Number: 14
Comment: IPAMS remains opposed to requiring the reporting of greenhouse gas emissions
from temporary or portable equipment.
Response: EPA has maintained the exclusion of emergency generators, has excluded other
emergency equipment from reporting, and has exempted portable equipment from reporting.
Please refer to the full definitions of emergency generator, portable equipment, and emergency
equipment in §98.6.
30
-------
Commenter Name: Paul Dubenetzky
Commenter Affiliation: KERAMIDA Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-0419.1
Comment Excerpt Number: 13
Comment: Many industrial processes combust volatile organic compound (VOC) emissions in
air pollution control devices, boilers, and industrial heaters, with or without supplemental fuel.
The general applicability and reporting of the GHG emissions generated by the combustion of
process VOCs is generally not addressed by the proposed rule (requirements for refinery gas
combustion being duly noted). The unstated treatment of these emissions falls predominately
within 40 CFR 98, Subpart C — General Stationary Fuel Combustion Sources. KERAMIDA
suggests that the U.S. EPA add 40 CFR 98.30(c) to state, "This source category does not include
emissions of GHG resulting from the combustion of volatile organic compounds generated by
industrial processes that are directed to air pollution control devices, boilers, or process heaters
for the primary purpose of air pollution control. This source category does include the GHG
emissions resulting from fossil fuels that are combusted in air pollution control devices, boilers,
or process heaters."
Response: See the General Stationary Combustion source category Preamble section, as well as
the separate comment response document volume, for the response on the definition of the
source category.
EPA acknowledges the concerns of the commenter and has revised the Preamble and §98.33 to
deal with certain unconventional combustion processes and types of fuel. It is EPA's intent that
sources allowed to use the Tier 1 and 2 methods, which include smaller combustion devices and
should be inclusive of control devices such as thermal oxidizers, will only be required to report
emissions from the combustion of fuels for which emission factors are provided. In the
Preamble, EPA has explained that "EPA believes that the reporting requirements for Tier 1 and
Tier 2 would only require the reporting of GHG emissions from supplementary traditional fossil
fuels from devices such as thermal oxidizers, pollution control devices, fume incinerators,
burnout furnaces, and other such equipment."
Commenter Name: Steven M. Maruszewski
Commenter Affiliation: Pennsylvania State University (Penn State)
Document Control Number: EPA-HQ-OAR-2008-0508-0409.1
Comment Excerpt Number: 5
Comment: Penn State agrees with the exclusion of emergency generators. Including these
would cause an undue reporting burden.
Response: EPA appreciates the commenter's support, and has maintained the exclusion of
emergency generators from reporting. Please refer to the full definition of emergency generator
in §98.6.
31
-------
Commenter Name: Charlie Burd and Nicholas DeMarco
Commenter Affiliation: Independent Oil and Gas Association of West Virginia (IOGA-WV)
and West Virginia and Natural Gas Association (WVONGA)
Document Control Number: EPA-HQ-OAR-2008-0508-0516.1
Comment Excerpt Number: 10
Comment: Under the proposed rule, portable equipment or generating units are excluded from
the fuel combustion source category designated, as long as they are used for emergency purposes
only. As proposed, the units must be designated as "emergency generators" in a permit issued by
a state or local air pollution control agency. In addition, the proposed rule does not exempt
engines that serve as back-up power sources under conditions of load shedding, peak shaving,
power interruption pursuant to an interruptible power source agreement, or scheduled
maintenance. While the WV Associations are supportive of an exemption for emergency
generators, we believe that the definition of emergency generator should be broadened and
should not require that such engine be permitted as an emergency generator. In addition, we
think that emergency engines used for the reasons cited above should also be exempted from the
reporting rule.
Response: Because of the need for comprehensive, national greenhouse gas emissions data, the
final rule provides only limited exclusions from the reporting requirements. In the final rule,
EPA has maintained the exclusion of emergency generators, has removed for such generators the
100-hour limitation and the requirement of designation in a state or local permit, and has
excluded other emergency equipment from reporting. However, engines that serve as back-up
power sources under conditions of load shedding, peak shaving, power interruption pursuant to
an interruptible power source agreement, or scheduled maintenance are not emergency
generators and are not excluded. This is because these operations are not necessarily infrequent,
the equipment involved can be of widely varying sizes, and so the GHG emissions from these
operations cannot be assumed to be, and treated as, insignificant.
Commenter Name: W. Walter Tyler
Commenter Affiliation: INVISTA S.a r.l. (INVISTA)
Document Control Number: EPA-HQ-OAR-2008-0508-0481.2
Comment Excerpt Number: 6
Comment: Clarify the obligation to report emissions from stationary sources only once.
Section 98.30 of the proposed rule specifies source-specific reporting for Stationary Fuel
Combustion Sources including, but not limited to "boilers, combustion turbines, engines,
incinerators, and process heaters." Reporting of emissions from combustion sources is also
included in other specific subparts: 1. Subpart D - Electricity Generation. Per section 98.43(b)
for units not subject to the Acid Rain Program, "emissions shall be calculated using the methods
specified in §98.33 for stationary fuel combustion units." 2. Subpart E - Adipic Acid
Production. Per section 98.52(b), facilities must report GHG emissions from "each stationary
combustion unit that uses a carbon-based fuel, following the requirements of Subpart C of this
part." 3. Subpart V - Nitric Acid Production. Per section 98.222(b), facilities must report GHG
emissions from "each stationary combustion unit. You must follow the requirements of Subpart
C of this part." INVISTA's facilities are subject to both Subpart C and other subparts. The rule
should be clarified to ensure that combustion emissions from a given unit at a site are to be
32
-------
reported only once, that is, under only one of the applicable subparts. Otherwise, certain
facilities may be subject to double counting of emissions that would serve no stated purpose in
the rule, nor would it lead to any increased accuracy in emissions estimates and reporting.
Accordingly, INVISTA requests that the reporting requirement in Subpart C be clarified to
ensure reporting of emissions only once from sources covered by more than one subpart.
INVISTA suggests the following modification to section 98.32: You must report CO2, CH4, and
N20 mass emissions from each stationary fuel combustion unit. Combustion emissions reported
under other source specific categories (e.g. Electricity Generation, Adipic Acid Production,
Nitric Acid Production, etc.) should not be included in combustion emissions reported in the
General Stationary Fuel Combustion category.
Response: See the individual source category section(s) of the Preamble and the source
category comment response document(s) for the response on the definition of the source
category.
EPA intends that the stationary combustion source category include any device that meets the
definition included in §98.30 for which emissions are not accounted for in the report through a
separate subpart of the rule. Per the requirements in 40 CFR Part 98, Subpart A, facilities have
to report GHG emissions from all source categories located at their facility, including stationary
combustion and process emissions. EPA does not intend that emissions be double reported, and
has revised the various subparts of the final rule to clarify the intent of the stationary combustion
source category.
Commenter Name: Rechelle Hollowaty
Commenter Affiliation: Tyson Foods, Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-0379.1
Comment Excerpt Number: 9
Comment: For many years EPA's position as proven through their own White Paper on
Emergency Generators, has been that permits are not required for emergency generators or fire
pumps operating less than 500 hours per year. This has been the rational for keeping hour logs
on both emergency generators and fire pumps as means of verifying compliance that these units
are not being used for peak shaving. For EPA to consider requiring these type of units to
become permitted has no precedence and would require a tremendous amount of additional
workload for industry and state agencies. This type of permitting on top of an extremely
complicated record keeping and data collection process to comply with the GHG mandatory
reporting program creates undue hardship with minimal value. EPA has offered no scientific
reasoning behind their consideration for permitting emergency units and therefore we
recommend EPA not proceed with requiring permit for emergency units.
Response: EPA has revised the rule language to remove the prerequisite for a state or local
permit. Please refer to the full definitions of emergency generator and emergency equipment in
§98.6.
33
-------
Commenter Name: Paul Dubenetzky
Commenter Affiliation: KERAMIDA Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-0419.1
Comment Excerpt Number: 9
Comment: KERAMIDA supports the exclusion of portable equipment and emergency
generators. The definition of "portable" contained at 40 CFR 98.6, 74 FR 16625 is not clear
regarding mobile equipment such as forklifts. We believe that mobile equipment should be
exempt as not being stationary combustion or portable equipment or both. The rule should be
revised to make that clear. KERAMIDA also believes that emergency fire pumps should be
included in this exclusion (40 CFR 98.30(b)) because their emissions are small and intermittent
similar to emergency generators.
Response: In the final rule, EPA has maintained the exclusion of emergency generators, and has
excluded other emergency equipment from reporting. EPA has also revised the rule language to
remove the prerequisite for a state or local permit. Please refer to the full definitions of
emergency generators, portable equipment, and emergency equipment in §98.6. The phrase
"same location" in the definition is intended to mean that the equipment remain "stationary"
rather than move from one "location" to another "location" within a "facility." EPA did not find
a change in rule language necessary regarding the definition of "portable," and believes that the
source category definition, as presented in §98.30, is sufficient.
Commenter Name: Phillip McNeely
Commenter Affiliation: City of Phoenix, AZ
Document Control Number: EPA-HQ-OAR-2008-0508-0374.1
Comment Excerpt Number: 8
Comment: Support the exemption for portable equipment and emergency generators.
Response: EPA appreciates the commenter's support. EPA has maintained the exclusion of
emergency generators, and has excluded other emergency equipment from reporting. EPA has
also revised the rule language to remove the prerequisite for a state or local permit. Please refer
to the full definitions of emergency generator and emergency equipment in §98.6. Portable
equipment, as defined in §98.6, is also exempt from reporting.
Commenter Name: Michael W. Stroben
Commenter Affiliation: Duke Energy Corporation
Document Control Number: EPA-HQ-OAR-2008-0508-0407.1
Comment Excerpt Number: 8
Comment: EPA should not require that an emergency generator must be listed as such in a state
or local permit to be exempt from reporting. The proposed rule includes a very clear definition
of "emergency generator." Requiring a permit for emergency generators will serve no purpose.
Permitting requirements vary from state to state, particularly for sources that are not subject to
34
-------
Title V permitting. If EPA's intent is that emergency generators (as defined in the proposed rule)
are not subject to reporting, then forcing a permit condition simply adds an administrative
compliance burden.
Response: EPA has revised the rule language to remove the prerequisite for a state or local
permit.
Commenter Name: Lloyd Stone
Commenter Affiliation: Westlake Chemical Corporation
Document Control Number: EPA-HQ-OAR-2008-0508-0442.1
Comment Excerpt Number: 8
Comment: Does an incinerator with a waste heat boiler meet the definition of "Stationary fuel
combustion source"? That is, does a gaseous incinerator "reduce the volume of waste by
removing the combustible matter"?
Response: EPA believes that it is clear in §98.30 of the final that the stationary fuel combustion
source category includes both incinerators and boilers, and that an incinerator with a waste heat
boiler would meet the definition. However, the commenter should note that hazardous waste
incinerators will only be required to report emissions from the combustion of any supplemental
fuels for which emission factors are provided, unless CEMS are used. Furthermore, it is EPA's
intent that sources allowed to use the Tier 1 and 2 methods, which include smaller combustion
devices and should be inclusive of control devices such as thermal oxidizers, will only be
required to report emissions from the combustion of fuels for which emission factors are
provided. In the Preamble, EPA has explained that "EPA believes that the reporting
requirements for Tier 1 and Tier 2 would only require the reporting of GHG emissions from
supplementary traditional fossil fuels from devices such as thermal oxidizers, pollution control
devices, fume incinerators, burnout furnaces, and other such equipment."
Commenter Name: Kathleen M. Sgamma
Commenter Affiliation: Independent Petroleum Association of Mountain States (IPAMS)
Document Control Number: EPA-HQ-OAR-2008-0508-0521.1
Comment Excerpt Number: 16
Comment: In regard to the definition of emergency generators, IPAMS requests that the
specification of hours be removed, as it is not reasonable to limit the number of hours.
Response: In the final rule, EPA has eliminated the 100-hour limitation for emergency
generators. Please refer to the full definition of emergency generator in §98.6.
35
-------
Commenter Name: Angus E. Crane
Commenter Affiliation: North American Insulation Manufacturers Association (NAIMA)
Document Control Number: EPA-HQ-OAR-2008-0508-0537.1
Comment Excerpt Number: 12
Comment: Reporting emissions from portable equipment or generating units is unnecessary.
NAIMA members support EPA's position because, in part, it eliminates some of the burden that
would be imposed on each facility if it had to report emissions from these types of units.
Moreover, EPA's position is consistent with its statement that the "purpose of the general
stationary combustion source category is to capture significant emitters of stationary combustion
GHG emissions that are not covered by the specific source categories described elsewhere in this
preamble." (Id. at 16,482). NAIMA believes that the exemption should be expanded to include
all fossil fuel-powered engines that drive emergency pumps, fans, and other devices that are
neither generators nor portable. Every industrial manufacturer has such devices on-site. But
since fossil fuel-powered engines that drive emergency devices and portable equipment typically
operate very few hours in any given year, they discharge a very small amount of GHG. The
GHG emissions from these devices are the most difficult to compute, and excluding them will
lessen the record keeping and reporting burden with little sacrifice in GHG accounting.
Moreover, either excluding all of these emergency or back up devices or including all of these
emergency or back up devices would be less burdensome than excluding only some of them.
Virtually none of these devices have fuel flow meters or tank gauges that accurately show the
amount of fuel used by that individual unit. Instead, facilities rely on plant-wide fuel usage
figures and it would lessen their burden if they could either report the GHG that was emitted by
all of these engines' fuels or, better yet, just disregard them altogether. Trying to apportion the
amount of diesel fuel, for instance, that was used only by those engines that are included in the
reporting scheme is much harder than just reporting all of the GHG from all of the engine fuel, or
reporting none of the GHG from all of the engine fuel.
Response: EPA has revised several sections of the rule that are relevant. Please refer to the full
definitions of emergency generators, portable equipment, and emergency equipment in §98.6.
Also, please refer to the revised §98.36(c)(3) which clarifies the methodology for reporting units
which are served by a common supply line.
Commenter Name: William C. Herz
Commenter Affiliation: The Fertilizer Institute (TFI)
Document Control Number: EPA-HQ-OAR-2008-0508-0952.1
Comment Excerpt Number: 7
Comment: Under the proposed 40 C.F.R. §98.30(b), EPA would exclude portable equipment or
generating units designated as emergency generators in a permit issued by a state or local air
pollution control agency. 74 Fed. Reg. 16,631. The proposed rule should exclude all portable
equipment, all emergency equipment (such as fire pumps, generating units, flood control pumps,
etc.), and any equipment listed as insignificant in a facility permit. In response to EPA's request
in the NPRM Preamble, portable equipment and emergency equipment should be excluded
regardless of permit designation. 74 Fed. Reg. at 16,461 (FN 31).
36
-------
Response: EPA has maintained the exclusion of emergency generators, and has excluded other
emergency equipment from reporting. EPA has also revised the rule language to remove the
prerequisite for a state or local permit. Please refer to the full definitions of emergency
generators, portable equipment, and emergency equipment in §98.6.
Commenter Name: Paul Glader
Commenter Affiliation: Hecla Mining Company
Document Control Number: EPA-HQ-OAR-2008-0508-0579.1
Comment Excerpt Number: 12
Comment: Hecla agrees that portable equipment and emergency generators are properly
excluded from this rule. Backup generators and portable equipment may vary tremendously in
size and are typically seldom used. Requiring reporting on these sources would be unduly
burdensome, especially on small businesses. Furthermore, collecting data on these sources
would not add significantly to EPA's understanding of the C02e emissions produced in the
United States.
Response: EPA appreciates the commenter's support. EPA has maintained the exclusion of
emergency generators and portable equipment, and has excluded other emergency equipment
from reporting. EPA has also revised the rule language to remove the prerequisite for a state or
local permit. Please refer to the full definitions of emergency generator, portable equipment, and
emergency equipment in §98.6.
Commenter Name: Marc J. Meteyer
Commenter Affiliation: Compressed Gas Association (CGA)
Document Control Number: EPA-HQ-OAR-2008-0508-0981.1
Comment Excerpt Number: 16
Comment: The proposed rule appropriately excludes minor combustion sources from the
definition of the Stationary Fuel Combustion source category, in particular process safety flares.
CGA supports this effort to minimize the burden on regulated facilities, as these units typically
have very low emissions, typically do not have measured flow rates, and do not make a
substantial impact on the total greenhouse gas inventory. Flares typically must operate over a
widely variable flow rate and it is often very challenging to finding an appropriate flow
measurement device capable of covering the range of flows encountered. Any requirement to
include these sources would put an unnecessary costly burden on facilities to add flow
measurement devices to the feed. As further evidence that these devices should be excluded,
thermal oxidizers and air pollution control devices are excluded from greenhouse gas reporting
requirements in the European Union. Where flaring operations are a routine operating control of
a facility, such as in refineries, EPA has explicitly included emission estimation and reporting
requirements. CGA Comment: Clarify that flare emissions should only be included in the
calculations of Subpart C of the rule if another subpart of the rule explicitly requires such
emission calculation and reporting. Flare emissions should be otherwise excluded categorically
or as a de minimis source.
37
-------
Response: EPA has revised the language of the final rule to expand the list of exempted source
categories to exclude flares as defined in §98.6 from reporting under Subpart C, unless their
emissions must are required to be reported by another subpart of Part 98 (see §98.30(b)). It is
EPA's intent that sources allowed to use the Tier 1 and 2 methods, which include smaller
combustion devices and should be inclusive of control devices such as thermal oxidizers, will
only be required to report emissions from the combustion of fuels for which emission factors are
provided. In the Preamble, EPA has explained that "EPA believes that the reporting
requirements for Tier 1 and Tier 2 would only require the reporting of GHG emissions from
supplementary traditional fossil fuels from devices such as thermal oxidizers, pollution control
devices, fume incinerators, burnout furnaces, and other such equipment." EPA also notes that
Subpart W is not being included in this rule at this time.
Commenter Name: Steven M. Pirner
Commenter Affiliation: South Dakota Department of Environment and Natural Resources (SD
DENR)
Document Control Number: EPA-HQ-OAR-2008-0508-0576
Comment Excerpt Number: 15
Comment: EPA is not proposing to require reporting of emissions from portable equipment or
generating units designated as emergency generators in a permit issued by a state or local air
pollution control agency. EPA is requesting comments on "whether or not a permit should be
required for theses emergency generators." This is not the correct venue for determining if an
emergency generator should be required to be permitted. There are current state and federal
requirements already in rule on when emergency generators are permitted. SD DENR agrees
with EPA in not requiring facilities to report greenhouse gas emissions from emergency
generators because the limited number of hours an emergency generator runs results in
insignificant greenhouse gas emissions.
Response: EPA has revised the rule language to remove the prerequisite for a state or local
permit for emergency generators. Please refer to the full definitions of portable equipment,
emergency generator, and emergency equipment in §98.6.
Commenter Name: Jeffry C. Muffat
Commenter Affiliation: 3M Company
Document Control Number: EPA-HQ-OAR-2008-0508-0793.1
Comment Excerpt Number: 10
Comment: The exemption in Section 98.30(b) is narrow in scope and should be expanded. The
explicit designation as an emergency generator in a permit should not be necessary to exclude it
from reporting. In addition, air pollution control devices should be exempt from the rule. Some
emergency generators might not be designated as "emergency" in their air permits even though
they are for emergency use. Furthermore, some may not be permitted at all. How the emissions
from these generators are authorized will vary from state to state, depending on the details of
state programs. The emissions from emergency generators are very small compared to other
stationary fuel combustion sources and are insignificant compared to the inventory of greenhouse
38
-------
gases; therefore, exempting these emissions will not have a significant impact on the usefulness
of the greenhouse gas inventory. Additionally, in Section 98.30(b), the term "emergency
generators" should be changed to "emergency stationary RICE." Many facilities use combustion
units (e.g., diesel engines) as the motive force for pumps, to ensure fire water availability and
process fluid movement during power outages. 3M recommends that EPA exclude all
emergency stationary reciprocating internal combustion engines (RICE) as the term is defined in
40 CFR 63 Subpart ZZZZ (§63.6675). These are sources whose operation is limited to
emergency situations and whose emissions are negligible when compared to other stationary
combustion sources. Exclusion of these sources would exclude sources such as stationary RICE
used to pump water in the case of fire or flood, for example. In §98.30(b), 3M requests that EPA
exclude thermal oxidizers and other air pollution control devices from the definition of stationary
combustion sources requiring calculation and reporting of greenhouse gas emissions. These
units typically have lower emissions with no substantial impact on the total greenhouse gas
inventory and generally would not have measured flow rates. In addition, thermal oxidizers and
air pollution control devices are excluded from the greenhouse gas reporting requirements in the
European Union. For the reasons provided above, 3M recommends that EPA change Section
98.30(b) to read as follows: (b) This source category does not include portable equipment or
units that are emergency stationary reciprocating internal combustion engines. Air pollution
control devices such as thermal oxidizers are also exempt from this source category unless
another subpart of the rule references an air pollution control device as a greenhouse gas
emission source requiring calculation and reporting of emissions.
Response: EPA acknowledges the concerns of the commenter. A number of exemptions to
GHG emissions reporting have been added for certain unconventional combustion processes and
types of fuel. EPA has maintained the exclusion of emergency generators, and has excluded
other emergency equipment from reporting. EPA has also revised the rule language to exclude
the prerequisite for a state or local permit. Please refer to the full definitions of portable
equipment, emergency generator, and emergency equipment in §98.6. EPA has revised the
Preamble and §98.33 to deal with certain unconventional combustion processes and types of
fuel. It is EPA's intent that sources allowed to use the Tier 1 and 2 methods, which include
smaller combustion devices and should be inclusive of control devices such as thermal oxidizers,
will only be required to report emissions from the combustion of fuels for which emission factors
are provided. In the Preamble, EPA has explained that "EPA believes that the reporting
requirements for Tier 1 and Tier 2 would only require the reporting of GHG emissions from
supplementary traditional fossil fuels from devices such as thermal oxidizers, pollution control
devices, fume incinerators, burnout furnaces, and other such equipment." EPA believes that
these provisions satisfy the intent of Part 98, to collect accurate and consistent GHG emissions
data that can be used to inform future decisions.
Commenter Name: Donald R. Schregardus
Commenter Affiliation: Department of the Navy, Department of Defense (DoD)
Document Control Number: EPA-HQ-OAR-2008-0508-0381.1
Comment Excerpt Number: 10
Comment: EPA should expand the emergency generator exemption to cover units that are
exempt per state regulations, including "permit-by-rule," allow owners/operators additional
hours to be used for maintenance check and readiness testing, and consider other legitimate uses
39
-------
of emergency and back-up power generation in its definition of "emergency generator." DoD
agrees with EPA's intent to exempt emergency generators from the GHG mandatory reporting
rule, but believes the descriptions provided in the preamble (several footnotes) and in Subparts C
and D at §§98.30(b) and 98.40(b) are not adequate to cover all emergency generators. A number
of state and local air pollution control agencies exempt emergency generators from certain CAA
regulations via "permit-by-rule" rather than a specific permit for the unit or under a General
permit. These units should also be exempted from the GHG mandatory reporting rule. With
respect to maintenance checks and readiness testing, the January 18, 2008 final rule for
Standards of Performance for Stationary Spark Ignition Internal Combustion Engines (ICE) and
National Emission Standards for Hazardous Air Pollutants for Reciprocating Internal
Combustion Engines, EPA recognized that in some cases, 100 hours was not an adequate limit
for testing of emergency generators. At §60.4243(d), EPA provided an alternative whereby,
"The owner or operator may petition the Administrator for approval of additional hours to be
used for maintenance checks and readiness testing, but a petition is not required if the owner or
operator maintains records indicating that Federal, State, or local standards require maintenance
and testing of an emergency ICE beyond 100 hours per year." This allowance would provide
DoD and other operators of emergency generators a mechanism to test the emergency units to
meet not only manufacturers' requirements but also to meet testing protocols mandated by
Federal standards. Lastly, the definition for "emergency generator" does not include applications
of these units that are common for DoD, specifically training requirements for military personnel
to operate using back-up power in order to be familiar with how their equipment will perform
during an emergency. These applications also do not fit within the 100 hour per year "standard
performance testing" allowed in the definition. EPA should modify the definition for emergency
generator and the exemptions for emergency generators in §§98.30(b) and 98.40(b). Suggested
language revisions: "§98.6 - Emergency generator means a stationary internal combustion
engine that serves solely as a secondary source of mechanical or electrical power whenever the
primary energy supply is disrupted or discontinued during power outages or natural disasters that
are beyond the control of the owner or operator of a facility. Emergency engines operate only
during emergency situations, for training of personnel under simulated emergency conditions,
and for standard performance testing procedures as required by law or by the engine
manufacturer. The hours of operation per calendar year for such standard performance testing
shall not exceed 100 hours. The owner or operator may petition the Administrator for approval
of additional hours to be used for maintenance checks and readiness testing, but a petition is not
required if the owner or operator maintains records indicating that Federal, State, or local
standards require maintenance and testing of an emergency ICE beyond 100 hours per year. An
engine that serves as a back-up power source under conditions of load shedding, peak shaving,
power interruptions pursuant to an interruptible power service agreement, or scheduled facility
maintenance shall not be considered an emergency engine." "§98.30 Definition of the source
category, (b) This source category does not include portable equipment or generating units
designated as emergency generators in a permit issued by a state or local air pollution control
agency, exempt from state permitting requirements, or via 'permit by rule. §98.40 Definition
of the source category, (b) This source category does not include portable equipment or
generating units designated as emergency generators in a permit issued by a State or local air
pollution control agency, exempt from state permitting requirements, or via 'permit by rule.'"
Response: EPA has maintained the exclusion of emergency generators, although it has
eliminated the 100-hour limitation for emergency generators, and has excluded other emergency
equipment from reporting. EPA has also revised the rule language to exclude the prerequisite for
a state or local permit. Please refer to the full definition of emergency generator in §98.6.
40
-------
Commenter Name: Lawrence W. Kavanagh
Commenter Affiliation: American Iron and Steel Institute (AISI)
Document Control Number: EPA-HQ-OAR-2008-0508-0695.1
Comment Excerpt Number: 17
Comment: If reporting of combustion source C02 emissions is retained in the final rule, and if
EPA is unwilling to consider our proposed facility-wide carbon balance approach, which would
cover emissions from all combustion units less than 250 MMBTUH, we respectfully request that
units less than 250 MMBTUH be exempt from reporting. In the alternative, a de minimis
threshold, e.g., the 30 MMBTUH exemption rate corresponding to the exemption threshold of
25,000 metric tons of CCVyear, should be established.
Response: See the Preamble, Section II. E., and the response to comment EPA-HQ-OAR-2008-
0508-0350.1 excerpt 3 for additional explanation of the selection and form of thresholds.
See the Preamble, Section II. K., and the response to comment EPA-HQ-OAR-2008-0508-
0423.2 excerpt 40 for the response on de minimis reporting for small emission points.
EPA has expanded the list of exempted source categories to include portable equipment,
emergency generators, other emergency equipment, irrigation well devices, and flares. EPA has
also removed the cumulative 250 mmBtu/hr restriction on unit aggregation, and believes that the
expanded availability of this option will reduce the reporting burden on facilities.
While units less than 250 mmBtu/hr are not exempt from reporting under Subpart C, they are
typically permitted to use Tiers 1 and 2 for reporting, which should reduce the burden on
facilities.
Commenter Name: See Table 9
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-1021.1
Comment Excerpt Number: 7
Comment: EPA should clarify its exemption from reporting for emergency generators and
similar equipment (e.g., emergency diesel fire pumps) under the proposed rule to acknowledge
that not all states issue permits for this equipment. Because some of these generators and related
equipment are too small to either require a permit or be covered in existing permits, a permit
should not be required for the exemption under this rule.
Response: EPA has maintained the exclusion of emergency generators, and has excluded other
emergency equipment from reporting. EPA has also revised the rule language to exclude the
prerequisite for a state or local permit. Please refer to the full definitions of emergency generator
and emergency equipment in §98.6.
41
-------
Commenter Name: Robert Rouse
Commenter Affiliation: The Dow Chemical Company
Document Control Number: EPA-HQ-OAR-2008-0508-0533.1
Comment Excerpt Number: 20
Comment: Dow Suggests that Emergency Generators and Emergency Stationary Engines
Should Not be Included in the Source Category. EPA requests comment on whether a permit
should be required for emergency generators that are excluded from GHG reporting requirements
in 98.30(b). Dow agrees with EPA that the reporting of GHG emissions from emergency
generators is not necessary. This is supported by their infrequent use and resulting relatively
small contribution to the total GHG inventory. Excluding these emissions will not have a
significant impact on the usefulness of the GHG inventory. In 98.30(b), Dow does not believe
that designation as an emergency generator in a permit should be necessary to exclude them from
reporting. Some emergency generators might not be designated as "emergency" in their air
permit even though they are for emergency use. Further, the "authorization" or "permitting" of
emissions from these generators varies from state to state, depending on the details of state NSR
permitting programs. For example, the Texas NSR permitting program allows either the
permitting of these sources and also authorizes these sources using a Permit by Rule. Dow
suggests that an internal record that identifies these sources as an "emergency generator" should
be sufficient to properly identify these sources as such. In addition, in 98.30(b), the term
"emergency generators" should be expanded to "emergency generators and engines." Dow
suggests that EPA exclude all emergency stationary reciprocating internal combustion engines
(RICE) as the term is defined in 40 CFR 63 Subpart ZZZZ (63.6675). These are sources whose
operation is limited to emergency situations whose emissions are negligible when compared to
other stationary combustion sources. Exclusion of these sources would exclude sources such as
stationary RICE used to pump water in the case of fire or flood, for example. Dow Suggests that
EPA Should Clarify the Applicability of Subpart C for Emission Control Equipment Such as
Flares, Thermal Oxidizers, and Other Air Pollution Control Devices. At a minimum, EPA
should clarify that flare/emission control device emissions should be included in the calculations
of Subpart C of the rule if another subpart of the rule references "flares" or "emission control"
equipment as a GHG emission source requiring calculation and reporting of emissions.
Examples include Subpart X (Petrochemical Facilities) and Subpart Y (Petroleum Refineries).
The final rule should clarify the requirements for flares and emission control equipment that
combust emissions from other source categories that are not specifically addressed in the
proposed rule. Dow suggests that EPA include the emissions from these sources if they exceed
1,250 metric tons of C02e, which is 5% of the 25,000 metric ton reporting trigger. This
approach would ensure the reporting of larger emitting flares/control equipment while excluding
sources that may only handle intermittent types of vents. Dow Suggests that EPA Should Clarify
the Applicability of Subpart C for Facilities that Combust Hazardous Waste. It is not clear
whether EPA intended for facilities to report GHG emissions of hazardous waste burned in
hazardous waste incinerators or combustors. For example, Table C-l on page 16481 of the
Federal Register does not mention hazardous waste fuels. Dow recommends that EPA exempt
hazardous waste combustion units from the rule. These units would be relatively small
contributions to the total inventory and may vary widely in flow rate and composition, thus
making the calculations more difficult. Furthermore, EPA has recognized the relatively small
contribution by exempting hazardous waste from the calculations and reporting in the landfill
subpart of this proposed rule.
42
-------
Response: See the Preamble and separate comment response document volume for the response
on de minimis reporting for small emission points.
EPA has maintained the exclusion of emergency generators and has excluded other emergency
equipment from reporting. EPA has also revised the rule language to exclude the prerequisite for
a state or local permit. Please refer to the full definitions of emergency generator and emergency
equipment in §98.6.
EPA has expanded the list of exemptions from the stationary combustion source category in
§98.30(b) to include flares, except where another subpart requires flare emissions to be reported.
Emissions from hazardous waste incinerators need not be reported unless CEMS are used to
monitor emissions or a fuel for which emission factors are provided is also combusted in the
unit. In that case, only emissions from the supplemental fuel need to be reported.
EPA has revised the Preamble and §98.33 to deal with certain unconventional combustion
processes and types of fuel. It is EPA's intent that sources allowed to use the Tier 1 and 2
methods, which include smaller combustion devices and should be inclusive of control devices
such as thermal oxidizers, will only be required to report emissions from the combustion of fuels
for which emission factors are provided. In the Preamble, EPA has explained that "EPA believes
that the reporting requirements for Tier 1 and Tier 2 would only require the reporting of GHG
emissions from supplementary traditional fossil fuels from devices such as thermal oxidizers,
pollution control devices, fume incinerators, burnout furnaces, and other such equipment." EPA
believes that these provisions satisfy the intent of Part 98, to collect accurate and consistent GHG
emissions data that can be used to inform future decisions.
Commenter Name: Ron Downey
Commenter Affiliation: LWB Refractories
Document Control Number: EPA-HQ-OAR-2008-0508-0719.1
Comment Excerpt Number: 6
Comment: Preamble C., p 173-174. EPA's asked for comments regarding portable equipment.
We agree with EPA's proposal not to require reporting of portable equipment or generating units
designated as emergency generators in a permit issued by a state.
Response: EPA appreciates the commenter's support. EPA has maintained the exclusion of
emergency generators, and has excluded other emergency equipment from reporting. EPA has
also revised the rule language to exclude the prerequisite for a state or local permit. Please refer
to the full definitions of emergency generator and emergency equipment in §98.6. Portable
equipment, as defined in §98.6, is also exempt from reporting.
43
-------
Commenter Name: Donald R. Schregardus
Commenter Affiliation: Department of the Navy, Department of Defense (DoD)
Document Control Number: EPA-HQ-OAR-2008-0508-0381.1
Comment Excerpt Number: 5
Comment: Many complex facilities that will be subject to the reporting rule under §98.2(a)(1),
(a)(2), or(a)(3) will be required to inventory a large number of small combustion units covered
by the rule. We believe a size threshold is needed in the stationary combustion source category
to reduce undue cost burden while still achieving EPA's goal of obtaining GHG data of sufficient
quality that it can be used to support a range of future climate change policies and regulations.
With the goal of focusing this rulemaking on large GHG emitters, EPA writes that it is able to
minimize the cost burden of the rule while still gathering GHG data in sufficient detail to advise
future policy decisions. However, an unnecessary burden will be placed on reporting sources if
the combustion unit source category does not have minimum size threshold added to the source
category definition. In the Memorandum: Reporting Methods for Small Emission Points (De
Minimis Reporting), EPA discusses the possibility of a de minimis provision to avoid imposing
excessive reporting costs on minor emission points that can be burdensome or infeasible to
monitor. EPA analyzed the de minimis provisions of existing reporting rules and concluded that
there is no need to exclude a percentage of emissions from reporting under this proposal. EPA
explains that it attempts to avoid burdening smaller sources in the way it sets thresholds and
providing simplified emission estimation methods such as the application of Tiers 1 and 2 for
small units. However, this approach will not provide relief to complex sources. As EPA
determined during the development of the Title V, Operating Permit Program, there was a need
to provide exemptions for insignificant activities or emission levels. This is incorporated in 40
CFR §70.5(c). The Title V regulation limits the State's discretion by precluding such exemptions
if they would interfere with the determination or imposition of any applicable requirement.
Permit applications are to include lists containing information on the insignificant activities that
are exempted except for those exemptions which apply to an entire category of activities, such as
space heaters. As supported by the Alabama Power decision, the Administrator may determine
levels below which there is no practical value in conducting an extensive review. States such as
Oregon (at OAR-340-200-0020) have taken the approach of developing a 'categorically
insignificant activity' with heat capacity limits for liquid and gaseous-fueled units. The
Technical Support Document (TSD) for "Stationary Fuel Combustion Emissions" and "Technical
Support Thresholds: Proposed Rule for Mandatory Reporting of Greenhouse Gases" both show
that commercial and residential sectors emitted about 14 percent of U.S. GHG emissions from
stationary fuel combustion. In Table 5-5, which lists industrial and commercial boiler population
in the U.S., boilers less than 10 MMBtu/hr are not tabulated, suggesting they do not belong in
this source category. The commercial sector includes emissions from fuel combustion in
commercial and institutional buildings (space heating and cooling, water heating, cooking and
baking, and dryers). The residential sector includes emissions from household fuel combustion
(space heating, water heating, and cooking). The Regulatory Impact Analysis, at page 27,
explains the high cost and burden that would be incurred if the rule covered the commercial and
residential sectors. To avoid this impact, the proposed rule does not include all of those emitters,
but instead requires reporting by the suppliers of industrial gases and suppliers of fossil fuels. In
Subpart C - General Stationary Fuel Combustion Sources - the definition of "stationary fuel
combustion sources" at §98.30(a) appears to capture all heaters of any size or purpose, used for
industrial, commercial, or institutional purposes. This definition lists every 'level' of fuel
combustion source except for residential units but there is no language specifically excluding
44
-------
residential units. There are also no definitions of commercial or residential units in the proposal.
Although §98.36(c)(1) allows for aggregation of units for reporting of emissions from this source
category, the facility would still be required by the proposed language in §98.36(c)(l)(ii) to
identify each unit, no matter how small, and provide a unit ID Number. Requiring a listing of
individual units that are not intended to be covered by the rule is a burdensome and un-necessary
collection of data, as it is not clear what use the EPA intends for the detailed data on small
aggregated stationary fuel combustion sources that would be gathered under this proposed
reporting requirement. These simplifications provided in Subpart C do not provide relief to
facilities that operate small combustion sources that have insignificant impact on emission totals
such as office building or control room comfort heating, cafeteria operations or heated lockers
that are located on the footprint of the industrial activity. We recommend to EPA to align the
source definition in Subpart C to match the intent of the rule to focus on large emitters and to
clarify the sources subject to the rule. Include definitions for commercial and residential fuel
combustion sources. Specifically exclude residential units from the source category. Set a
capacity threshold for commercial-size units that are excluded from the source category.
Response: See the Preamble and separate comment response document volume for the response
on de minimis reporting for small emission points. See the response to comment EPA-HQ-
OAR-2008-0508-0615 excerpt 21 for an explanation of the treatment of residential facilities.
EPA acknowledges the commenter's concerns and has expanded the list of combustion sources
and fuels that are exempted from reporting. Please refer to §98.6 for revised definitions of
portable equipment, emergency generators, other emergency equipment that are exempted. The
revised source category definition also exempts irrigation well devices and flares, except where
covered by other parts of the rule. In addition, EPA has also removed the cumulative 250
mmBtu/hr restriction on unit aggregation and clarified the use of common supply line metering,
and believes that the expanded availability of this option will reduce the reporting burden on
facilities. However, EPA does not agree with the commenter's assertion that the amount of unit-
level data and verification information to be reported is excessive, burdensome, or unnecessary.
For this mandatory GHG emissions reporting rule, two main approaches to data verification were
considered, i.e., EPA verification and third-party verification. EPA decided on the former
approach. In view of this, additional, unit-level information, including ID numbers for units
grouped in common pipe or common stack configurations and included in unit aggregation, is
deemed necessary to provide assurance that the reported facility-wide GHG emissions data are
both credible and accurate.
Commenter Name: Ron Downey
Commenter Affiliation: LWB Refractories
Document Control Number: EPA-HQ-OAR-2008-0508-0719.1
Comment Excerpt Number: 5
Comment: Preamble C., p 172 and Subpart C, 98.30 (a). The definition of stationary fuel
combustion source category includes but is not limited to among other sources incinerators.
Incinerators are not clearly defined as we could determine. The reporting requirements are
different depending on the TIER selected for reporting. One definition of incinerator would
include waste combustors such as municipal waste or other units that reduce the volume of waste
such s a municipal waste incinerator. Does this incinerator definition include hydrocarbon
45
-------
pollution control devices such as a thermal incinerator, catalytic incinerator or regenerative
thermal oxidizers that are required to meet permitted emissions limits? We have several sources
that are combustion sources (ovens, kilns) that have an incinerator to control organic emissions.
In this case does the incinerator (control device) meet the definition of a stationary fuel
combustion source and require emission reporting? Several different issues are involved. A gas
or oil fired kiln would meet the reporting criteria? Does the fuel required to fire the incinerator
meet the reporting criteria? Does any GHG from the hydrocarbon emissions from the organic
binder meet the reporting criteria? Again this may be dependent on the TIER selected for
reporting. In many cases these sources are small and would not justify the purchase of a C02
CEM for recording GHG emissions.
Response: It is EPA's intent that sources allowed to use the Tier 1 and 2 methods, which include
smaller combustion devices and should be inclusive of control devices such as thermal oxidizers,
will only be required to report emissions from the combustion of fuels for which emission factors
are provided. In the Preamble, EPA has explained that "EPA believes that the reporting
requirements for Tier 1 and Tier 2 would only require the reporting of GHG emissions from
supplementary traditional fossil fuels from devices such as thermal oxidizers, pollution control
devices, fume incinerators, burnout furnaces, and other such equipment." The Agency believes
that these provisions satisfy the intent of Part 98, to collect accurate and consistent GHG
emissions data that can be used to inform future decisions. The commenter is encouraged to
consider the complete definitions provided in the revised §98.6.
Commenter Name: Edgar O. Morris
Commenter Affiliation: Mosaic Fertilizer Company LLC
Document Control Number: EPA-HQ-OAR-2008-0508-0687.1
Comment Excerpt Number: 5
Comment: The proposal properly excludes portable equipment and certain emergency
equipment from its definition of stationary fuel combustion sources subject to GHG reporting.
See proposed 40 C.F.R. §98.30(b). However, this definition should be clarified to cover other
emergency equipment in addition to "portable equipment or generating units designated as
emergency generators" and should cover all portable and emergency equipment, regardless of
whether they are so designated on a permit. Additional emergency equipment would include
such things as fire protection pumps and flood control pumps. These types of equipment are
equivalent to emergency generators in that they are only utilized in response to abnormal
emergency conditions necessary for protection of life and property. This definition should also
exclude any equipment associated with insignificant emissions and therefore not regulated or
subject to other reporting requirements in an air permit. For all of these sources the same
rationale applies: Reporting GHG emissions from these minor sources imposes a reporting
burden on companies and provides only immaterial GHG emissions information to EPA. Mosaic
proposes the following clarifying revision: §98.30 Definition of the source category (b) This
source category does not include portable equipment or equipment designated as "emergency"
equipment, or sources designated as "insignificant" in a permit issued by a state or local air
pollution control agency.
Response: EPA has maintained the exclusion of emergency generators, and has excluded other
emergency equipment from reporting. EPA has also revised the rule language to remove the
46
-------
prerequisite for a state or local permit. Please refer to the full definitions of portable equipment,
emergency generators, and emergency equipment in the revised §98.6.
Commenter Name: Lawrence W. Kavanagh
Commenter Affiliation: American Iron and Steel Institute (AISI)
Document Control Number: EPA-HQ-OAR-2008-0508-0695.1
Comment Excerpt Number: 4
Comment: Cokemaking operations, whether contained within integrated steel plants or operated
as stand-alone facilities, are obligated under the proposed rule to report emissions from
combustion stacks under terms of Subpart C and from pushing operations using an emission
factor provided in Subpart Q. Many coke plants also have boilers or other combustion sources
that would be subject to reporting under Subpart C. In the first instance, any C02 emitted from
coke oven combustion stacks will have already been accounted for by reports of coal suppliers
under Subpart KK. Thus, reporting of C02 from combustion of coke oven gas for underfiring
ovens or other combustion sources is duplicative. Furthermore, requirements for reporting these
emissions is inconsistent with the stated intention of the rule - as well as underlying intent of the
Congressional mandate - to require reporting of upstream sources to the maximum extent
possible. For this reason, AISI and ACCCI strongly urge EPA to delete coke oven combustion
stack CO2 reporting from the rule.
Response: See the Preamble for the response on the statutory authority for the reporting rule
and separate comment response document volume for the response on definition of the source
category.
EPA intends that the stationary combustion source category include any device that meets the
definition included in §98.30 for which emissions are not accounted for in the report through a
separate subpart of the rule. Per the requirements in 40 CFR Part 98, Subpart A, facilities have
to report GHG emissions from all source categories located at their facility, including stationary
combustion and process emissions. EPA has revised the various subparts of the final rule to
clarify the intent of the stationary combustion source category.
The commenter should note that EPA is not preparing a final version of the subpart for suppliers
of coal at this time. The commenter should also note that EPA was asked to collect data from
both upstream and downstream sources. The calculation methods for downstream reporters are
based on collecting the best information from downstream emitters. See the Preamble, Section
II. D. 3., for the response to comments on the inclusion of upstream and downstream reporters.
Commenter Name: Jay M. Dietrich
Commenter Affiliation: IBM
Document Control Number: EPA-HQ-OAR-2008-0508-0978.1
Comment Excerpt Number: 4
Comment: Inclusion of Emergency Generator Fuel Use in Emissions Reports IBM agrees with
EPA that it is not necessary to include the fuel use from permitted Emergency Generating units.
47
-------
These units are typically restricted to less than 500 hours of operation per year and, using IBM's
facilities as an example, represent less than 0.1% of the fuel use at the facilities that would be
covered by the proposed reporting thresholds. On page 16480 of the Federal Register rule, EPA
states "We request comment on whether or not a permit should be required for these emergency
generators." Permits, beyond the current operating permits for these systems, should not be
required nor should the permit requirements be modified to include language for the
management of C02 emissions
Response: EPA has maintained the exclusion of emergency generators, and has excluded other
emergency equipment from reporting. EPA has also revised the rule language to remove the
prerequisite for a state or local permit. Please refer to the full definitions of emergency generator
and emergency equipment in §98.6.
Commenter Name: Jessica S. Steinhilber
Commenter Affiliation: Airports Council International North America (ACI-NA)
Document Control Number: EPA-HQ-OAR-2008-0508-1063.1
Comment Excerpt Number: 9
Comment: EPA states that generator usage for "scheduled facility maintenance shall not be
considered an emergency engine." Many facilities occasionally rely on generators during de-
electrification of a system for a high-power replacement of electric switching or required
maintenance of such a high-voltage system. ACI-NA suggests that such generator use falls
within the definition of "emergency generator" when the total hours used, including generator
standard performance testing, do not exceed 200 hours per calendar year. While EPA proposes a
usage threshold of 100 hours per calendar year, there is existing precedent for relying on 200
hours. As one example, California's South Coast Air Quality Management District Rule 1304
(a)(4) defines "Emergency Equipment" as a "source [that] is exclusively used as emergency
standby equipment for nonutility electrical power generation or any other emergency equipment
as approved by the Executive Officer or designee, provided the source does not operate more
than 200 hours per year as evidenced by an engine-hour meter or equivalent method." This
situation happens very infrequently, but is necessary to keep electric systems that are crucial to
safe and essential airport operations running at optimum efficiency.
Response: EPA has revised the final rule to eliminate the 100-hour limitation for emergency
generators. Please refer to the full definitions of emergency generator and emergency equipment
in §98.6.
Commenter Name: Lauren E. Freeman
Commenter Affiliation: Hunton & Williams LLP
Document Control Number: EPA-HQ-OAR-2008-0508-0493.1
Comment Excerpt Number: 24
Comment: Under Subpart C, the term "stationary fuel combustion sources" is defined simply as
a device that combusts fuel. Proposed §98.30(a). Although the rule describes some of the
general uses of these devices, it does not require that the device be used for any particular
48
-------
purpose. UARG is concerned that miscellaneous combustion sources, like small gas-fired
heaters, stoves, or even hot water heaters, at electric generating facilities could be construed as
falling under that broad description. Reporting GHG emissions from such miscellaneous devices
could be very difficult even using the Tier 1 methodology because specific data on fuel
consumption might not be available. To avoid requiring reporting from such activities, UARG
request that EPA either provide a more specific definition of combustion device or include a de
minimis cut-off.
Response: See the Preamble and separate comment response document volume for the response
on de minimis reporting for small emission points. In addition, EPA has also removed the
cumulative 250 mmBtu/hr restriction on unit aggregation and clarified the use of common supply
line metering, and believes that the expanded availability of this option will reduce the reporting
burden on facilities, particularly for including smaller combustion sources.
EPA appreciates the commenter's concern, and believes that the revised §98.30 appropriately
defines the general stationary combustion source category.
Commenter Name: Karen St. John
Commenter Affiliation: BP America Inc. (BP)
Document Control Number: EPA-HQ-OAR-2008-0508-0631.1
Comment Excerpt Number: 55
Comment: "EPA is proposing to not require reporting of emissions from portable equipment or
generating units designated as emergency generators in a permit issued by a state or local air
pollution control agency. We request comment on whether or not a permit should be required
for these emergency generators." (p. 16480) BP supports EPA's approach of not requiring
emissions reporting from emergency equipment or portable equipment. BP recommends that
EPA extend the scope of this exclusion to include all emergency equipment (not just generators)
such as fire-water pumps, life boats, etc along with portable equipment. BP does not believe that
designation as an emergency unit in a permit should be necessary to exclude emergency
equipment from reporting. Some emergency equipment may not be designated as "emergency"
in their air permit even though they are for emergency use. Further, some may not be permitted
at all. How the emissions from these emergency units are authorized will vary from state to state
and jurisdiction to jurisdiction, depending on the details of the programs. For example, due to
the MMS jurisdiction in Federal waters there is no permit program and no opportunity to
establish a permit designation; Indiana does not permit emergency generators at all, but rather
considers them to be de minimis; Texas might cover them under a PBR (Permit by Rule). In
§98.30(b), the term "emergency generators" should be changed to "emergency generators,
pumps, lifeboats, and other emergency equipment." Many facilities use combustion units (e.g.,
diesel engines) as the motive force for emergency pumps, to ensure fire water availability and
process fluid movement during power outages and life boats are powered with liquid fuels. BP
further recommends that EPA exclude all emergency stationary reciprocating internal
combustion engines (RICE) as the term is defined in 40 CFR 63 Subpart ZZZZ (§63.6675).
These are sources whose operation is limited to emergency situations and whose emissions are
negligible when compared to other stationary combustion sources. Exclusion of these sources
would exclude sources such as stationary RICE used to pump water in the case of fire or flood,
for example. EPA should also consider exclusion of infrequent use stationary units (such as
49
-------
small generators) which are used during maintenance activities for control and minor power uses.
EPA should specifically acknowledge that portable onshore drilling and completion rigs and
mobile offshore drilling units (regardless of time at the same lease block or coordinates) (vessels)
are "portable sources" and excluded for rule applicability.
Response: Because of the need for comprehensive, national greenhouse gas emissions data, the
final rule provides only limited exclusions from the reporting requirements. In the final rule
EPA has maintained the exclusion of emergency generators and portable equipment, has
removed the requirement for a state or local permit designating them as emergency generators,
and has excluded other emergency equipment from reporting. See §98.6, which includes
definitions of emergency generator and emergency equipment. However, stationary units used
during scheduled or routine maintenance are not emergency equipment and are not excluded.
This is because maintenance operations are not necessarily infrequent, the equipment involved
can be of widely varying sizes, and consequently the GHG emissions from these operations
cannot be assumed to be, and treated as, insignificant. With regard to the application of the
portable equipment exclusion to equipment on onshore drilling and completion rigs and on
offshore drilling units, the exclusion covers only equipment that is portable, as defined in the
rule. Under the definition of "portable," equipment that is "designed and capable of being
carried or moved from one location to another" is portable, unless such equipment meets one or
more certain specified criteria related to ability to be moved and residency time at a particular
location within a facility. The commenter does not provide any basis for changing the definition
and instead requests that EPA state that equipment on onshore drilling and completion rigs and
on offshore drilling units is, under all circumstances, portable, but such a statement would be
inconsistent with the definition of "portable." The applicability of the "portable" definition, and
thus of the reporting requirements, to particular equipment on a particular onshore rig or offshore
unit will depend on the specific circumstances of such rig or unit. Currently lacking such
information about the rigs and units, EPA cannot make a determination at this time with regard
to the commenter's equipment, but intends to do so in the future, upon request, when such
information is provided.
Commenter Name: Rich Raiders
Commenter Affiliation: Arkema Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-0511.1
Comment Excerpt Number: 50
Comment: EPA has long recognized that hazardous waste combustors as the most highly
regulated units under the Clean Air Act. Because of the nature of the materials that these
combustors process, EPA has appropriately promulgated extensive operating and monitoring
requirements to minimize public risk from waste management operations, where EPA has a
vested interest in protecting the public from undue risks from hazardous waste activities.
Because of this appropriate scrutiny, reporters operating hazardous waste combustion ("HWC")
MACT (40 CFR 63 Subpart EEE) units are required to collect extensive quantities of
information concerning the streams being combusted in each affected source. Regulated
facilities are required to develop detailed waste profiles, describing the composition of the
significant components of each stream, the BTU value of each stream, and the firing schedule for
each processed waste, for each waste stream introduced into the combustion unit. This
compendium of information constitutes a very detailed process knowledge base whereby
50
-------
operators of HWC MACT units can identify, in significant detail with reasonable accuracy, the
GHG emissions being emitted from each hazardous waste combustor. 40 CFR 63 Subpart EEE
contains extensive instrument monitoring and management provisions that represent the state of
the art in parametric monitoring systems. The HWC MACT also requires operators to test each
affected source twice every five years for a variety of emissions, including C02 emissions by
EPA Method 3 (40 CFR 60, Appendix A). The HWC MACT periodic testing requirements, the
most extensive testing requirements in all EPA compliance programs, protect the environment
and provide adequate data for any reporting system that may be required, including proposed
Part 98. HWC MACT operators must also manage the heat value of streams entering the
combustor unit. For example, in one Arkema HWC MACT unit, heat values for one stream are
determined per batch of material charged to the combustor, and on a periodic basis for a second
stream. The facility has the ability to directly evaluate if each stream contributes comparable
heat value, as defined by the comparable fuels rule, to the combustion device. These monitoring
activities provide data on indicator parameters, a subset of the extensive list of potential analytes
that indicate how the stream will perform in the combustor. Supplemental fuel (typically natural
gas) is metered using typical natural gas flow meters. As this facility can determine the total fuel
loading and heat value by existing systems, no further evaluation of the heating value of the
materials combusted should be required. Streams not contributing significant heat value should
not be tracked for Part 98 compliance. Part 98 should recognize the existing regulatory scrutiny
already placed on HWC MACT operators, and should only require a facility complying with the
HWC MACT to use existing data to calculate annual actual GHG emissions. Part 98 should
exclude all data management, equipment calibration, and parametric monitoring conditions for
any unit complying with 40 CFR 63 Subpart EEE. Compliance with the HWC MACT should be
deemed compliance with Part 98, except for the end-of-year actual GHG emission calculation
based on existing compliance data. EPA should further note in the preamble of any final Part 98
rule that the existing Method 3 CO2 determinations from HWC MACT comprehensive
performance tests ("CPT") comprise adequate data to derive a site-specific emission CO2
emission factor with no further testing required.
Response: See the General Stationary Combustion source category section of the Preamble and
the separate source category comment response document for the response on the definition of
the source category.
EPA acknowledges the concerns of the commenter. Section 98.30 of the final rule clarifies the
definition of the general stationary fuel combustion source category and provides an expanded
list of sources exempted from GHG emissions reporting under Subpart C. Subsection (c) states
that, "For a unit that combusts hazardous waste, . . . reporting of GHG emissions is not required
unless: (1) Continuous emission monitors (CEMS) are used to quantify CO2 mass emissions; or
(2) Any fuel listed in Table C-l of this subpart is also combusted in the unit. In this case,
reporting of the GHG emissions from combustion of the other fuel(s), i.e., the fuel(s) listed in
Table C-l, is required." If reporting of GHG emissions is required, there is no requirement to
derive a site-specific emission factor for CO2, and the default factors used in Table C-l can be
used. For this reason, the concern raised about the burden or inclusion of hazardous waste
combustion is addressed without the specific change requested by the commenter.
51
-------
Commenter Name: See Table 6
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0679.1
Comment Excerpt Number: 48
Comment: EPA is proposing to not require reporting of emissions from portable equipment or
generating units designated as emergency generators in a permit issued by a state or local air
pollution control agency. We request comment on whether or not a permit should be required
for these emergency generators." (p. 16480) API supports EPA's approach of not requiring
emissions reporting from emergency equipment or portable equipment. The scope of this
exclusion should be broadened to include all emergency equipment (not just generators) such as
fire-water pumps, life boats, etc. API does not believe that designation as an emergency unit in a
permit should be necessary to exclude emergency equipment from reporting. Some emergency
equipment may not be designated as "emergency" in their air permit even though they are for
emergency use. Further, some may not be permitted at all. How the emissions from these
emergency units are authorized will vary from state to state and jurisdiction to jurisdiction,
depending on the details of the programs. For example, due to the MMS jurisdiction in Federal
waters there is no permit program and no opportunity to establish a permit designation; Indiana
does not permit emergency generators at all, but rather considers them to be de minimis; Texas
might cover them under a PBR (Permit by Rule). EPA should allow additional alternatives for
omitting reporting for an emergency unit other than description in an air permit, such as type of
use. The emissions from emergency units are very small compared to other stationary fuel
combustion sources, and are insignificant compared to the inventory of greenhouse gases;
therefore, discounting these emissions will not have a significant impact on the usefulness of the
greenhouse gas inventory. Also in §98.30(b), the term "emergency generators" should be
changed to "emergency generators, pumps, lifeboats, and other emergency equipment." Many
facilities use combustion units (e.g., diesel engines) as the motive force for emergency pumps, to
ensure fire water availability and process fluid movement during power outages and life boats
are powered with liquid fuels. API further recommends that EPA exclude all emergency
stationary reciprocating internal combustion engines (RICE) as the term is defined in 40 CFR 63
Subpart ZZZZ (§63.6675). These are sources whose operation is limited to emergency situations
and whose emissions are negligible when compared to other stationary combustion sources.
Exclusion of these sources would exclude sources such as stationary RICE used to pump water
in the case of fire or flood, for example. EPA should exclude infrequent use units (such as small
stationary engines) in the same manner in which they have excluded portable equipment which
are used during maintenance activities for control and minor power uses. EPA should
specifically acknowledge that portable onshore drilling and completion rigs and mobile offshore
drilling units (vessels) are "portable sources", regardless of time at the same lease block or
coordinates, and excluded for rule applicability.
Response: EPA has maintained the exclusion of emergency generators, and has excluded other
emergency equipment from reporting. EPA has also revised the rule language to remove the
prerequisite for a state or local permit. Please refer to the full definitions of portable equipment,
emergency generators, and emergency equipment in §98.6. The definition of emergency
generator includes emergency recipriocating internal combustion engines or turbines. The
commenter should note that generators and other equipment used during scheduled facility
maintenance are not considered emergency equipment.
52
-------
Commenter Name: Karen St. John
Commenter Affiliation: BP America Inc. (BP)
Document Control Number: EPA-HQ-OAR-2008-0508-0631.1
Comment Excerpt Number: 46
Comment: Heating value §98.6 (p. 16622): The use of the API compendium would be clearer.
Suggested definition is: "Heating Value: The amount of energy released when a fuel is burned
completely. (See also HHV and LHV). HHV: Higher Heating Value or Gross Calorific Value.
The quantity of heat produced by the complete combustion of a unit volume or weight of fuel
assuming that the produced water is completely condensed (liquid state) and the heat is
recovered. LHV: Lower Heating Value or Net Calorific Value. The quantity of heat produced
by the complete combustion of a unit volume or weight of fuel assuming that the produced water
remains as a vapor and the heat of the vapor is not recovered. The difference between the HHV
and LHV is the latent heat of vaporization of the product water (i.e., the LHV is reduced by the
enthalpy needed to vaporize liquid water).
Response: The commenter did not identify how the EPA definition of HHV was unclear and,
therefore, it is difficult to respond to the request to change the definition. EPA believes that the
proposed definition of high heat value includes the concepts identified by the commenter and has
finalized this definition.
Commener Name: Gregory A. Wilkins
Commenter Affiliation: Marathon Oil Corporation
Document Control Number: EPA-HQ-OAR-2008-0508-0712.1
Comment Excerpt Number: 45
Comment: Marathon proposes exempting emissions from any portable equipment
(compressors, generators, welders, etc.), stationary engines (that do not burn refinery fuel gas or
natural gas), or emergency equipment. EPA currently proposes to not require reporting of
emissions from emergency generating units but EPA should further that exemption to include all
emergency equipment including fire water pump drivers. Additionally, Marathon would like to
propose that in order to use this exemption, the emergency equipment should not be required to
be listed in a permit, and instead equipment be excluded if they are designated by the facility for
emergency use. Also, as an example, any equipment exempted from a Title V permit or any de
minimis activities as identified in a Title V permit or program should be exempted. These
sources are not only small and insignificant to the overall emissions data but are also extremely
difficult to estimate due to their mobility and the number of units. Another problem is that many
are used by contractors and are difficult to track. Also, the fuel used in this equipment (engines,
portable equipment, etc.) is already being counted as product emissions from the facility where
the fuel was produced. This would result in double counting. It is onerous to track fuel used for
small portable, stationary, or emergency equipment for insignificant emissions and should be
exempted or allowed to be accounted for as a portion of the de minimis level.
Response: See the Preamble and separate comment response document volume for the response
on de minimis reporting for small emission points.
53
-------
EPA has expanded the list of exempted source categories to include portable equipment,
emergency generators, other emergency equipment, irrigation well devices, and flares except
where required in other subparts of the rule. EPA has revised the rule language to remove the
prerequisite of a state or local permit for the exclusion of an emergency generator. Please refer
to the full definitions of emergency generator, emergency equipment, and portable equipment in
§98.6. In addition, EPA has revised the rule in order to ease the reporting burden on facilities,
such as allowing the use of a common supply line to determine fuel combustion, and removing
the cumulative 250 mmBtu/hr restriction on unit aggregation.
The commenter should note that EPA was asked to collect data from both upstream and
downstream reporters. The calculation methods for downstream reporters are based on
collecting the best information from downstream emitters.
Commenter Name: Michael Carlson
Commenter Affiliation: MEC Environmental Consulting
Document Control Number: EPA-HQ-OAR-2008-0508-0615
Comment Excerpt Number: 16
Comment: We recommend that the exemption for reporting of GHG emissions from emergency
generators not be limited to those generators which are permitted by either the state or local air
pollution control agency. Some generators, particularly smaller ones, are not required by all
state or local authorities to be permitted and thus would be subject to reporting under the
proposed rule as written.
Response: EPA has maintained the exclusion of emergency generators, and has excluded other
emergency equipment from reporting. EPA has also revised the rule language to remove the
prerequisite for a state or local permit. Please refer to the full definitions of emergency generator
and emergency equipment in §98.6.
Commenter Name: Keith Overcash
Commenter Affiliation: North Carolina Division of Air Quality (NCDAQ)
Document Control Number: EPA-HQ-OAR-2008-0508-0588
Comment Excerpt Number: 24
Comment: If a permit for these sources is to be requested then the definitions should be aligned
with other regulations. For example; definition of emergency generator should be aligned with
NSPS subparts IIII and JJJJ depending on the fuel used. These rules also include the standard
performance testing being limited to 100 hours or less but for a limited group of generators.
Subpart IIII limits the generators affected to those units whose construction, modification or
reconstruction began after July 11, 2005. Currently NC DAQ does not permit emergency
generators if this is the only emission source at a facility. There is no definition in the proposed
rule for peak-shaving generators. How does EPA propose to handle these emission sources?
Does the facility report the emissions from these sources if the facility is over the reporting
threshold or does the power company report their emissions? If a facility that exceeds the
54
-------
reporting threshold sells an emergency generator to a facility that is below the reporting
threshold, does the new owner of the generator have to report the emissions? This provision in
the rule will be a recordkeeping nightmare. How does EPA propose to track equipment sold by
facilities that have exceeded the reporting threshold? The database for reporting the GHG
emissions will have to be able to handle the facility-wide emissions from a facility that exceeds
the threshold and emission source specific emissions from sources that changed ownership if the
new owner's GHG emissions are below the reporting threshold.
Response: EPA believes that the applicability provisions and definitions of the rule should be
appropriate in light of the purposes of the rule and so need not necessarily "align" with the
applicability provisions and definitions in other rules. Because of the need for comprehensive,
national greenhouse gas emissions data, the rule provides only limited exclusions from the
reporting requirements. In the final rule, EPA has maintained the exclusion of emergency
generators, has removed for such generators the 100-hour limitation and the requirement of
designation in a state or local permit, and has excluded other emergency equipment from
reporting.
However, emergency generators are limited to generators that "serve solely as a secondary
source of mechanical or electrical power whenever the primary energy supply is disrupted or
discontinued during power outages or natural disasters that are beyond the control of the owner
or operator of a facility." Consequently, generators that serve "as a back-up power source under
conditions of load shedding, peak shaving, power interruptions pursuant to an interruptible
power service agreement, or scheduled facility maintenance" are not emergency generators.
Generators that serve as back-up power sources under conditions of load shedding, peak
shaving, power interruption pursuant to an interruptible power source agreement, or scheduled
maintenance are not excluded because these operations are not necessarily infrequent, the
equipment involved can be of widely varying sizes, and so the GHG emissions from these
operations cannot be assumed to be, and treated as, insignificant. Because emissions are
reported on a facility basis, peak-shaving generators' emissions will be reported by the facility
where the generators are located. When generators are sold (and presumably moved) to a
different facility, emissions will be reported consistent with that facility's reporting obligations
under the rule in light of the sale. The owners and operators of the initial facility, and the owners
and operators of the subsequent facility, where the generators are located will know when the
sale took place and how the generators were operated when located at their respective facilities.
EPA will rely on submissions by the facilities' designated representatives and, as appropriate, on
audits to ensure that reporting obligations are met. While the commenter claims, without support
or specific examples, that these circumstances would result in a "recordkeeping nightmare," EPA
does not agree with the commenter's claim and believes that the reporting requirement is clear.
Commenter Name: Kimberly S. Lagomarsino
Commenter Affiliation: Mississippi Lime
Document Control Number: EPA-HQ-OAR-2008-0508-1568
Comment Excerpt Number: 3
Comment: Mississippi Lime Company agrees with EPA's proposal for facilities to NOT report
emissions from portable equipment or generating units designated as emergency generators in a
55
-------
permit issued by a state or local air pollution control agency, as contained in Section V.C. 1 of the
Preamble. Such emissions compose a tiny fraction of overall facility GHG emissions.
Response: EPA appreciates the comment, and has maintained the exclusion of emergency
generators and portable equipment, and has excluded other emergency equipment from
reporting. EPA has also revised the rule language to remove the prerequisite for a state or local
permit. Please refer to the full definitions of portable equipment, emergency generators, and
emergency equipment in §98.6.
Commenter Name: Sarah B. King
Commenter Affiliation: DuPont Company
Document Control Number: EPA-HQ-OAR-2008-0508-0604.1
Comment Excerpt Number: 24
Comment: DuPont agrees with EPA that the reporting of GHG emissions from portable
equipment and emergency generators is not necessary. This is supported by their infrequent use
and resulting relatively small contribution to the total greenhouse gas inventory. Further,
DuPont believes that coverage by a permit should not be a requirement for exclusion, but that the
definitions of "Emergency generator" and "Portable equipment" in §98.6 are sufficient to
delineate the excluded units
Response: EPA has maintained the exclusion of emergency generators, and has excluded other
emergency equipment from reporting. EPA has also revised the rule language to remove the
prerequisite for a state or local permit. Please refer to the full definitions of emergency generator
and emergency equipment in §98.6. Portable equipment, as defined in §98.6, is also exempt
from reporting.
Commenter Name: Lauren E. Freeman
Commenter Affiliation: Hunton & Williams LLP
Document Control Number: EPA-HQ-OAR-2008-0508-0493.1
Comment Excerpt Number: 22
Comment: EPA solicits comment on whether an emergency generator should be exempt only if
it is designated as such in a permit. 74 Fed. Reg. at 16,480. Because some of these generators
are too small to require a permit, or to be covered in existing permits, a permit should not be
required for the exemption under this rule. UARG suggests that EPA exempt a generator under
this rule if (1) it meets the definition of "emergency generator" in Subpart A of the rule, or (2)
the generator is otherwise identified as an emergency generator in a permit.
Response: EPA has maintained the exclusion of emergency generators, and has excluded other
emergency equipment from reporting. EPA has also revised the rule language to remove the
prerequisite for a state or local permit. Please refer to the full definitions of emergency generator
and emergency equipment in §98.6.
56
-------
Commenter Name: Patrick J. Nugent
Commenter Affiliation: Texas Pipeline Association (TPA)
Document Control Number: EPA-HQ-OAR-2008-0508-0460.1
Comment Excerpt Number: 21
Comment: TPA supports proposed §98.30(b), which would exclude portable equipment and
generating units designated as emergency generators in state or local permits from the rule's
coverage.
Response: EPA appreciates the commenter's support. EPA has maintained the exclusion of
emergency generators, and has excluded other emergency equipment from reporting. EPA has
also revised the rule language to remove the prerequisite for a state or local permit. Please refer
to the full definitions of emergency generator and emergency equipment in §98.6.
Commenter Name: J. P. Blackford
Commenter Affiliation: American Public Power Association (APPA)
Document Control Number: EPA-HQ-OAR-2008-0508-0661.1
Comment Excerpt Number: 21
Comment: EPA requested comments on its proposal "to not require reporting of emissions from
portable equipment or generating units designated as emergency generators in a permit issued by
a state or local air pollution control agency. [The EPA] requests] comment on whether or not a
permit should be required for these emergency generators." APPA believes that such a permit
should not be required to exempt these emergency generators from reporting. Many emergency
generators are too small to require a state permit. This would be overly burdensome to affected
facilities and the permitting authority. In addition, by the very nature of the generator being used
solely for "emergencies," the emissions from those generators are minimal compared to the rest
of the electric utility sector. In the event of an emergency, the most important consideration for
the electric utility is providing power for our customers; asking the utility to maintain records to
allow the calculation of GHG emissions from those emergency generators may impede the main
goal of restoring power as quickly as possible to our customers.
Response: EPA has maintained the exclusion of emergency generators, and has excluded other
emergency equipment from reporting. EPA has also revised the rule language to remove the
prerequisite for a state or local permit. Please refer to the full definitions of emergency generator
and emergency equipment in §98.6.
Commenter Name: Lauren E. Freeman
Commenter Affiliation: Hunton & Williams LLP
Document Control Number: EPA-HQ-OAR-2008-0508-0493.1
Comment Excerpt Number: 21
Comment: Although EGU is defined in proposed §98.6 as "any unit that combusts solid, liquid,
or gaseous fuel and is physically connected to a generator to produce electricity," Subpart D
57
-------
explicitly excludes "portable equipment" or generating units designated as "emergency
generators" in a state or local permit. Proposed §98.40(b). As a result, the existence of an
emergency generator would not itself be enough to subject a unit to Subpart D. EPA should
make clear in the final rule that this exemption for emergency generators also means that Subpart
D does not include a "methodology" that would otherwise subject such units to reporting.
Response: The direction of the comment is unclear, but EPA has clarified the applicability
under Subpart D to apply only to Acid Rain Program units and other units already reporting CO2
emissions to EPA under 40 CFR Part 75.
Commenter Name: Michael Carlson
Commenter Affiliation: MEC Environmental Consulting
Document Control Number: EPA-HQ-OAR-2008-0508-0615
Comment Excerpt Number: 21
Comment: We urge the agency to include an exemption under proposed Subpart C for units
used solely for comfort heating. Such an exemption would be consistent with other reporting
requirements under the agency's air programs.
Response: See the Preamble and separate comment response document volume for the response
on de minimis reporting for small emission points.
Because of the need for comprehensive, national greenhouse gas emissions data, the final rule
provides only limited exclusions from the reporting requirements. In light of this need for
comprehensive data, EPA has instead taken the approach of limiting the exclusions but allowing
reporting methods that provide data of a sufficient level of quality and consistency for the
purposes of this rule but that reduce the reporting burden on reporters. In §98.30, EPA has
excluded from reporting, for example, emergency generators and other emergency equipment,
but has not adopted an exclusion for "comfort heating." The commenter fails to define what is
meant by "comfort heating," much less explained how the suggested exclusion would be
consistent with reporting requirements in other programs. In any event, the commenter's
category of units used solely for comfort heating presumably would include sources providing
only heating for individuals, whether in an industrial, commercial, institutional, or residential
setting. EPA notes that the category of stationary fuel combustion sources already excludes
residential sources. With regard to "comfort heating" in industrial, commercial, and institutional
facilities, sources providing such heating will likely be routinely used and will be of widely
varying sizes depending on the size of the facility involved, and so the GHG emissions from
these units cannot be assumed to be, and treated as, insignificant. For the reasons discussed
above, this category of sources is not excluded from reporting.
58
-------
Commenter Name: Marcelle Shoop
Commenter Affiliation: Rio Tinto Services, Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-0636.1
Comment Excerpt Number: 43
Comment: EPA requests comment on whether or not a permit should be required for
emergency generators as a condition for them to be excluded from emission reporting
requirements. (74 Fed. Reg. at 16480) If emergency generators are truly used for emergency
purposes, their emissions should in most cases be insignificant and should not be subject to the
GHG emissions reporting requirements.
Response: EPA has maintained the exclusion of emergency generators, and has excluded other
emergency equipment from reporting. EPA has also revised the rule language to remove the
prerequisite for a state or local permit. Please refer to the full definitions of emergency generator
and emergency equipment in §98.6.
Commenter Name: Benjamin Brandes
Commenter Affiliation: National Mining Association (NMA)
Document Control Number: EPA-HQ-OAR-2008-0508-0466.1
Comment Excerpt Number: 21
Comment: EPA does not provided definitions in the proposed reporting rule for "combustion
source" or "combustion unit." NMA requests that EPA provide definitions for these terms, or
alternatively revise the regulation to clarify that GHG emissions from a combustion source or a
combustion unit are those that are emitted from a stack serving the unit. NMA believes that
EPA's intent is to require emissions reporting from non-fugitive stationary combustion sources,
and therefore requests that EPA make its intentions clear in a final rule.
Response: In response to the comments, EPA does not believe that any additional language is
needed to address the differences between the terms "combustion source," "combustion unit,"
and "device," as they are used in Subpart C. As stated in §98.30 of the final rule, "Stationary
fuel combustion sources are devices that combust solid, liquid, or gaseous fuel, generally for the
purposes of producing electricity, generating steam, or providing useful heat or energy for
industrial, commercial, or institutional use, or reducing the volume of waste by removing
combustible matter." The use of the word "device" is not limited in any way by the definition of
the source category, general stationary fuel combustion. "Source" refers to those devices that do
meet the provisions of the definition of the source category, as presented in §98.30. "Unit"
generally describes a device that could be subject to the reporting requirements (were it to meet
the specifications listed in §98.30). EPA believes that as clarified by these explanations,
revisions to the rule are unnecessary.
59
-------
Commenter Name: Lorraine Krupa Gershman
Commenter Affiliation: American Chemistry Council (ACC)
Document Control Number: EPA-HQ-OAR-2008-0508-0423.2
Comment Excerpt Number: 41
Comment: In §98.30, EPA should also exclude flares, thermal oxidizers, and other air pollution
control devices from the definition of stationary combustion sources requiring calculation and
reporting of greenhouse gas emissions. These units typically have low emissions, would not
have measured flow rates, and do not make a substantial impact on the total greenhouse gas
inventory. Any requirement to include these sources would put an unnecessary costly burden on
facilities to add flow measurement devices to the feed. For devices such as flares, which may
have a widely variable flow rate, there are additional challenges to finding an appropriate flow
measurement device capable of covering the range of flows encountered. EPA should clarify
that flare emissions should only be included in the calculations of Subpart C of the rule if another
subpart of the rule references 3flares' or 3emission control' equipment as a greenhouse gas
emission source requiring calculation and reporting of emissions.
Response: EPA has expanded the list of exempted source categories in §98.30(b) to include
portable equipment, emergency generators, other emergency equipment, irrigation well devices,
and flares (unless another subpart requires flare emissions to be reported). EPA has also revised
the Preamble and §98.33 to deal with certain unconventional combustion processes and types of
fuel. It is EPA's intent that sources allowed to use the Tier 1 and 2 methods, which include
smaller combustion devices and should be inclusive of control devices such as thermal oxidizers,
will only be required to report emissions from the combustion of fuels for which emission factors
are provided. In the Preamble, EPA has explained that "EPA believes that the reporting
requirements for Tier 1 and Tier 2 would only require the reporting of GHG emissions from
supplementary traditional fossil fuels from devices such as thermal oxidizers, pollution control
devices, fume incinerators, burnout furnaces, and other such equipment." EPA believes that
these provisions satisfy the intent of Part 98, to collect accurate and consistent GHG emissions
data that can be used to inform future decisions.
Commenter Name: Keith A. Nagel
Commenter Affiliation: ArcelorMittal USA and Severstal North America
Document Control Number: EPA-HQ-OAR-2008-0508-0496.1
Comment Excerpt Number: 31
Comment: EPA has requested comment on §98.30(b)'s proposed exclusion of "emergency
generators in a permit issued by a state or local air pollution control agency" from regulation
under Subpart C. While we agree with the exemption of emergency generators, we see no reason
why permitting of these small, rarely used sources is necessary. Requiring permitting would
only increase the permitting burden on states and facilities with no corresponding benefit.
Instead, EPA can rely on the Proposed Rule's definition of "emergency generator" as an
appropriate way to limit operation and testing of (and thus emissions from) these emergency
generation units.
60
-------
Response: EPA has maintained the exclusion of emergency generators, and has excluded other
emergency equipment from reporting. EPA has also revised the rule language to remove the
prerequisite for a state or local permit. Please refer to the full definitions of emergency generator
and emergency equipment in §98.6.
Commenter Name: Jeff A. Myrom
Commenter Affiliation: MidAmerican Energy Holdings Company
Document Control Number: EPA-HQ-OAR-2008-0508-0581.1
Comment Excerpt Number: 28
Comment: MidAmerican agrees that portable and emergency generating equipment is not a
significant source of emissions and emissions from portable and emergency generators should
not be included in the reporting requirements, nor should a permit for greenhouse gas emissions
be required for emergency generators.
Response: EPA has maintained the exclusion of emergency generators, and has excluded other
emergency equipment from reporting. EPA has also revised the rule language to remove the
prerequisite for a state or local permit. Please refer to the full definitions of emergency generator
and emergency equipment in §98.6.
Commenter Name: Leslie Bellas
Commenter Affiliation: National Lime Association (NLA)
Document Control Number: EPA-HQ-OAR-2008-0508-0520.1
Comment Excerpt Number: 26
Comment: 40 C.F.R. §98.33 and Table C-l require sources to include biomass fuel emissions
in the emissions calculation for stationary fuel combustion sources. NLA believes that biomass
should be excluded from the emissions calculation because biomass offsets carbon emissions
from fossil fuel combustion, biomass is considered carbon neutral, see
http://www.eia.doe.gov/oiaf/1605/coefficients.html, and biomass emissions are not included in
determining whether a source meets the emissions threshold. NLA proposes that 40 C.F.R
§98.33 be revised to exclude biomass (which does not encompass municipal solid waste)
emissions calculation for stationary fuel combustion sources.
Response: See the response to comment EPA-HQ-OAR-2008-0508-0690.1 excerpt 1
corresponding to Section II. of the Preamble, and the response to comment EPA-HQ-OAR-2008-
0508-0631.1 excerpt 71 corresponding to Subpart C for additional explanation of the reporting of
biogenic CO2 emissions.
EPA intends that biogenic CO2 emissions should be reported; although EPA has decided to track
biogenic emissions separately, they still must be included in the total CO2 emissions reported.
However, EPA notes (and believes that it has made clear in §98.2) that CO2 emissions from
biogenic fuels do not count toward the 25,000 metric ton threshold for reporting for stationary
combustion units, although CH4 and N2O emissions from biogenic fuels must be considered.
Including reporting of biogenic CO2 at facilities that are already reporting for stationary
61
-------
combustion provides EPA with information on the use of biofuels as they relate to reductions of
fossil CO2 emissions over time. This reporting requirement also provides additional data for
verification. Reporters not using CEMS are required only to report on emissions of biomass
fuels for which default emission factors are provided, greatly reducing the burden associated
with this data element.
Commenter Name: Linda Farrington
Commenter Affiliation: Eli Lilly and Company (Lilly)
Document Control Number: EPA-HQ-OAR-2008-0508-0680.1
Comment Excerpt Number: 24
Comment: Lilly believes the applicability of Subpart C should not include hazardous waste
incinerators or thermal oxidizers used as air pollution control devices. If the EPA receives
comments to the contrary and insists on including these types of units, the rule should only
require emission calculations for C02 and not for CH4 and N20. EPA states that, "Typically,
nearly 100 percent of the fuel carbon is oxidized to CO2. The CH4 and N2O emissions from
stationary combustion are much smaller and indirectly related to the carbon and nitrogen
contents of the fuel. In the U.S., CO2 emissions represent over 99 percent of the total CO2-
equivalent (C02e) GHG emissions from all commercial, industrial, and electricity generation
stationary combustion sources. CH4 and N2O emissions together represent less than one percent
of the total C02e emissions from the same sources (U.S. EPA, 2008 - Inventory of U.S.
Greenhouse Gases and Sinks)."
Response: While the commenter has not provided a reason for an exclusion of hazardous waste
incinerators, EPA has revised the Preamble and §98.33 to deal with certain unconventional
combustion processes and types of fuel. It is EPA's intent that sources allowed to use the Tier 1
and 2 methods, which include smaller combustion devices and should be inclusive of control
devices such as thermal oxidizers, will only be required to report emissions from the combustion
of fuels for which emission factors are provided. In the Preamble, EPA has explained that "EPA
believes that the reporting requirements for Tier 1 and Tier 2 would only require the reporting of
GHG emissions from supplementary traditional fossil fuels from devices such as thermal
oxidizers, pollution control devices, fume incinerators, burnout furnaces, and other such
equipment."
EPA notes that stationary combustion units that combust hazardous waste would report only the
emissions from combustion of any fuels covered by Subpart C that are co-fired with hazardous
wastes, not the hazardous wastes themselves.
See the response to comment EPA-HQ-OAR-2008-0508-0561.1 excerpt 2 for information on the
reporting requirements for CH4 and N2O.
62
-------
Commenter Name: Reed B. Hitchcock
Commenter Affiliation: Asphalt Roofing Manufacturers Association (ARMA)
Document Control Number: EPA-HQ-OAR-2008-0508-0794.1
Comment Excerpt Number: 4
Comment: For most stationary fuel combustion sources, EPA's calculation methodologies for
calculating carbon dioxide emissions wisely focus only on emissions related to the fuel
combusted. Section 98.33of the GHG Reporting Proposal makes clear that the Tier 1 and Tier 2
calculation methodologies use fuel emission factors to estimate carbon dioxide emissions. Tier 3
uses a calculation based on annual fuel use and measured carbon content of that fuel. ARMA
agrees with this common-sense position. Yet in the preamble, EPA at times refers to carbon
dioxide emissions from stationary fuel combustion sources, without noting that the emissions
that must be reported are confined to those related to combustion of the fuel. See, for example,
p. 16480, col. 3. This failure in certain places to point out that the carbon dioxide emissions that
must be reported are limited to those related to fuel use could cause confusion for the regulated
community. For example, many facilities use thermal oxidizers as an air pollution control
device. While it is relatively straightforward to calculate carbon dioxide emissions from the fuel
combusted in these thermal oxidizers, it would be difficult to measure emissions from the
oxidation of volatile organic compounds in the gas exhaust stream. Thus, EPA should clarify in
the preamble to the final rule that for units such as thermal oxidizers the facility should calculate
and report only carbon dioxide emissions that are fuel-related.
Response: See the General Stationary Combustion source category Preamble section, as well as
the separate comment response document volume, for the response on the definition of the
source category.
EPA acknowledges the concerns of the commenter and has revised the Preamble and §98.33 to
deal with certain unconventional combustion processes and types of fuel. It is EPA's intent that
sources allowed to use the Tier 1 and 2 methods, which include smaller combustion devices and
should be inclusive of control devices such as thermal oxidizers, will only be required to report
emissions from the combustion of fuels for which emission factors are provided. In the
Preamble, EPA has explained that "EPA believes that the reporting requirements for Tier 1 and
Tier 2 would only require the reporting of GHG emissions from supplementary traditional fossil
fuels from devices such as thermal oxidizers, pollution control devices, fume incinerators,
burnout furnaces, and other such equipment."
Commenter Name: Filipa Rio
Commenter Affiliation: Alliance of Automobile Manufacturers (Alliance)
Document Control Number: EPA-HQ-OAR-2008-0508-0630.1
Comment Excerpt Number: 21
Comment: EPA is proposing to exclude reporting of portable equipment and generating units
designated as emergency generators in a permit issued by a state or local air pollution control
agency. While the premise of excluding the particular emergency generator sources also is
appropriate, we are concerned that many of these units would still need to be included because
they are not always addressed by air permits. Many state and local agencies provide exemptions
63
-------
from the requirement to obtain a permit for these types of units. Consequently, the proposed
reporting exclusion would not be available as the units may not be identified in a permit. The
Alliance proposes the emergency generator units as well as other pieces of equipment such as
emergency air compressors and fire pumps be excluded regardless of their permitted status.
Response: EPA has maintained the exclusion of emergency generators, and has excluded other
emergency equipment from reporting. EPA has also revised the rule language to remove the
prerequisite for a state or local permit. Please refer to the full definitions of emergency generator
and emergency equipment in §98.6.
Commenter Name: Lorraine Krupa Gershman
Commenter Affiliation: American Chemistry Council (ACC)
Document Control Number: EPA-HQ-OAR-2008-0508-0423.2
Comment Excerpt Number: 44
Comment: EPA has requested comment on whether a permit should be required for emergency
generators excluded from greenhouse gas reporting requirements in §98.3(b). ACC agrees with
EPA that the reporting of GHG emissions from emergency generators is not necessary. This is
supported by their infrequent use and small contribution to the total greenhouse gas inventory.
However, in §98.30(b), ACC does not believe that designation as an emergency generator in a
permit should be necessary to exclude them from reporting. Some emergency generators might
not be designated as Emergency' in their air permit even though they are for emergency use.
Further, some may not be permitted at all. How the emissions from these generators are
authorized will vary from state to state, depending on the details of state programs. For example,
Indiana does not permit emergency generators at all, but rather considers them to be de minimis.
Texas might cover them under a PBR (Permit by Rule). EPA should allow additional
alternatives for omitting reporting for an emergency generator other than description in an air
permit, such as hours of use and type of use. The emissions from emergency generators are very
small compared to other stationary fuel combustion sources, and are insignificant compared to
the inventory of greenhouse gases; therefore, discounting these emissions will not have a
significant impact on the usefulness of the greenhouse gas inventory.
Response: EPA has maintained the exclusion of emergency generators, and has excluded other
emergency equipment from reporting. EPA has also revised the rule language to remove the
prerequisite for a state or local permit. Please refer to the full definitions of emergency generator
and emergency equipment in §98.6.
Commenter Name: Keith Adams
Commenter Affiliation: Air Products and Chemicals, Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-1142.1
Comment Excerpt Number: 19
Comment: The proposed rule appropriately excludes minor combustion sources from the
definition of the Stationary Fuel Combustion source category, in particular process safety flares.
Air Products supports this effort to minimize the burden on regulated facilities, as these units
64
-------
typically have very low emissions, typically do not have measured flow rates, and do not make a
substantial impact on the total greenhouse gas inventory. Flares typically must operate over a
widely variable flow rate and it is often very challenging to finding an appropriate flow
measurement device capable of covering the range of flows encountered. Any requirement to
include these sources would put an unnecessary costly burden on facilities to add flow
measurement devices to the feed. As further evidence that these devices should be excluded,
thermal oxidizers and air pollution control devices are excluded from greenhouse gas reporting
requirements in the European Union. Where flaring operations are a routine operating control of
a facility, such as in refineries, EPA has explicitly included emission estimation and reporting
requirements. Air Products Comment: Clarify that flare emissions should only be included in
the calculations of Subpart C of the rule if another subpart of the rule explicitly requires such
emission calculation and reporting. Flare emissions should be otherwise excluded categorically
or as a de mini mis source.
Response: EPA has revised the language of the final rule to expand the list of exempted source
categories to include flares as defined in §98.6, except where another subpart of the rule requires
flare emissions to be reported (see §98.30(b)). It is EPA's intent that sources allowed to use the
Tier 1 and 2 methods, which include smaller combustion devices and should be inclusive of
control devices such as thermal oxidizers, will only be required to report emissions from the
combustion of fuels for which emission factors are provided. In the Preamble, EPA has
explained that "EPA believes that the reporting requirements for Tier 1 and Tier 2 would only
require the reporting of GHG emissions from supplementary traditional fossil fuels from devices
such as thermal oxidizers, pollution control devices, fume incinerators, burnout furnaces, and
other such equipment."
Commenter Name: Linda Farrington
Commenter Affiliation: Eli Lilly and Company (Lilly)
Document Control Number: EPA-HQ-OAR-2008-0508-0680.1
Comment Excerpt Number: 19
Comment: The language in §98.30(a) clearly indicates that "incinerators" are to be included in
the general stationary fuel combustion source category. However, the EPA does not provide a
definition of "incinerators," nor does it discuss the various types of incineration processes and
their relative contribution to the nation's GHG emissions. Lilly believes further consideration is
warranted for two types of incinerators, thermal oxidizers used for emissions control and
incinerators used to destroy hazardous solid and liquid waste, a. Thermal oxidizers and fume
incinerators are acceptable control methods for reducing emissions of VOCs and hazardous air
pollutants (HAPs) and are often required in order to meet Part 60, 61, or 63 emission standards.
These units would typically have low GHG emissions that result from the combustion of process
VOC/HAP emissions and the combustion of supplemental fossil fuels necessary to maintain
temperature in the incinerator. For instance, the CO2 emissions from process vapor destroyed in
a Regenerative Thermal Oxidizer at one of our sites was estimated to be 1% of the CO2
emissions from the fuel used to maintain the RTO's temperature. Additionally, these estimated
CO2 emissions are less than 0.05% of the estimated direct CO2 emissions from the site.
Estimating GHG emissions from the combustion of supplemental fossil fuels, such as natural
gas, is very straightforward since emission factors are readily available and flow measurement
devices are usually present. However, the estimation of GHG emissions from the combustion of
65
-------
process VOC/HAP emissions is more problematic. As proposed, the mandatory reporting rule
would require facilities with thermal oxidizers or fume incinerators to perform daily sampling to
determine the carbon content of the process gas (Tier 3) or install C02 CEMS (Tier 4). In
addition, facilities would also have to conduct stack tests to determine source specific emission
factors for CH4 and N20. Lilly believes this to be overly burdensome, given the relatively low
GHG emissions expected from these air pollution control devices, b. Hazardous waste
incinerators are not included in the current European Union Emissions Trading Scheme and Lilly
suggests that they should also be excluded from the proposed mandatory GHG emission
reporting rule. [Footnote: EU Directive 2003-87, Annex 1] According to EPA's 2005 estimates,
there are fewer than 100 hazardous waste on-site incinerators in the United States. [Footnote:
National Emission Standards for Hazardous Air Pollutants: Final Standards for Hazardous Air
Pollutants for Hazardous Waste Combustors (Phase I Final Replacement Standards and Phase
II); Final Rule; October 12, 2005 Federal Register, p. 59530 [70FR59530]] The proposed GHG
emission reporting rule would essentially require each of these units to conduct monthly testing
of carbon content (Tier 3) or install C02 CEMS (Tier 4). As with thermal oxidizers, stack
testing would also be necessary for hazardous waste incinerators in order to develop source
specific emission factors for CH4 and N20. Lilly does not believe it is appropriate or cost
effective to require this degree of monitoring for such as small group of sources and we
recommend that the EPA maintain consistency with the European Union by excluding hazardous
waste incinerators from the reporting requirements in Subpart C. For the reasons described
above, Lilly recommends the following addition to the language included in §98.30: "§98.30(c)
This source category does not include air pollution control devices (including thermal oxidizers
and fume incinerators) or hazardous waste incinerators."
Response: EPA acknowledges the concerns of the commenter and has revised the Preamble and
§98.33 to deal with certain unconventional combustion processes and types of fuel. It is EPA's
intent that sources allowed to use the Tier 1 and 2 methods, which include smaller combustion
devices and should be inclusive of control devices such as thermal oxidizers, will only be
required to report emissions from the combustion of fuels for which emission factors are
provided. In the Preamble, EPA has explained that "EPA believes that the reporting
requirements for Tier 1 and Tier 2 would only require the reporting of GHG emissions from
supplementary traditional fossil fuels from devices such as thermal oxidizers, pollution control
devices, fume incinerators, burnout furnaces, and other such equipment." In addition, §98.30 has
been revised to exempt units that combust hazardous waste from reporting GHG emissions given
that CEMS are not used to quantify C02 mass emissions and that no fuel listed in Table C-l is
also combusted in the unit (in that case only emissions from the supplemental fuel must be
reported).
Commenter Name: Dan F. Hunter
Commenter Affiliation: ConocoPhillips Company
Document Control Number: EPA-HQ-OAR-2008-0508-0515.1
Comment Excerpt Number: 18
Comment: Typically, non-permitted emergency generators emit fewer emissions than permitted
generators. Therefore, the state may not require a permit for an emergency generator. All
emergency generators should also be excluded from the requirements of Subpart C.
66
-------
ConocoPhillips recommends non-permitted emergency generators also be excluded from
requirements of Subpart C.
Response: EPA has maintained the exclusion of emergency generators, and has excluded other
emergency equipment from reporting. EPA has also revised the rule language to remove the
prerequisite for a state or local permit. Please refer to the full definitions of emergency generator
and emergency equipment in §98.6.
Commenter Name: Linda Farrington
Commenter Affiliation: Eli Lilly and Company (Lilly)
Document Control Number: EPA-HQ-OAR-2008-0508-0680.1
Comment Excerpt Number: 18
Comment: The language in §98.30(b) states that the source category does not include portable
equipment or generating units designated as emergency generators in a permit issued by a state
or local air pollution control agency. The EPA should not base the applicability of Subpart C on
how a specific piece of equipment is permitted because permitting requirements for these types
of units vary significantly from state to state. Some states, including Indiana, provide permit
exemptions for emergency generators and fire pumps. [Footnote: 326 IAC 2-1.1-
3(e)(25)(B)and(C)] The GHG reporting exemption for these kinds of engines should not depend
on how the unit is permitted. A small, infrequently used engine will emit low quantities of
GHGs regardless of how the unit is permitted or described in a permit. Thus, Lilly proposes the
following revision to the language in §98.30(b): "§98.30(b) This source category does not
include portable equipment, emergency generators, or emergency pumps." If the agency
believes it is necessary to establish some regulatory parameters around engines used for
emergencies to prevent abuse of the exemption, the rules should define emergency generators or
emergency pumps, similar to how it is addressed in MACT and NSPS rules.
Response: EPA has maintained the exclusion of emergency generators, and has excluded other
emergency equipment from reporting. EPA has also revised the rule language to remove the
prerequisite for a state or local permit. Please refer to the full definitions of emergency generator
and emergency equipment in §98.6.
Commenter Name: Sarah E. Amick
Commenter Affiliation: The Rubber Manufacturers Association (RMA)
Document Control Number: EPA-HQ-OAR-2008-0508-0647.1
Comment Excerpt Number: 15
Comment: Table C-3 provides emission factors for "distillate." (74 Fed. Reg. at 16640).
However, distillate is not a defined term in the rule. In order to avoid confusion, the fuel types
listed in the emission factor tables should be consistent with the defined terms.
Response: EPA has revised the Tables in the final rule considerably, and believes that the
commenter's concern is addressed by the revision. Also, please see §98.6 for definitions on
different classes of distillates (e.g., No.l, No.2, etc.).
67
-------
Commenter Name: Kelly R. Carmichael
Commenter Affiliation: NiSource
Document Control Number: EPA-HQ-OAR-2008-0508-1080.2
Comment Excerpt Number: 15
Comment: NiSource agrees with INGAA recommendation of a de minimis threshold of 10
MMBtu/hr: The Proposed Rule does not include de minimis emission levels or exemption for
small combustion sources that are not required to have a permit issued by a state or local air
pollution control agency, and the rule notes that the burden associated with reporting small
sources is addressed. Despite this claim, we believe that an unwarranted burden will be imposed
and recommend that a de minimis or size-based exemption threshold be identified for
combustion sources. NiSource agrees with the INGAA recommendation of a 10 MMBtu/hr
exemption threshold. Many subject facilities include small combustors with minimal emissions.
For example, water heaters at a small co-located office building and other small heaters will
typically be present at subject facilities with much larger combustion sources. Typically,
emissions will be inconsequential but activity data associated with these source types will not be
readily available. Thus, an unnecessary amount of time will be spent devising fuel use or
operating time estimates that will be highly uncertain and have an insignificant affect on facility
emissions. Affected sources are faced with significant implementation challenges due to the
breadth and timing of the Proposed Rule, and the additional burden associated with reporting
trivial emissions is not warranted.
Response: See the Preamble, Section II. K., and the response to comment EPA-HQ-OAR-2008-
0508-0423.2 excerpt 40 for the response on de minimis reporting for small emission points.
See the Preamble, Section II. E., and the response to comment EPA-HQ-OAR-2008-0508-0350.1
excerpt 3 for additional explanation of the selection and form of thresholds.
EPA appreciates the commenter's concern. The final rule includes further clarification and
flexibility regarding aggregation and common pipe provisions that will reduce the burden on
sources. First, in order to reduce the burden of compliance, EPA has explicitly allowed for the
use of company records to determine fuel consumption. EPA has also removed the cumulative
250 mmBtu/hr restriction on unit aggregation, and has clarified the common pipe reporting
option. In §98.30, EPA has expanded the list of sources excluded from coverage; however, this
expansion does not include a 10 mmBtu/hr exemption threshold. These sources would be
included under Subpart C for facilities that are required to comply with Part 98. In addition,
EPA has maintained the exclusion of emergency generators, and has excluded other emergency
equipment from reporting. EPA has also revised the rule language to remove the prerequisite for
a state or local permit.
68
-------
Commenter Name: Benjamin Brandes
Commenter Affiliation: National Mining Association (NMA)
Document Control Number: EPA-HQ-OAR-2008-0508-0466.1
Comment Excerpt Number: 23
Comment: NMA agrees that portable equipment and emergency generators are properly
excluded from this rule and should not be required to be reported upon. Backup generators and
portable equipment may vary tremendously in size and are typically seldom used. Requiring
reporting on these sources would be unduly burdensome, especially on small businesses.
Furthermore, collecting data on these sources would not add significantly to EPA's
understanding of the CC^e emissions produced in the United States.
Response: EPA has maintained the exclusion of emergency generators, and has excluded other
emergency equipment from reporting. EPA has also revised the rule language to remove the
prerequisite for a state or local permit. Please refer to the full definitions of emergency generator
and emergency equipment in §98.6. Portable equipment, as defined in §98.6, is also exempt
from reporting.
Commenter Name: Sean M, O'Keefe
Commenter Affiliation: Hawaiian Commercial and Sugar Company (HC&S)
Document Control Number: EPA-HQ-OAR-2008-0508-1138.1
Comment Excerpt Number: 2
Comment: EPA proposes that emissions from portable equipment or from generating units
designated as emergency generators in a permit issued by a state or local air pollution control
agency should not be included in the general stationary fuel combustion source category or in the
electricity generation source category. Emissions from these units would therefore not be
counted when determining whether a facility emits 25,000 metric tons of CO2 equivalents
(CC^eq) per year, nor would they be included in the annual emissions to be reported to EPA.
EPA requests comment regarding whether or not a permit should be required for such emergency
generators. A&B supports EPA's proposal to exclude from reporting requirements emissions
from portable equipment and emergency generating units. Annual emissions from these units are
typically very low, due to their small size and/or very low operating hours, and tracking and
reporting these emissions would impose an unreasonable burden on reporting facilities without
significant benefit. A&B does not feel that generating units should have to be designated as
emergency generators in a permit issued by a state or local air pollution control agency in order
to be excluded from reporting. Some facilities with emergency generators may not be subject to
state or local air permitting requirements; emissions from such unpermitted generators would be
no higher than those from permitted generators and therefore should be covered by the same
reporting exclusion. A&B believes that other emergency equipment with similarly low operating
hours and correspondingly low emissions, such as backup fire pumps, should also be excluded
from reporting requirements for the same reason that emergency generators should be excluded.
Response: EPA has maintained the exclusion of emergency generators, and has excluded other
emergency equipment from reporting. EPA has also revised the rule language to remove the
69
-------
prerequisite for a state or local permit. Please refer to the full definitions of emergency generator
and emergency equipment in §98.6.
Commenter Name: See Table 10
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0635
Comment Excerpt Number: 75
Comment: EPA requested comment on whether portable combustion equipment should be
exempt. The oil and gas sector includes a number of large portable combustion units (e.g.
drilling rigs, work over rigs, construction equipment, portable flares, portable generators, etc.).
We recommend including these sources in the mandatory reporting rule.
Response: EPA refers the commenter to the definition of "portable" in §98.6, which the effect
of which is to cause only some portable equipment to be exempt. The commenter should also
note that EPA is not preparing a final version of the Oil and Natural Gas Systems (Subpart W) at
this time.
Commenter Name: Joel R. Hall
Commenter Affiliation: INEOS Fluor Americas LLC
Document Control Number: EPA-HQ-OAR-2008-0508-1525
Comment Excerpt Number: 3
Comment: Exempt other emergency units in a permit issued by a state or local air pollution
control agency. Paragraph 98.30(b) exempts "generating units designated as emergency
generators in a permit issued by a state or local air pollution control agency" from the reporting
requirements of Subpart C - General Stationary Fuel Combustion Sources. INEOS Fluor is
unable to find any substantiation for this exemption in the preamble or the Technical Support
Document. However, INEOS Fluor offers that other types of emergency units (firewater,
cooling water, etc.) exist that are designated as emergency units in a permit issued by a state or
local air pollution control agency. These units (typically a diesel driver) are likely to be of the
same general type and size as emergency generators. INEOS Fluor's experience is that these
units are generally operated for routine maintenance and during periodic performance checks.
They are rarely operated for their intended used (i.e., extended periods of time). As such,
INEOS Fluor requests that all emergency units (generators, firewater pumps, cooling water
pumps, etc.) designated as emergency units in a permit issued by a state or local air pollution
control agency be exempted from Subpart C in the final rule.
Response: EPA has maintained the exclusion of emergency generators, and has excluded other
emergency equipment from reporting. EPA has also revised the rule language to remove the
prerequisite for a state or local permit. Please refer to the full definitions of emergency generator
and emergency equipment in §98.6.
70
-------
Commenter Name: Bruce R. Byrd
Commenter Affiliation: AT & T Services, Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-0426.1
Comment Excerpt Number: 2
Comment: The emergency generator exemption should not be limited to state permits. In
exempting emergency generators from the proposed Reporting Rule's requirements, the proposed
regulations limit the exemption to engines "designated as emergency generators in a permit
issued by a state or local air pollution control agency." See Proposed 40 C.F.R. §98.30(b) and
§98.40(b), 74 Fed. Reg. at 16631, 16641. This definition of "emergency generator" is
unnecessarily limited. Many states do not have a permitting program that identifies "emergency
generators" as such. States treat emergency generators in widely disparate manners, identifying
them using permits, permits by rule, and exemptions. Many states do not have any separate
program for emergency generators at all. Thus, under EPA's proposed rule, there will be many
instances where emergency generators exist but are not explicitly identified by the permit issued
by a state. Including such generators in the reporting process simply due to administrative
differences in state licensing practices renders moot an otherwise important exemption.
Consequently, EPA should supplement this definition with an exemption that applies
consistently across the United States in order to avoid irrationally excluding emergency
generators beyond those permitted by some states as emergency generators. EPA can achieve
this result by hinging the exemption on the rule's definition of "emergency generator," and not
necessarily on state and local permits. Specifically, we propose that 40 C.F.R. §98.30(b) and
§98.40(b) should read: "This source category does not include portable equipment or emergency
generators, as defined in this rule or designated in a permit, permit by rule, or exemption issued
or otherwise authorized by a state or local air pollution control agency." This proposed change
would not hinge the applicability of the rule solely on state law approaches, while at the same
time providing EPA the flexibility to define the scope of the emergency generator exemption
through the definition of "emergency generators" as described above.
Response: EPA has maintained the exclusion of emergency generators, and has excluded other
emergency equipment from reporting. EPA has also revised the rule language to remove the
prerequisite for a state or local permit. Please refer to the full definitions of emergency generator
and emergency equipment in §98.6.
Commenter Name: Delaine W. Shane
Commenter Affiliation: Metropolitan Water District of Southern California (MWD)
Document Control Number: EPA-HQ-OAR-2008-0508-0551.1
Comment Excerpt Number: 2
Comment: We support the exclusion/exemption of emergency generators and engines from the
Rule, which is consistent with CARB's reporting rule. The definition of emergency generator in
the proposed rule needs to be comprehensive in order to exclude all such portable and stationary
equipment and incorporate related exemption language as contained in other existing reporting
rules, such as CARB's reporting rule and other CARB and SCAQMD rules for portable and
stationary emergency engines. EPA's definition needs to be broad enough to include items such
as maintenance and testing, demand response programs, and failure of a facility's internal power
distribution system.
71
-------
Response: EPA has maintained the exclusion of emergency generators, and has excluded other
emergency equipment from reporting. EPA has also revised the rule language to remove the
prerequisite for a state or local permit. Please refer to the full definitions of emergency generator
and emergency equipment in §98.6, which address demand response procedures and other testing
procedures.
Commenter Name: H. Allen Faulkner
Commenter Affiliation: Ascend Performance Materials, LLC, Decatur Plant
Document Control Number: EPA-HQ-OAR-2008-0508-1578
Comment Excerpt Number: 2
Comment: Currently, the stationary fuel combustion source category is defined as "devices that
combust solid, liquid, or gaseous fuel, generally for the purposes of producing electricity,
generating steam, or providing useful heat or energy for industrial, commercial, or institutional
use, or reducing the volume of waste by removing combustible matter. Stationary fuel
combustion sources include, but are not limited to, boiler, combustion turbines, engines,
incinerators, and process heaters." Ascend operates two unique devices for the production of
coke from coal at its Decatur Alabama Plant. To our knowledge these are the only two units like
this in the United States. The coking units burn the volatiles out of the coal and produce a high
grade "buckwheat" coke used primarily in the steel industry. Generally, half the coal input to
Image is discharged as coke and the other half is the volatiles combusted. The units do have tube
sections to recover the heat from the volatiles that are burned and generate steam as a byproduct
that is used to heat our chemical processes. We sell the coke into the spot market, and only run
the units to meet customer orders and demand. It is not practical to run the coking units solely
for steam generation. The current definition of the stationary fuel combustion source category
states that if a device is operated "... generally for the purposes of producing steam ....
or...useful heat...." it would be considered a stationary fuel combustion source. The coking units
primary purpose is to produce coke product, even though some byproduct steam is generated and
recovered. Therefore, we suggest that the word "generally" be replaced with the word "primary."
Response: See the individual source category section(s) of the Preamble and the source
category comment response document(s) for the response on the definition of the source
category.
Because of the need for comprehensive, national greenhouse gas emissions data, the final rule
provides only limited exclusions from the reporting requirements. In light of this need for
comprehensive data, EPA has instead taken the approach of limiting the exclusions but allowing
reporting methods that provide data of a sufficient level of quality and consistency for the
purposes of this rule but that reduce the reporting burden on reporters. The commenter's
suggested revision would reduce, potentially significantly, the scope of the category of
"stationary fuel combustion sources" to cover only sources whose "primary" purpose is
"producing electricity, generating steam, or providing useful heat or energy for industrial,
commercial, or institutional use, or reducing the volume of waste by removing combustible
matter", rather than sources that "generally" combust fuel (i.e., combust fuel during normal
operation) for such purposes. The commenter provides no information about what facilities,
other than its two facilities, might potentially be excluded from reporting as a result of the
72
-------
suggested change. However, it seems that the suggested change could arguably exclude facilities
that produce electricity, steam, or useful heat or energy for another purpose (e.g., to manufacture
a product) and thus could claim that latter purpose is their "primary" purpose. Not only would
the excluded group of sources potentially be extensive, but also such sources would likely
operate frequently and be of widely varying sizes. For all these reasons, the GHG emissions
from these sources cannot be assumed to be, and treated as, insignificant. For the reasons
discussed above, EPA rejects the commenter's suggested revision.
Commenter Name: Jeffrey A. Sitler
Commenter Affiliation: University of Virginia (UVA)
Document Control Number: EPA-HQ-OAR-2008-0508-0675.1
Comment Excerpt Number: 2
Comment: The University of Virginia (UVA) owns a variety of stationary combustion sources
from large steam generating boilers at our Main Heat Plant to small residential furnaces and
water heaters. Does the stationary source definition (§98.30) include small units such as
residential type water heaters, furnaces, etc? These units are not included in our Title V
emissions reporting. §98.30(a) states "stationary fuel combustion sources are devices that
combust fuel, generally for the purposes of... providing useful heat or energy..." In the request
for comments on de minimis exclusions G.2., a statement for the justification of the lack of de
minimis exclusions states that the "proposed rule would affect only larger facilities, would only
require reporting of significant emission points only..." In light of this statement, it would seem
that small residential units would not be considered since individually they are not significant
emission sources. We suggest modifying the text of §98.30(b) to include an exemption for small
residential type units. If the smaller units are not included, we would suggest that a threshold
Btu/hr limit be used, such as 200,000 Btu/hr, which would eliminate most home sized hot water
units and smaller furnaces. Virginia air regulation, 9 VAC 5-80-720 C2, considers the following
fuel combustion units as insignificant sources: 1. Those with heat input levels less than 10
MMBtu/hr rated input, using natural gas. 2. Those with heat input levels less than 1 MMBtu/hr
rated input, using distillate oil (maximum 0.5% sulfur). Alternatively, potential language for
exempting small combustion sources can be taken from an EPA survey we completed last year.
The survey was gathering information to support a revised NESHAP for boilers and process
heaters. The following text is the response to a question on whether space heaters or water
heaters were in the scope of the survey: "If a boiler serves as a space heater it is included in the
survey. If a boiler serves as a hot water heater (as defined below) it is not included. Any unit
that is not a boiler, but provides comfort heat is not included in the scope of the survey. A hot
water heater means a closed vessel with a capacity of no more than 120 U.S. gallons in which
water is heated by combustion of gaseous or liquid fuel and is withdrawn for use external to the
vessel at pressures not exceeding 160 psig, including the apparatus by which the heat is
generated and all controls and devices necessary to prevent water temperatures from exceeding
210 °F (99 °C)."
Response: See the Preamble, Section II. K., and the response to comment EPA-HQ-OAR-2008-
0508-0423.2 excerpt 40 for the response on de minimis reporting for small emission points.
See the Preamble, Section II. E., and the response to comment EPA-HQ-OAR-2008-0508-0350.1
excerpt 3 for additional explanation of the selection and form of thresholds.
73
-------
In the final rule the definition of "stationary fuel combustion source" already excludes residential
sources because it covers devices combusting fuel "generally for the purposes of producing
electricity, generating steam, or providing useful heat or energy for industrial commercial or
institutional use, or reducing the volume of waste by removing combustible matter" (§98.30(a)
(emphasis added)). Consequently, EPA believes that it is unnecessary to add a specific
exemption for "small residential type units" as suggested by the commenter. Whether the
commenters' facilities that are referred to in the comment are covered by the stationary fuel
combustion source definition depends on the specific circumstances of those facilities. Currently
lacking such information about these facilities, EPA cannot make a determination at this time
with regard to the commenter's equipment, but intends to do so in the future, upon request, when
such information is provided.
Commenter Name: Lorraine Krupa Gershman
Commenter Affiliation: American Chemistry Council (ACC)
Document Control Number: EPA-HQ-OAR-2008-0508-0423.2
Comment Excerpt Number: 42
Comment: In §98.30(a), EPA has not defined "incinerator." Without a definition, it could
apply to a very broad range of things from large waste incinerators to small thermal control
devices for vent gas streams. While it may be appropriate to include non-hazardous waste
incinerators due to the potential significant contribution to a facility's total GHG emissions, small
devices may not be flow monitored and do not add a significant contribution to the total
greenhouse gas inventory. It would be overly burdensome and unnecessarily costly to add these
flow measurement devices to these sources to facilitate emission calculations.
Response: See the General Stationary Combustion source category section of the Preamble and
the source category separate comment response document volume for the response on the
definition of the source category.
EPA acknowledges the concerns of the commenter, and has revised §98.30 of the final rule to
clarify the definition of the general stationary fuel combustion source category and provide an
expanded list of sources exempted from GHG emissions reporting under Subpart C. The
commenter should consult the revised rule which includes devices that combust fuel for the
purpose of "reducing the volume of waste by removing combustible manner" in the definition of
the stationary combustion source category, and exempts flares (except where required to report
by another subpart) and devices that incinerate hazardous waste (with certain conditions). EPA
has revised the Preamble and §98.33 to deal with certain unconventional combustion processes
and types of fuel. It is EPA's intent that sources allowed to use the Tier 1 and 2 methods, which
include smaller combustion devices and should be inclusive of control devices such as thermal
oxidizers, will only be required to report emissions from the combustion of fuels for which
emission factors are provided. In the Preamble, EPA has explained that "EPA believes that the
reporting requirements for Tier 1 and Tier 2 would only require the reporting of GHG emissions
from supplementary traditional fossil fuels from devices such as thermal oxidizers, pollution
control devices, fume incinerators, burnout furnaces, and other such equipment."
74
-------
Commenter Name: George H. Berghorn
Commenter Affiliation: Michigan Forest Products Council (MFPC)
Document Control Number: EPA-HQ-OAR-2008-0508-0721.1
Comment Excerpt Number: 2
Comment: A restrictive definition limits the use of forest biomass to meet the RFS mandate of
36 billion gallons by 2022, thus jeopardizing our ability to meet the standard. A restrictive
standard creates a market barrier for forest biomass and creates an uneven playing field relative
to other feedstocks. A broad definition of wood is necessary. A broad definition of forest
biomass that appropriately addresses sustainability is essential. Sustainability is best addressed
at the local level using established and familiar tools and processes, like state water quality best
management practices, that have proven effective over time.
Response: EPA has finalized the biomass definition in §98.6 largely as proposed, with some
additional language addressing the biogenic fractions of industrial and municipal wastes. The
EPA believes the definition of biomass is defined broadly enough to include the majority of
wood and forest biomass. In addition, addressing sustainability and certifying renewable fuels is
beyond the scope of this rule.
Commenter Name: Lorraine Krupa Gershman
Commenter Affiliation: American Chemistry Council (ACC)
Document Control Number: EPA-HQ-OAR-2008-0508-0423.2
Comment Excerpt Number: 43
Comment: It is not clear whether EPA intended for facilities to report greenhouse gas emissions
of hazardous waste burned in hazardous waste incinerators or combustors. For example, Table
C-l (74 FR 16481) does not mention hazardous waste fuels. ACC recommends that EPA
exempt hazardous waste combustion units from the rule. These hazardous waste units would be
small contributions to the total inventory and may vary widely in flow rate and composition, thus
making the calculations more difficult. Furthermore, EPA has recognized the small contribution
by exempting hazardous waste from the calculations and reporting in the landfill subpart of this
proposed rule.
Response: See the General Stationary Combustion source category section of the Preamble and
the separate source category comment response document volume for the response on the
definition of the source category.
EPA acknowledges the concerns of the commenter, and has revised §98.30 of the final rule to
clarify the definition of the general stationary fuel combustion source category and provide an
expanded list of sources exempted from GHG emissions reporting under Subpart C. The
commenter should consult the revised rule which exempts combustion of hazardous waste,
unless CEMS are used to quantify CO2 mass emissions, or any fuel listed in Table C-l is also
combusted in the unit.
75
-------
Commenter Name: Geoffrey Cullen
Commenter Affiliation: Can Manufacturers Institute (CMI)
Document Control Number: EPA-HQ-OAR-2008-0508-0703.1
Comment Excerpt Number: 2
Comment: EPA is using a very broad definition of "General Stationary Fuel Combustion
Sources." The rule defines General Stationary Fuel Combustion Sources as: "devices that
combust solid, liquid, or gaseous fuel, generally for the purposes of producing electricity,
generating steam, or providing useful heat or energy for industrial, commercial, or institutional
use, or reducing the volume of waste by removing combustible matter. Stationary fuel
combustion sources include, but are not limited to, boilers, combustion turbines, engines,
incinerators, and process heaters." CMI is concerned that the proposed definition is so broad that
it might include pollution control devices such as thermal oxidizers that combust natural gas.
CMI urges EPA to add an explicit exclusion from the definition of General Stationary Fuel
Combustion Sources for "air pollution control devices." EPA does exclude "portable equipment
or generating units designated as emergency generators in a permit issued by a state or local air
pollution control agency" from the definition of Stationary Fuel Combustion Source. CMI
supports this exclusion.
Response: EPA has revised the Preamble and §98.33 to deal with certain unconventional
combustion processes and types of fuel. It is EPA's intent that sources allowed to use the Tier 1
and 2 methods, which include smaller combustion devices and should be inclusive of control
devices such as thermal oxidizers, will only be required to report emissions from the combustion
of fuels for which emission factors are provided. In the Preamble, EPA has explained that "EPA
believes that the reporting requirements for Tier 1 and Tier 2 would only require the reporting of
GHG emissions from supplementary traditional fossil fuels from devices such as thermal
oxidizers, pollution control devices, fume incinerators, burnout furnaces, and other such
equipment."
Commenter Name: Bruce R. Byrd
Commenter Affiliation: AT & T Services, Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-0426.1
Comment Excerpt Number: 1
Comment: The definition of "emergency generator" must encompass emergency demand
response. EPA proposes to explicitly exclude certain emergency generators from the General
Stationary Fuel Combustion Source and Electricity Generation subparts. See Proposed 40 C.F.R.
§98.30(b) and §98.40(b), 74 Fed. Reg. at 16631, 16641. The currently proposed definition,
however, could be read to disqualify generators from the emergency classification if the
generator is used or could be used for the critical function of providing emergency demand
response. Importantly, while the definition initially makes it clear that emergency generators
providing a "secondary source" of electrical power during "power outages" are within the
definition, this last sentence creates ambiguity by removing from the definition generators that
respond to "power interruptions pursuant to an interruptible power service agreement." Thus, as
a result of this ambiguity, the definition arguably could be read to impose significant reporting
obligations on generators that participate in emergency demand response programs despite the
76
-------
clear statement at the outset of the definition purporting to exempt secondary sources of
electrical power in "emergency situations." In other words, it is possible that "power
interruptions pursuant to an interruptible power service agreement" could be read to include the
emergency generators that participate in emergency demand response programs that are often
our nation's last line of defense against power outages. We believe EPA must clarify the final
rule to provide that generators providing emergency power under emergency demand response
programs are properly within the "emergency generator" definition. Emergency demand
response programs are critical to our environment and the security of the nation's power grid.
Developed by companies that manage the electric grid, these programs are only used in the most
serious emergencies to prevent brownouts and blackouts due to insufficient supply of power to
the grid. Participants in an emergency demand response program have no control over the
timing of these events, they are identified by the grid managers, who direct participants to
comply. Participants in such programs do not supply power to the grid; all power is used at the
individual facility. The emergency demand response programs are only instituted in cases of
true emergencies. Following are three examples of this type of emergency demand response
program. 1. In New England, the demand response program is only implemented once ISO New
England, the Regional Transmission Organization (RTO) serving Connecticut, Maine,
Massachusetts, New Hampshire, Rhode Island, and Vermont, declares Operating Procedure 4,
Action 12. Since the demand response program was initiated in New England in 2002, there
have been three days on which ISO New England requested action in Connecticut, and on only
one of those days was action requested for all of New England. 2. The mid-Atlantic RTO, PJM,
activates its Emergency Load Response Program (ELRP) according to the procedures in the PJM
Manual 13 Emergency Operations for a PJM Declared Emergency. In the past five years, the
ELRP has only been activated five times for a total of 20 hours. 4. The Electricity Reliability
Council of Texas (ERCOT) activates its Emergency Interruptible Load Service (EILS) Program
just before the electric grid is expected to fail. The EILS is integrated into ERCOT's Electrical
Emergency Curtailment Plan and is activated during a Stage 3 emergency, where the alternative
is blackouts. The EILS Program is designed for a maximum of six dispatches per year with a
maximum of 24 hours. While participants in emergency demand response programs are
compensated whether or not their engines are called, emergency demand response programs
should not be confused with economic demand response programs or peak-shaving. Emergency
demand response programs are initiated by the transmission system operators when the threat of
power outages is likely and are critical to maintaining available power during periods of extreme
load on the electric power infrastructure. These unplanned events are out of the control of
emergency generator owners or operators. As the examples above demonstrate, emergency
generators providing such critical power are not major contributors to GHG emissions. In fact,
as part of an effective emergency demand response program, they lead to a significant decrease
in emissions. They are only used to save the grid when it is about to fail. In their absence, the
grid would fail, and the generators would have to run to provide back-up power, a clearly
exempted emergency use. And all generators on the grid would have to run, even those not
enrolled in emergency demand response programs, dramatically increasing GHG emissions.
Thus, the objectives of this reporting program are benefited by clearly exempting this category of
generators. Refusing to exempt these generators would create a strong incentive to remove them
from emergency demand response programs for two reasons. First, companies would have to
carefully monitor thousands of these units' GHG emissions to determine whether they reached
the 25,000 ton reporting threshold, even though they are rarely, if ever, used for emergency
demand response. And second, companies might have to report emissions for their entire
facilities if the emergency generator pushed them over the threshold. This might seem very
unlikely because emergency demand response events are so rare. But the rule as written does not
77
-------
exempt particular generation activities, it exempts particular generators. Thus, if a generator
participates in an emergency demand response program, all of its emissions, including emissions
generated during power outages, maintenance, or natural disasters — could count toward the
25,000 ton threshold. This is true even if a facility never actually runs its generator during an
emergency demand event. Even worse, if a natural disaster or power outage ever required
sufficient generator use to meet the threshold, the facility would have to report its emissions in
perpetuity because of the proposed rule's oncein-always-in structure. Unless the rule is clarified,
many companies will withdraw their generators from these crucial programs. To clearly achieve
the goal of exempting these critical generators from the reporting rule, EPA should remove the
current ambiguity by modifying the existing emergency generator definition as proposed in the
following text: Emergency generator means a stationary internal combustion engine that serves
solely as a secondary source of mechanical or electrical power whenever the primary energy
supply is disrupted or discontinued during power outages or natural disasters that are beyond the
control of the owner or operator of a facility. Emergency engines operate only during emergency
situations or for standard performance testing procedures as required by law or by the engine
manufacturer. The hours of operation per calendar year for such standard performance testing
shall not exceed 100 hours. An engine that serves as a back-up power source under conditions of
load shedding, peak shaving, or scheduled facility maintenance shall not be considered an
emergency engine. An engine that provides energy to a facility during periods in which the
Regional Transmission Organization or other local or regional entity responsible for maintaining
reliability of electrical operations directs the implementation of emergency demand response
procedures shall be considered an emergency generator, so long as it otherwise meets the
requirements of this definition.
Response: In the final rule, EPA has maintained the exclusion of emergency generators, has
removed for such generators the 100-hour limitation and the requirement of designation in a state
or local permit, and has excluded other emergency equipment from reporting. However, under
the rule, emergency generators are limited to generators that "serve solely as a secondary source
of mechanical or electrical power whenever the primary energy supply is disrupted or
discontinued during power outages or natural disasters that are beyond the control of the owner
or operator of a facility" (emphasis added). Such generators operate "only during emergency
situations, for training of personnel under simulated emergency conditions, as part of emergency
demand response procedures, or for standard performance testing procedures as required by law
or by the generator manufacturer" (emphasis added). Consequently, generators that serve "as a
back-up power source under conditions of load shedding, peak shaving, power interruptions
pursuant to an interruptible power service agreement, or scheduled facility maintenance" are not
emergency generators.
The commenter states, with no support or specific examples, that the exclusion of generators
used during '"power interruptions pursuant to an interruptible power service agreement' could be
read to include the emergency generators that participate in emergency demand response
programs." The commenter does not explain why this interpretation would be reasonable or
why, for example, a transmission system operator initiating emergency demand response
procedures would not expressly invoke such procedures and thereby distinguish the event from
cases of power interruptions pursuant to an interruptible power service agreement. Moreover,
the commenter does not claim that generators used for peak-shaving (e.g., power interruptions
pursuant to an interruptible power service agreement) should be treated as emergency generators,
and EPA continues to believe that they should not. Yet, the commenter's suggested language
revisions would remove the provision that generators that serve "as a back-up power source
78
-------
under conditions of. . . power interruptions pursuant to an interruptible power service
agreement" are not emergency generators. EPA rejects the commenter's suggested language as
unnecessary and confusing.
Commenter Name: Mark A. Dupuis
Commenter Affiliation: International Paper Products Corporation (IPPC)
Document Control Number: EPA-HQ-OAR-2008-0508-0445.1
Comment Excerpt Number: 1
Comment: IPPC is pleased that the United States Environmental Protection Agency's Proposed
Rule "Mandatory Reporting of Greenhouse Gases" allows for exclusion of carbon dioxide (C02)
emissions from biogenic (biomass) fuels used in General Stationary Fuel Combustion. It is
IPPC's position that the development of this rule and subsequent policies regarding its
implementation should include Paper Derived Fuel (PDF). There is adequate and available
analytical technology to ascertain the biogenic portion of PDF and it is well recognized that
paper is derived from biomass (TSD for Stationary Fuel Combustion Emissions, Section 3.3.2;
Intergovernmental Panel on Climate Change Guidelines). Manufacture of Enviro-Fuelcubes® is
the result of a tightly controlled acquisition process. Therefore, the quality and positive
combustion characteristics of Enviro-Fuelcubes® are high because PDF is manufactured from
carefully specified and selected non-recyclable secondary raw materials. The result is a fuel
having a nominal Higher Heat Value (HHV) of 10,000 BTU per pound on a consistent basis and
over 75% of that energy is biogenic in origin. The remaining (fossil) energy content of Enviro-
Fuelcubes® is due to inseparable coatings or mixtures of clean, non-recyclable, non-hazardous
polymers whose origins are identified and verified.
Response: EPA appreciates the comment but notes that CO2 emissions from biomass are
excluded from the threshold determination for Subpart C, but facilities that report due to fossil
CO2 emissions must report CO2 emissions from combustion of biomass. The rule provides for
separate accounting of biomass and fossil CO2 emissions from mixed fuels. In most cases, Tier
1 may be used to calculate biogenic emissions. When a premixed blend of biomass and fossil
fuel is combusted, the facility may determine the quantity of biomass combusted using the best
available information. Furthermore, EPA has allowed units that use CEMS to measure total CO2
emissions to determine the biogenic portion of emissions for units that combust a combination of
biomass- and fossil-derived fuels using ASTM Methods D7459-08 and D6866-06a.
Commenter Name: Gregory A. Wilkins
Commenter Affiliation: Marathon Oil Corporation
Document Control Number: EPA-HQ-OAR-2008-0508-0712.1
Comment Excerpt Number: 103
Comment: Marathon would like to receive further clarification on the issue of whether or not
building heating would be applicable under this rule. Marathon interprets that building heating
would be excluded from this rule or be allowed to be considered de minimis. The emissions
from building heating would be far less than 1% of any refinery's total emissions.
79
-------
Response: See the Preamble and separate comment response document volume for the response
on de minimis reporting for small emission points. See response to comment EPA-HQ-OAR-
2008-0508-0615 excerpt 21 and response to comment EPA-HQ-OAR-2008-0508-0675.1 excerpt
2 for an explanation of the treatment of residential facilities.
EPA has expanded the list of exempted source categories to include portable equipment,
emergency generators, other emergency equipment, irrigation well devices, and flares, but has
not excluded building heating from this rule. EPA has also removed the cumulative 250
mmBtu/hr restriction on unit aggregation and clarified common pipe metering, and believes that
the expanded availability of these options will reduce the reporting burden on facilities.
Commenter Name: Lorraine Krupa Gershman
Commenter Affiliation: American Chemistry Council (ACC)
Document Control Number: EPA-HQ-OAR-2008-0508-0423.2
Comment Excerpt Number: 45
Comment: Also in §98.30(b), the term "emergency generators" should be changed to
Emergency stationary RICE.' Many facilities use combustion units (e.g., diesel engines) as the
motive force for pumps, to ensure fire water availability and process fluid movement during
power outages. ACC recommends that EPA exclude all emergency stationary reciprocating
internal combustion engines (RICE) as the term is defined in 40 CFR 63 Subpart ZZZZ
(§63.6675). These are sources whose operation is limited to emergency situations and whose
emissions are negligible when compared to other stationary combustion sources. Exclusion of
these sources would exclude sources such as stationary RICE used to pump water in the case of
fire or flood, for example. For the reasons above, ACC recommends that EPA revise §98.30(b)
to read as follows: "(b) This source category does not include portable equipment or units that
are emergency stationary reciprocating internal combustion engines." GHGs to report - §98.32
The text of §98.32 should be revised by adding text to the end of the sentence as follows (new
language underlined): "... each stationary fuel combustion unit except as allowed by
§98.36(c)."
Response: EPA asks the commenter to please refer to the full definitions of emergency
generator and emergency equipment in §98.6, which include reciprocating internal combustion
engines (RICE), and include "... secondary sources of mechanical and electrical power ..."
Commenter Name: Sean M, O'Keefe
Commenter Affiliation: Hawaiian Commercial and Sugar Company (HC&S)
Document Control Number: EPA-HQ-OAR-2008-0508-1138.1
Comment Excerpt Number: 4
Comment: A&B also strongly supports a de minimis exemption for small stationary
combustion sources at reporting facilities, similar to reduced requirements for "insignificant
activities" allowed under state Title V permit programs. Typically, such activities may be
exempted from emissions reporting and other Title V permit requirements based upon the size or
type of equipment or based upon their emissions. For example, activities at the HC&S Puunene
80
-------
Sugar Mill classified as "insignificant" under Hawaii's Title V permit program include an
emergency diesel generator and a secondary fire pump (both classified as insignificant based
upon the type of equipment) and various small diesel or propane-fired stationary equipment all
with rated heat input capacities less than one million BTUs per hour (classified as insignificant
based upon their size and corresponding emissions). Even assuming that all of this small
equipment operated continuously at maximum capacity for 8,760 hours per year, combined
theoretical maximum emissions of carbon dioxide would amount to less than five percent of the
25,000 tons per year reporting threshold in the proposed rule; since in reality such equipment
will operate far less frequently, actual combined emissions would amount to less than one
percent of the proposed facility reporting threshold, and to an even smaller percentage of the
facility's total GHG emissions. A&B believes that the considerable effort and expense required
to annually monitor, record, and report emissions from numerous de minimis sources at a
reporting facility is unreasonable and unwarranted given the very minimal impact on the
accuracy of reported GHG emissions that exclusion of these sources would have. While we
appreciate EPA's efforts to minimize this burden through its proposal to allow emissions
aggregation from a group (or groups) of small units at a facility, this measure only reduces (but
does not eliminate) the reporting burden for these sources; it does not alleviate the need to
monitor, record, and track fuel usage for the individual units within an aggregated group, nor to
maintain associated records. A&B therefore recommends that EPA incorporate into the rule a
reporting exclusion for de minimis sources, and that EPA define "de minimis sources" as all
sources at a facility below a specified heat input capacity (e.g., one million BTU per hour)
contributing, in the aggregate, less than one percent of total facility emissions of CO2
equivalents. Facilities should not be required to monitor, record, or report GHG emissions from
any units which meet the criteria for classification as de minimis sources.
Response: See the Preamble, Section II. K., and the response to comment EPA-HQ-OAR-2008-
0508-0423.2 excerpt 40 for the response on de minimis reporting for small emission points.
EPA has expanded the list of exempted source categories to include portable equipment,
emergency generators, other emergency equipment, irrigation well devices, and flares. EPA has
also removed the cumulative 250 mmBtu/hr restriction on unit aggregation, and believes that the
expanded availability of this option will reduce the reporting burden on facilities.
Commenter Name: Curtis J. Winner
Commenter Affiliation: New Mexico Gas Company (NMGC)
Document Control Number: EPA-HQ-OAR-2008-0508-0585
Comment Excerpt Number: 2
Comment: In the preamble, EPA requests comments as to whether a permit should be required
for emergency generators. NMGC does not think a permit should be required for emergency
generators.
Response: EPA has maintained the exclusion of emergency generators, and has excluded other
emergency equipment from reporting. EPA has also revised the rule language to remove the
prerequisite for a state or local permit. Please refer to the full definitions of emergency generator
and emergency equipment in §98.6.
81
-------
Commenter Name: Robert D. Bessette
Commenter Affiliation: The Council of Industrial Boiler Owners (CIBO).
Document Control Number: EPA-HQ-OAR-2008-0508-0513.1
Comment Excerpt Number: 18
Comment: In the proposed rule, EPA proposes to exclude the reporting of only such portable
equipment and generating units designated as emergency generators that have been permitted
under the New Source Review (NSR) program. As stated here, CIBO agrees with the exclusion
of these sources from the reporting obligations, but such pieces are not always explicitly covered
by an NSR permit based on state NSR programs, which might specifically exempt such units
from the requirement to obtain a permit. Hence, based on the current language in the proposed
rule, the proposed reporting exemption could not be utilized for those units not identified in a
NSR permit. CIBO therefore recommends that EPA amend the proposed rule to exclude the
reporting of these units regardless of their permitted status.
Response: EPA has maintained the exclusion of emergency generators, and has excluded other
emergency equipment from reporting. EPA has also revised the rule language to remove the
prerequisite for a state or local permit. Please refer to the full definitions of emergency generator
and emergency equipment in §98.6.
Commenter Name: See Table 6
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0679.1
Comment Excerpt Number: 70
Comment: Emergency generator §98.6 (p. 16620): The definition of'Emergency generator'
states "the hours of operation per calendar year for performance testing shall not exceed 100
hours." API requests that the specification of hours be removed from the definition of
emergency generators. It is not reasonable to limit the number of hours. In addition, the
definition in regards to the duration of operation for performance testing should be revised to be
consistent with the existing Clear Air Act (CAA) regulations definition for emergency equipment
that state testing of units should be minimized, but there is no time limit on the use of emergency
equipment in emergency situations and for routine testing and maintenance. Refer to Stationary
Combustion Turbines MACT (§63.6175) and Stationary Reciprocating Internal Combustion
Engines MACT (§63.6675).
Response: EPA has eliminated the 100-hour limitation for emergency generators in the final
rule. Please refer to the full definition of emergency generator in §98.6.
82
-------
Commenter Name: Phillip McNeely
Commenter Affiliation: City of Phoenix, AZ
Document Control Number: EPA-HQ-OAR-2008-0508-0374.1
Comment Excerpt Number: 9
Comment: Recommend that the definition of emergency generators add "maintenance and
repairs" to 100 hour operation limit. The edit indicated below would clarify the rule and make it
consistent with the definition of emergency generators in the New Source Performance Standard
Rule in 40 CFR 60 Subparts 1111 and JJJJ and in proposed 40 CFR 63 Subpart ZZZZ. Without
this clarification, many affected facility owners would be required to either bring in portable
generators for minor maintenance procedures or submit GHG records. Recommended edit to
Subsection, 98.6 provided below. "Emergency generator means a stationary internal combustion
engine that serves solely as a secondary source of mechanical or electrical power whenever the
primary energy supply is disrupted or discontinued during power outages or natural disasters that
are beyond the control of the owner or operator of a facility. Emergency engines operate only
during emergency situations or for REPAIRS, MAINTENANCE, OR standard performance
testing procedures as required by law or by the engine manufacturer. The hours of operation per
calendar year for such REPAIRS, MAINTENANCE AND, standard performance testing shall
not exceed 100 hours".
Response: In the final rule, EPA has addressed the concern raised by the commenter by
eliminating the 100-hour limitation for emergency generators. Please refer to the full definition
of emergency generator in §98.6.
Commenter Name: Lorraine Krupa Gershman
Commenter Affiliation: American Chemistry Council (ACC)
Document Control Number: EPA-HQ-OAR-2008-0508-0423.2
Comment Excerpt Number: 32
Comment: The definition of emergency generator states that the hours of operation per calendar
year for performance testing shall not exceed 100 hours. The definition in regards to the
duration of operation for performance testing should be revised to be consistent with existing
Clear Air Act regulations definition for emergency equipment that state testing of units should be
minimized, but there is no time limit on the use of emergency equipment in emergency situations
and for routine testing and maintenance. See, for example, Stationary Combustion Turbines
NESHAP (40 CFR §63.6 175) and Stationary Reciprocating Internal Combustion Engines
NESHAP (40 CFR §63.6675). Furthermore, the definition of "emergency generator" should be
changed to "emergency stationary RICE" to reflect the various types of equipment that can be
used by facilities. ACC recommends that EPA utilize the definition in §63.6675: "Emergency
stationary RICE means any stationary RICE that operates in an emergency situation. Examples
include stationary RICE used to produce power for critical networks or equipment (including
power supplied to portions of a facility) when electric power from the local utility is interrupted,
or stationary RICE used to pump water in the case of fire or flood, etc. Emergency stationary
RICE may be operated for the purpose of maintenance checks and readiness testing, provided
that the tests are recommended by the manufacturer, the vendor, or the insurance company
associated with the engine. Required testing of such units should be minimized, but there is no
83
-------
time limit on the use of emergency stationary RICE in emergency situations and for routine
testing and maintenance. Emergency stationary RICE may also operate an additional 50 hours
per year in non-emergency situations."
Response: In the final rule, EPA has eliminated the 100-hour limitation for emergency
generators. Please refer to the full definition of emergency generator in §98.6.
Commenter Name: See Table 6
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0679.1
Comment Excerpt Number: 80
Comment: HHV: Higher Heating Value or Gross Calorific Value. The quantity of heat
produced by the complete combustion of a unit volume or weight of fuel assuming that the
produced water is completely condensed (liquid state) and the heat is recovered.
Response: EPA believes that the proposed definition of high heat value is satisfactory, and has
finalized this definition.
Commenter Name: Burl Ackerman
Commenter Affiliation: J. R. Simplot Company
Document Control Number: EPA-HQ-OAR-2008-0508-1641
Comment Excerpt Number: 12
Comment: Section 98.32 GHGs states, "You must report CO2, CH4, and N2O mass emissions
from each stationary fuel combustion unit." We recommend that a de minimis level be set for
units not requiring reporting. We recommend that units which have a nameplate capacity less
than 10 mmbtu/hr not be included in the report. To include every combustion source regardless
of size, is an unreasonable reporting burden.
Response: See the Preamble, Section II. K., and the response to comment EPA-HQ-OAR-2008-
0508-0423.2 excerpt 40 for the response on de minimis reporting for small emission points.
See the Preamble, Section II. E., and response to comment EPA-HQ-OAR-2008-0508-0350.1
excerpt 3 for additional explanation of the selection and form of thresholds.
EPA appreciates the commenter's concern. The final rule includes further clarification and
flexibility regarding aggregation and common pipe provisions that will reduce the burden on
sources. First, in order to reduce the burden of compliance, EPA has explicitly allowed for the
use of company records to determine fuel consumption. EPA has also removed the cumulative
250 mmBtu/hr restriction on unit aggregation, and has clarified the common pipe reporting
option. In §98.30, EPA has expanded the list of sources excluded from coverage; however, this
expansion does not include a 10 mmBtu/hr exemption threshold, and such activities would be
included under Subpart C for facilities that are required to comply with Part 98.
84
-------
Commenter Name: Steven J. Rowlan
Commenter Affiliation: Nucor Corporation (Nucor)
Document Control Number: EPA-HQ-OAR-2008-0508-0605.1
Comment Excerpt Number: 41
Comment: In 98.30, an additional exclusion should be created at (c) for any unit, the
methodology for which is set forth in Subparts D through PP to avoid double counting. For
example, an EAF is listed in Subpart Q, but also combusts natural gas and/or other fuels, and
hence would also appear to be subject to calculation under Subpart C.
Response: EPA intends that the stationary combustion source category include any device that
meets the definition included in §98.30 for which emissions are not accounted for in the report
through a separate subpart of the rule. Per the requirements in 40 CFR Part 98, Subpart A,
facilities have to report GHG emissions from all source categories located at their facility,
including stationary combustion and process emissions. EPA does not intend that emissions be
double reported, and has revised the various subparts of the final rule to clarify the intent of the
stationary combustion source category.
Commenter Name: Steven D. Meyers
Commenter Affiliation: General Electric Company (GE)
Document Control Number: EPA-HQ-OAR-2008-0508-0532.1
Comment Excerpt Number: 7
Comment: As an example of the confusing nature of the rule, the following question has been
raised within GE concerning the applicability of the stationary source combustion category: Are
GHG emissions from all fuels combusted by stationary combustion units including boilers, space
heaters, dryers, furnaces, etc. included in the stationary source category?
Response: Subpart C excludes portable equipment, emergency generators and emergency
equipment as defined in §98.6, irrigation pumps at agricultural operations, and flares, unless
otherwise required by provisions of another subpart of Part 98 to use methodologies in this
subpart. Other devices are included subject to the requirements of specific Tiers. EPA has
revised the rule to clarify the applicability of the general stationary combustion source category.
For units that have a maximum rated heat input capacity less than 250 mmBtu/hr and are not
required to use Tier 4, only emissions from those fuels for which emission factors are provided
need to be reported. Emissions from fuels for which emission factors are not provided only need
to be reported if CEMS are used or the fuel provides ten percent or more of the annual heat input
to a unit with a maximum rated heat input capacity greater than 250 mmBtu/hr or a group of
units served by a common pipe. CH4 and N2O emissions only need to be reported for units that
are required to report CO2 emissions under Subpart C and for fuels for which default emission
factors are provided.
The final rule includes further clarification and flexibility regarding aggregation and common
pipe provisions that may also reduce the burden on sources. First, in order to reduce the burden
of compliance, EPA has explicitly allowed for the use of company records to determine fuel
85
-------
consumption. EPA has also removed the cumulative 250 mmBtu/hr restriction on unit
aggregation, and has clarified the common pipe reporting option.
86
-------
2. REPORTING THRESHOLD
Commenter Name: See Table 5
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0480.1
Comment Excerpt Number: 42
Comment: The Proposed Rule does not include de minimis emission levels or exemption for
small combustion sources that are not required to have a permit issued by a state or local air
pollution control agency, and the rule notes that the burden associated with reporting small
sources is addressed. Despite this claim, INGAA believes that unwarranted burden will be
imposed and recommends that a de minimis or size-based exemption threshold be identified for
combustion sources. INGAA recommends a 10 MMBtu/hr exemption threshold. Many subject
facilities include small combustors with minimal emissions. For example, water heaters at a
small co-located office building and other small heaters will typically be present at subject
facilities with much larger combustion sources. Typically, emissions will be inconsequential but
activity data associated with these source types will not be readily available. Thus, an
unnecessary amount of time will be spent devising fuel use or operating time estimates that will
be highly uncertain and have an insignificant affect on facility emissions. Affected sources are
faced with significant implementation challenges due to the breadth and timing of the Proposed
Rule, and the additional burden associated with reporting trivial emissions is not warranted.
INGAA recommends that a 10 MMbtu/hour exemption threshold be included in the rule for
combustion sources.
Response: See the Preamble, Section II. K., and the response to comment EPA-HQ-OAR-2008-
0508-0423.2 excerpt 40 for the response on de minimis reporting for small emission points.
EPA appreciates the commenter's concern. The final rule includes further clarification and
flexibility regarding aggregation and common pipe provisions that will reduce the burden on
sources. First, in order to reduce the burden of compliance, EPA has explicitly allowed for the
use of company records to determine fuel consumption. EPA has also removed the cumulative
250 mmBtu/hr restriction on unit aggregation, and has clarified the common pipe reporting
option. In §98.30, EPA has expanded the list of sources excluded from coverage; however, this
expansion does not include a 10 mmBtu/hr exemption threshold. These sources would be
included under Subpart C for facilities that are required to comply with Part 98.
Commenter Name: Matthew Frank
Commenter Affiliation: Wisconsin Department of Natural Resources
Document Control Number: EPA-HQ-OAR-2008-0508-1062.1
Comment Excerpt Number: 23
Comment: Reporting requirements clearly require submittal to EPA. It is not clear how soon
State agencies would have access to the reports. Reports should be provided to the States at the
same time as they are submitted to EPA.
Response: See the Preamble, Section II. O., "General Requirements of the Rule — Summary of
Comments and Responses on the Role of States and Relationship of this Rule to Other
87
-------
Programs" and separate comment response document volume for the response on the relationship
of this rule to other programs, and on the collection, management, and dissemination of GHG
emissions data.
Commenter Name: Juanita M. Bursley
Commenter Affiliation: GrafTech International Holdings Inc. Company (GrafTech)
Document Control Number: EPA-HQ-OAR-2008-0508-0686.1
Comment Excerpt Number: 18
Comment: GrafTech agrees with the rationale used and conclusions reached by EPA to select
the 25,000 metric tons/year C02e as the appropriate reporting threshold for stationary fuel
combustion equipment.
Response: See the Preamble and separate comment response document volume for the response
on selection of the threshold.
EPA appreciates this comment and intends to finalize the 25,000 metric tons C02e per year
reporting threshold as proposed.
Commenter Name: David R. Case
Commenter Affiliation: Environmental Technology Council (ETC)
Document Control Number: EPA-HQ-OAR-2008-0508-0664.1
Comment Excerpt Number: 3
Comment: We do not believe that the 25,000 metric ton threshold for general stationary fuel
combustion sources is appropriate for hazardous waste incinerators. We urge EPA to adopt a
100,000 metric ton threshold for these facilities. Since the 25,000 ton threshold is based on gross
emissions, and does not consider net emissions resulting from destruction of CC^e, at least a
100,000 ton threshold would provide some indirect consideration of this unique characteristic of
hazardous waste incinerators. In addition, the hazardous waste sector is at most a very small
contributor to overall CC^e emissions from industrial sources. Even though individual
incinerators may exceed the 25,000 ton threshold on a gross basis, the number of hazardous
waste incinerators is sufficiently small to make emissions from these sources negligible.
Response: EPA acknowledges the concerns of the commenter, but has retained the 25,000 ton
threshold in the final rule. See the Preamble, Section II. E., "General Requirements of the Rule
— Summary of Comments and Responses on Thresholds" for the response on the selection of the
threshold. From analyses of available data, we concluded that a 25,000 metric ton threshold
suited the needs of the reporting program by providing comprehensive coverage of emissions
with a reasonable number of reporters, thereby creating the robust data set necessary for the
quantitative analyses of the range of likely GHG policies, programs and regulations. We
considered higher and lower thresholds, and determined that the intermediate options between
25,000 and 100,000 metric tons would not provide a point that significantly reduced the number
of the reporters or substantially increased the cost effectiveness.
88
-------
The commenter should consult §98.30 of the final rule, which EPA has revised to provide an
expanded list of sources exempted from GHG emissions reporting under Subpart C, including in
certain cases hazardous waste incinerators. It is EPA's intent that sources allowed to use the Tier
1 and 2 methods, which include smaller combustion devices and should be inclusive of control
devices such as thermal oxidizers, will only be required to report emissions from the combustion
of fuels for which emission factors are provided. In the Preamble, EPA has explained that "EPA
believes that the reporting requirements for Tier 1 and Tier 2 would only require the reporting of
GHG emissions from supplementary traditional fossil fuels from devices such as thermal
oxidizers, pollution control devices, fume incinerators, burnout furnaces, and other such
equipment."
Commenter Name: Linda Farrington
Commenter Affiliation: Eli Lilly and Company (Lilly)
Document Control Number: EPA-HQ-OAR-2008-0508-0680.1
Comment Excerpt Number: 27
Comment: The quantity of biomass or biomass derived fuel is easily distinguished from the
fossil fuels combusted in a boiler; however, this does not hold true for industrial solid waste
incinerators. Consequently, the requirement to report biogenic C02 emissions creates a much
higher burden for industrial solid waste incinerators than for boilers. For a unit that combusts
municipal solid waste (MSW), an owner or operator is required to us the prescribed ASTM
methods to determine the relative portions of biogenic and non-biogenic CO2 emissions. To our
knowledge, no such methods exist for industrial solid wastes. In order to report biogenic C02
emissions under the proposed rule, an owner or operator of an industrial solid waste incinerator
would need to classify each individual waste stream as "biomass" or "non-biomass" or determine
the relative % if the waste stream contains a mixture of both. This exercise will take a
tremendous amount of time and effort for incinerators, such as Lilly's, that treat hundreds of
different types of waste streams each year. Therefore, we request EPA limit the reporting of
biogenic CO2 emission to boilers, process heaters, and MSW incinerators only.
Response: The use of ASTM Methods D7459-08 and D6866-06a to determine biogenic CO2
emissions has been expanded to include the combustion of other fuels with a biogenic portion
besides municipal solid waste where CEMS are used; these methods can be used for industrial
solid waste incinerators. Further, EPA refers the commenter to §98.33(e) that provides that
reporting of CO2 emissions from combustion of biomass is required only for those biomass fuels
listed in Table C-l of this section, unless emissions are measured using CEMS. Industrial solid
waste is not a type of fuel found in Table C-l of Subpart C Part 98, and therefore the reporting of
biogenic CO2 emissions from the combustion of industrial solid waste will only be required if
the use of CEMS is required, e.g., pursuant to the Tier 4 provisions in §98.33(b)(4). The use of
Tier 4 is required only when all six conditions specified in §98.33(b)(4)(ii)(A) through (F) are
met by a stationary combustion unit or when a unit meets the conditions specified in §98.33
(b)(4)(iii)(A) through (C).
89
-------
Commenter Name: Kelly R. Carmichael
Commenter Affiliation: NiSource
Document Control Number: EPA-HQ-OAR-2008-0508-1080.2
Comment Excerpt Number: 10
Comment: NiSource supports conclusion made by EPA in the Subpart C preamble discussions
that the Stationary Fuel Combustion Sources should report GHG emissions only if they exceed
the threshold of 25,000 metric tons of C02e for the calendar year.
Response: See the Preamble and separate comment response document volume for the response
on selection of the threshold.
EPA appreciates this comment and intends to finalize the 25,000 metric tons CC^e per year
reporting threshold as proposed.
Commenter Name: Theresa Pfeifer
Commenter Affiliation: Metro Wastewater Reclamation District
Document Control Number: EPA-HQ-OAR-2008-0508-0574.1
Comment Excerpt Number: 2
Comment: Many wastewater treatment plants operate numerous stationary fuel combustion
sources as defined in Subpart C, Section 98.30 of the proposed rule. Additional clarification is
needed on the scope of the combustion units that must be included. The District recommends
that sources of air emissions that are currently categorized as insignificant activities or are
exempted from Title V Operating Permits also be exempted from the total facility emissions
calculations under the proposed rule. Such sources might include, but are not limited to,
individual gaseous fuel burning equipment below a specific rated design threshold (10 million
British thermal units per hour (mmBtu/hr) in Colorado) used solely for heating buildings for
personal comfort.
Response: See the Preamble, Section II. K., and the response to comment EPA-HQ-OAR-2008-
0508-0423.2 excerpt 40 for the response on de minimis reporting for small emission points.
See also the individual source category section(s) of the Preamble and the source category
comment response document(s) for the reponse on the source category-specific reporting
requirements in Subparts C through PP. In particular, note that EPA is not preparing the final
rule, including requiring reporting of the emissions from wastewater treatment under Subpart II
at this time.
EPA has revised §98.30 of the final rule to clarify the definition of the general stationary fuel
combustion source category and provide an expanded list of sources exempted from GHG
emissions reporting under Subpart C; however, this exclusion does not set a 10 mmBtu/hr
capacity threshold. EPA has also removed the cumulative 250 mmBtu/hr restriction on unit
aggregation and clarified common supply pipe metering, and believes that the expanded
availability of these options will reduce the reporting burden on facilities.
90
-------
Commenter Name: Michael E. Van Brunt
Commenter Affiliation: Covanta Energy Corporation
Document Control Number: EPA-HQ-OAR-2008-0508-0548.1
Comment Excerpt Number: 1
Comment: The threshold for triggering reporting by EfW is not consistent with thresholds
applied to other point sources with the EfW threshold being 5 to 7 time lower than other sources.
The Proposed Rule assigns a 250 mmBtu/hr threshold for other sources but for some reason
applies a 250 ton-per-day threshold to EfW facilities. As explained in the following table - this
fuel firing rate is proportional to approximately 80 metric tons of fossil CC^/day versus a range
of 318 to 566 metric tons for fossil fuel sources. The EPA should note that stack fossil C02
emissions is only one aspect of the overall GHG impact of EfW. When avoided grid and landfill
methane are factored in, EfW is a GHG mitigation technology, well recognized internationally,
including by the Intergovernmental Panel on Climate Change and the World Economic Forum.
Applying an artificially low threshold to EfW has two problems: 1) it is far lower than others for
no scientific reason, and 2) it ignores the GHG mitigation aspects. The reporting requirements
should recognize the GHG benefits of EfW. At a minimum, the threshold applied to EfW
facilities for Tier 4 reporting must be consistent with the reporting threshold applied to other
stationary fuel combustion sources. Under the Proposed Rule, tier 2 calculations may be used
for stationary combustion units where the maximum rated heat input capacity is 250 mmBtu/hr
or less; however, a different threshold of 250 tons/day is applied to units that combust MSW.
Based on a nominal heat content of 5,000 Btu/lb, consistent with monthly calculated MSW heat
content at over nearly 30 Covanta facilities, the 250 tons/day threshold is equivalent to 104
mmBtu/hr, less than half the standard applied to other stationary combustion units. Conversely,
a 250 mmBtu/hr threshold applied to nominal MSW would translate into a mass rate threshold of
approximately 600 tons/day per unit. [See DCN: EPA-HQ-OAR-2008-0508-0548.1 for data
table comparing daily CO2 emissions by fuel.]
Response: In the final rule, the threshold of 250 tons per day for units that combust MSW
relates to the applicability of specific tiers and is not a trigger for reporting. A unit combusting
greather than 250 tons per day of MSW must use Tier 4 only if each of the other requirements
are met, including the pre-existence of installed CEMS that are required either by an applicable
Federal or State regulation or the unit's operating permit. The threshold 25,000 metric ton per
year threshold for triggering reporting applies equally to units combusting MSW and units
combusting other fuels.
Both the 250 mmBtu/hr and 250 tons MSW/day are size determinations for considering large
sources in other EPA programs (e.g., 40 CFR 60 Subpart Ea and Eb for Municipal Solid Waste
Combustors) that also require CEMS and the associated infrastructure. These size
determinations were not considered to be directly comparable, but rather to reflect consistency
with other EPA programs.
91
-------
Commenter Name: Robert P. Strieter
Commenter Affiliation: The Aluminum Association
Document Control Number: EPA-HQ-OAR-2008-0508-0350.1
Comment Excerpt Number: 3
Comment: In determining fuel combustion related reporting requirements for facilities, the
Aluminum Association supports fuel specific emission thresholds for reporting. Each of the
major combustion fuels under consideration has markedly differing C02 equivalent emissions
rates. Coal has the highest rate of emissions per unit of energy, while natural gas is relatively
low in emissions per unit of energy. EPA proposed a 30 million BTU reporting threshold for
combustion units regardless of fuel type. As a result, natural gas combustion units will be
required to address reporting at a lower emission threshold than coal fired units. We recommend
that EPA adopt separate BTU reporting thresholds for each fuel type to eliminate this inequity.
By adopting fuel-specific specific thresholds, the reporting requirements will be more equitable
and will better reflect the carbon-intensity of reporting facilities.
Response: See the Preamble and separate comment response document volume for the response
on selection of the threshold.
EPA acknowledges the concerns of the commenter, but will continue to use the 25,000 metric
ton CC^e threshold for facilities that only include stationary combustion equipment. The 30
mmBtu/hr provision, as described in the general provisions is not a separate threshold, but was
provided to give guidance to smaller facilities that would not be subject to applicability
determinations. EPA prefers a single number to give to potential reporters for simplicity. If
EPA were to calculate such numbers for specific fuels, it would have to calculate them for each
possible fuel used in stationary combustion units, likely increasing uncertainty about
applicability rather than decreasing it. EPA plans to publish additional guidance, as feasible, on
equipment capacities, production levels, or other parameters that correlate with emissions of
25,000 metric tons per year of CC^e.
Commenter Name: Steven J. Rowlan
Commenter Affiliation: Nucor Corporation (Nucor)
Document Control Number: EPA-HQ-OAR-2008-0508-0605.1
Comment Excerpt Number: 42
Comment: In 98.31, it is not clear what purpose this section serves since applicability is set in
98.2. This is true of all sections 98.xl throughout the rule.
Response: EPA believes that it is appropriate to include §98.31 in the final rule, since this
section provides clarification regarding which sources are required to report under Subpart C.
Note also that the final version of this section refers directly to the facility applicability
requirements defined in §98.2(a).
92
-------
3. GHGS TO REPORT
Commenter Name: Jeffry C. Muffat
Commenter Affiliation: 3M Company
Document Control Number: EPA-HQ-OAR-2008-0508-0793.1
Comment Excerpt Number: 12
Comment: The emission factors for methane and nitrous oxide are shown in Table C-3 for
common fuels and certain wastes only, and it is not clear how to report these emissions if the
materials burned in the facility are not included in this Table. EPA stated in the Technical
Support Document for this Subpart that methane and nitrous oxide account for less than one
percent of the carbon dioxide equivalents. Technical Support Document for Stationary Fuel
Combustion Emissions: Proposed Rule for Mandatory Reporting of Greenhouse Gases Office of
Air and Radiation (U.S. Environmental Protection Agency, January 30, 2009), section 1.1. Since
greater than 99% of the greenhouse gas emissions for this sector are covered by reporting carbon
dioxide, little additional accuracy would be gained by reporting methane and nitrous oxide
emissions. In addition, hazardous waste incinerators are required to destroy 99.99% of the
organic material fed, including materials that are very difficult to destroy. Since methane is very
easy to destroy, it is highly unlikely that any methane will be emitted from these facilities.
Furthermore, there is very little, if any, information on nitrous oxide emissions for incinerators,
including hazardous waste incinerators. Nitrous oxide emissions are not measured during
required testing for incinerators. Information in current technical literature indicates the nitrous
oxide emissions from high temperature combustion are very small. ("Until a few years ago, fuel
combustion was thought to be a major source of nitrous oxide emissions. However, the
discovery of a sampling error, which resulted in erroneously high emissions factors, revealed that
combustion is actually a minor anthropogenic source." Department of Energy website:
(http://www.eia.d0e.g0v/0iaf/l 605/archive/87-92rpt/chap4.html - accessed 4/20/09). This
conclusion is also echoed in the TSD for this Subpart where EPA states: "The stationary
combustion of carbon-based fuels produces three significant greenhouse gases: carbon dioxide
(C02), methane (CH4) and nitrous oxide (N20). The amount of C02 emitted is directly related
to the carbon content of the fuel. Typically, nearly 100 percent of the fuel carbon is oxidized to
C02. The CH4 and N20 emissions from stationary combustion are much smaller and are
indirectly related to the carbon and nitrogen contents of the fuel. In the U.S., C02 emissions
represent over 99 percent of the total C02-equivalent (C02e) GHG emissions from all
commercial, industrial, and electricity generation stationary combustion sources. CH4 andN20
emissions together represent less than one percent of the total C02e emissions from the same
sources (U.S. EPA, 2008 - Inventory of U.S. Greenhouse Gases and Sinks)." Research on
nitrous oxide formation or destruction during the combustion processes gives the same picture.
In a 1989 paper, it is stated that "N20 is a very short-lived species in hot combustion gases..."
Miller, J. A. and C.T. Bowman, 1989, Mechanism and Modeling of Nitrogen Chemistry in
Combustion, Prog. Energy Combust. Sci., Vol. 15:287-33 8, p. 324). In a subsequent article,
Miller and Bowman state, "At low temperatures, the N20 is relatively stable and appears as a
major product in the gas stream; however, at temperatures above 1150 K, the calculations show
that N20 decays rapidly in the gas stream and is still decomposing at the exit of the reactor..."
Miller, J. A. and C.T. Bowman, 1991. Kinetic Modeling of the Reduction of Nitric Oxide in
Combustion Products by Isocyanic Acid, International Journal of Chemical Kinetics, Vol 23:
289-313, p. 310. The 1150 K temperature mentioned in the quote corresponds to approximately
1600 °F, slightly lower than the temperatures in most hazardous waste combustors. In addition,
93
-------
the authors state that nitrous oxide decays rapidly in gas-phase temperatures above 1150 K. (p.
310). Finally, in his book Principles of Combustion, Kuo states that N2O formed during
combustion reacts rapidly with hydrogen ions to form N2. Kuo, K.K. 2005, Principles of
Combustion, John Wiley & Sons, Inc. (p. 268). Development of emission factors for methane
and nitrous oxide emissions for hazardous waste incinerators will be onerous for those
incinerators which burn a significant number of waste streams. 3M has thousands of active
waste streams all with a slightly different profile. In addition, testing for these compounds will
be costly and is not likely to show a significant quantity of such emissions based on the literature
described above. 3 M requests that EPA exempt hazardous waste incinerators from the scope of
Subpart C.
Response: EPA acknowledges the concerns of the commenter. Section 98.33(c) of the final
rule excludes CH4 and N20 emissions from fuels that are not listed in Table C-2 from
calculation. Table C-2 has been revised to include generic CH4 and N2O emission factors
covering all fuel types listed in Tables C-l. In addition, the rule includes instructions for
estimating CH4 and N2O emissions from MSW. However, EPA has deleted from §98.33(c)
instructions which prescribed methods for facilities burning other fuels to develop site-specific
emission factors based on the results of source testing. Finally, hazardous waste incinerators that
do not combust any supplemental fuels are excluded from the stationary combustion source
category in §98.30. Only emissions from supplemental fuels combusted in these units must be
reported. Furthermore, it is EPA's intent that sources allowed to use the Tier 1 and 2 methods,
which include smaller combustion devices and should be inclusive of control devices such as
thermal oxidizers, will only be required to report emissions from the combustion of fuels for
which emission factors are provided. In the Preamble, EPA has explained that "EPA believes
that the reporting requirements for Tier 1 and Tier 2 would only require the reporting of GHG
emissions from supplementary traditional fossil fuels from devices such as thermal oxidizers,
pollution control devices, fume incinerators, burnout furnaces, and other such equipment."
Commenter Name: Traylor Champion
Commenter Affiliation: Georgia-Pacific, LLC (GP)
Document Control Number: EPA-HQ-OAR-2008-0508-0380.1
Comment Excerpt Number: 24
Comment: Throughout the reporting rule EPA indicates that emissions of biogenic CO2 are to
be calculated and reported separately, but are not to be included in the threshold determination.
GP agrees with EPA that biogenic CO2 emissions should not be included in the calculations for
comparison to the reporting threshold. GP further believes that biogenic CO2 emissions should
not be required to be reported. It is widely accepted that biogenic CO2 emissions are carbon
neutral because the carbon in the biomass is part of the natural carbon cycle. Not reporting
biogenic CO2 emissions is consistent with the Department of Energy (DOE) Technical
Guidelines and the European Union Emissions Trading Scheme. In addition, current prospective
climate change legislation does not address or include emissions from biomass. One purpose of
the proposed reporting rule is to provide data to be used in potential future GHG emission
control programs. Given that these programs will not include biogenic CO2 emissions, reporting
of these emissions under this proposed rule is not warranted.
94
-------
Response: See the response to comment EPA-HQ-OAR-2008-0508-0690.1 excerpt 1
corresponding to Section II. of the Preamble, and the response to comment EPA-HQ-OAR-2008-
0508-0631.1 excerpt 71 corresponding to Subpart C for additional explanation of the reporting of
biogenic CO2 emissions.
EPA appreciates the comment, but has retained the mandatory requirement for reporting of
biogenic C02 emissions in the final rule. Including reporting of biogenic C02 at facilities that
are already reporting for stationary combustion provides EPA with information on the use of
biofuels as they relate to reductions of fossil C02 emissions over time. This reporting
requirement also provides additional data for verification. EPA believes that it is clear in §98.2
that C02 emissions from biogenic fuels do not count toward the 25,000 metric ton threshold for
reporting, although CH4 and N2O emissions from biogenic fuels must be considered.
Commenter Name: Thomas M. Ward
Commenter Affiliation: Novelis Corporation
Document Control Number: EPA-HQ-OAR-2008-0508-0561.1
Comment Excerpt Number: 1
Comment: The proposed rule speaks up front to facility-level reporting which for such a rule is
reasonably well received. However, in the detail of the rule the requirements actually demand
source unit measurement and reporting unless an aggregation is available and with the
aggregation there is a high level of complexity and restriction in the rule that would almost
certainly be augmented by challenges at the facility to monitor and report.
Response: See the Preamble and the response to comment EPA-HQ-OAR-2008-0508-0520.1
excerpt 16 for the response indicating the additional flexibility provided to reporters, particularly
for common pipe and aggregated unit circumstances.
EPA appreciates the commenter's concerns. Reporting at the unit level has a number of benefits,
including greatly increasing the ability of EPA to verify data and not require third party
verification. EPA has made a number of significant adjustments in the final rule to the data
reporting requirements of §98.36, both to clarify those requirements and to reduce the reporting
burden at the unit level.
First, for units that use Tiers 1, 2, and 3 to calculate CO2 mass emissions, the cumulative 250
mmBtu/hr heat input capacity limit on the aggregation of units into a group has been dropped.
Rather, the 250 mmBtu/hr restriction applies only to the individual units in the group. Therefore,
for reporting purposes, individual units with maximum rated heat input capacities of 250
mmBtu/hr or less may be aggregated without limit into a single group, provided that the Tier 4
Calculation Methodology is not required for any of the units, and all units in the group use the
same tier for any common fuel(s) that they combust. Units with maximum rated heat inputs
greater than 250 mmBtu/hr must report as individual units, unless they burn the same type of fuel
provided by a common pipe or supply line; in that case, the owner or operator may opt to use the
common pipe reporting provisions in §98.36(c)(3). Units using Tier 4 must report as individual
units unless they share a monitored common stack or duct; in that case, the common stack or
duct reporting provisions of §98.36(c)(2) may be used.
95
-------
Second, §98.36(d) specifically addresses units that are required to monitor and report emissions
and heat input data according to Part 75. This includes units that are subject to the Acid Rain
Program, CAIR, and RGGI. The unit-level data required for these sources is minimal, consisting
primarily of the GHG emissions totals at each monitored location (i.e., unit, stack, or pipe).
Commenter Name: Thomas M. Ward
Commenter Affiliation: Novelis Corporation
Document Control Number: EPA-HQ-OAR-2008-0508-0561.1
Comment Excerpt Number: 2
Comment: Given the low contribution from emissions of the non-C02 GHG gases, EPA should
recognize the low value of this additional reporting and thereby consider elimination of the
requirement for reporting of these other gases from the stationary combustion sources.
Response: CH4 and N20 are covered under the UNFCCC, are emitted from stationary sources
that would report under Subpart C, and while the national greenhouse gas inventory tracks
overall trends of these emissions, this reporting requirement will provide EPA with valuable
additional information relating to these gases such as trends over time in specific industries.
Emissions data at the facility level for CH4 and N20 are also useful for researchers who need to
know where the gases are emitted. EPA is also seeking information to make informed decisions
regarding whether, what and how to address GHG emissions from particular sectors. While EPA
may not end up addressing CH4 and N20 from boilers in a standard or a program, the Agency
needs the information to make an informed decision. EPA believes that the use of fuel-specific
emission factors for these pollutants strikes an appropriate balance between minimizing the
burden on reporters and obtaining valuable GHG emission data. EPA has, however, revised the
final rule to exclude CH4 and N20 emissions from fuels for which the rule does not provide
emission factors, and has deleted the provision allowing the owner or operator of a facility to
develop site-specific emission factors for such fuels. EPA believes that this change will reduce
the reporting burden on facilities.
Commenter Name: Filipa Rio
Commenter Affiliation: Alliance of Automobile Manufacturers (Alliance)
Document Control Number: EPA-HQ-OAR-2008-0508-0630.1
Comment Excerpt Number: 20
Comment: C02, CH4, and N20 emissions are required to be reported from all stationary fuel
combustion activities. The Alliance recommends that CH4 and N20 emissions be excluded from
stationary fuel combustion source reporting. Emissions of these particular gases are relatively
low when compared to C02 and require a disproportionate effort to estimate and report. In fact,
the DOE notes in the Technical Guidelines for the Voluntary Reporting of Greenhouse Gases
(1605(b)) Program that "stationary source combustion also produces trace quantities of methane
and nitrous oxide." The Technical Guidelines state that "95 to 99 percent of global warming
potential-weighted emissions from stationary source combustion are usually attributed to carbon
dioxide." Several other prominent technical resources such as the World Resources Research
Institute/World Business Council for Sustainable Development "WRIM/BCSD Greenhouse Gas
96
-------
Protocol" indicate CH4 and N20 emissions from stationary combustion are generally minor, on a
C02e basis, compared to 02. While EPA has proposed simpler calculation methods for these
gases, the emission rates for CH4 and N20 are much less predictable as they are by-products of
incomplete or inefficient combustion, and depend on many factors such as combustion
technology and other considerations. The potential inaccuracies of reporting CH4 and N20
emissions based upon a simplified approach may not be worth the additional effort required by
reporters based on the trace amount of emissions. This concept has been endorsed by several
existing GHG reporting programs including the Regional Greenhouse Gas Initiative ("RGGI")
and the EU ETS.
Response: CH4 and N20 are covered under the UNFCCC, are emitted from stationary sources
that would report under Subpart C, and while the national greenhouse gas inventory tracks
overall trends of these emissions, this reporting requirement will provide EPA with valuable
additional information relating to these gases such as trends over time in specific industries.
Emissions data at the facility level for CH4 and N20 are also useful for researchers who need to
know where the gases are emitted. EPA is also seeking information to make informed decisions
regarding whether, what and how to address GHG emissions from particular sectors. While EPA
may not end up addressing CH4 and N20 from boilers in a standard or a program, the Agency
needs the information to make an informed decision. EPA believes that the use of fuel-specific
emission factors for these pollutants strikes an appropriate balance between minimizing the
burden on reporters and obtaining valuable GHG emission data. EPA has, however, revised the
final rule to exclude CH4 and N20 emissions from fuels for which the rule does not provide
emission factors, and has deleted the provision allowing the owner or operator of a facility to
develop site-specific emission factors for such fuels. EPA believes that this change will reduce
the reporting burden on facilities.
Commenter Name: Jeff A. Myrom
Commenter Affiliation: MidAmerican Energy Holdings Company
Document Control Number: EPA-HQ-OAR-2008-0508-0581.1
Comment Excerpt Number: 30
Comment: EPA should not include CH4 and N20 emissions from combustion because such
emissions are too small, variable, and technology dependent to add material value to the
emissions inventory. For example, EPA states that CH4 emissions are equivalent to 0.03% of
C02e emissions per ton of coal, and N20 emissions are equivalent to 0.4% of C02e emissions
per ton of coal. Regarding natural gas combustion, CH4 emissions are equivalent to 0.1% of
C02e emissions, and N20 emissions equivalent to 0.1% of C02e emissions. In no other portion
of the proposed rule does EPA propose including such uncertain and negligible emissions. Thus,
to aid EPA, GHG emissions reporters, and the quality of the emissions inventory, CH4 and N20
estimated emissions from any combustion process should be removed as a reporting requirement
for all facilities and suppliers.
Response: CH4 and N20 are covered under the UNFCCC, are emitted from stationary sources
that would report under Subpart C, and while the national greenhouse gas inventory tracks
overall trends of these emissions, this reporting requirement will provide EPA with valuable
additional information relating to these gases such as trends over time in specific industries.
Emissions data at the facility level for CH4 and N20 are also useful for researchers who need to
97
-------
know where the gases are emitted. EPA is also seeking information to make informed decisions
regarding whether, what and how to address GHG emissions from particular sectors. While EPA
may not end up addressing CH4 and N20 from boilers in a standard or a program, the Agency
needs the information to make an informed decision. EPA believes that the use of fuel-specific
emission factors for these pollutants strikes an appropriate balance between minimizing the
burden on reporters and obtaining valuable GHG emission data. EPA has, however, revised the
final rule to exclude CH4 and N20 emissions from fuels for which the rule does not provide
emission factors, and has deleted the provision allowing the owner or operator of a facility to
develop site-specific emission factors for such fuels. EPA believes that this change will reduce
the reporting burden on facilities.
Commenter Name: Paul Dubenetzky
Commenter Affiliation: KERAMIDA Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-0419.1
Comment Excerpt Number: 12
Comment: KERAMIDA appreciates that the U.S. EPA has proposed that sources aggregate
small emission units into groups for the purposes of reporting GHG emissions. However, we
believe that requiring that the total aggregate heat capacity of each group not exceed 250
mniBtu/hr is arbitrary and serves no useful purpose. Facilities that have multiple, small
emissions units should not be required to separately account for emissions based solely on the
combined heat input capacity rating. An additional "sub-metering" requirement is a burden to
reporters that provides no additional useful information to the U.S. EPA or to the public.
Response: EPA appreciates the commenter's concern and has made several revisions to the final
rule. For units that use Tiers 1, 2, and 3 to calculate C02 mass emissions, the cumulative 250
mmBtu/hr heat input capacity limit on the aggregation of units into a group has been dropped.
Rather, the 250 mmBtu/hr restriction applies only to the individual units in the group. Therefore,
for reporting purposes, individual units with maximum rated heat input capacities of 250
mmBtu/hr or less may be aggregated without limit into a single group, provided that the Tier 4
methodology is not required for any of the units, and all units in the group use the same tier for
any common fuel(s) that they combust. Units with maximum rated heat inputs greater than 250
mmBtu/hr using Tiers 1, 2, and 3 must report as individual units, unless they burn the same type
of fuel provided by a common pipe or supply line; in that case, the owner or operator may opt to
use the common pipe reporting provisions in §98.36(c)(3). Units using Tier 4 must report as
individual units unless they share a monitored common stack or duct; in that case, the common
stack or duct reporting provisions of §98.36(c)(2) may be used.
Commenter Name: Renae Schmidt
Commenter Affiliation: CITGO Petroleum Corporation
Document Control Number: EPA-HQ-OAR-2008-0508-0726.1
Comment Excerpt Number: 8
Comment: CITGO agrees with the tiered approach for fuel combustion sources and that most of
the requirements for this category are reasonable. CITGO disagrees with the reporting for CH4
98
-------
and N20 within the Combustion Sources and some Petroleum Refinery source categories.
Rather, greenhouse gases resulting from combustion sources or processes for the Petroleum
Refinery source category should be reported on a C02e basis rather than C02, N20, and CH4
separately. CH4 and N20 greenhouse gas contributors are insignificant when compared to the
C02 emissions and, as such, should be combined into a single emission factor for calculating and
reporting purposes. As an example, the default factor for natural gas is 102.04 while the default
values for CH4 and N20 are 9.0 x 10-4and 1.0 x 10-4, respectively. If one then applies the
global warming potential, the C02e equivalent can be shown as follows: [See DCN: EPA-HQ-
OAR-2008-0508-0726.1 for C02, CH4 and N20 Contribution to Combustion C02e from Natural
Gas Combustion table] Similar calculations apply to other fuels used within a refinery. In
summary, CITGO believes that greenhouse gas emission reporting should be on C02e basis for
all combustion sources including cat cracker coke combustion. It is both unreasonable and
unnecessary to track, calculate, and report every greenhouse gas separately as though the
inventory were a speciation exercise when it is, in fact, an inventory. Measurement error alone
for the combustion sources and cat cracker coke burns significantly exceed the contributions of
either CH4 and/or N20 combustion contribution. For example, orifice meters typically have 1 -
3% accuracy, depending on use and process conditions - well above the CH4 and N20
contribution. For complex refineries with dozens of combustion sources, setting up and
verifying additional (and unnecessary) calculations in a database or spreadsheet is time
consuming, expensive, and wasteful. The nearly nonexistent return relative to the value of
information gleamed on the time invested to generate it justifies the Agency's application of a
rational "cutoff for such insignificant emissions, if any. In addition, these extra calculations
steps can often result in error due to extra configuration of a database or spreadsheet. CITGO
urges EPA to keep reporting simple as possible and to focus on calculation and measurement
accuracy for the inventory, not insignificant contribution breakout of CH4 and N20. In the end,
the reporting of GHG emissions as C02e will have little, if any, bearing on any future reduction
program.
Response: Reporting gases individually increases transparency, provides atmospheric
researchers who are concerned with actual radiative forcing individual gases more useful data for
their work, and allows EPA to retroactively apply updated GWPs more easily should they need
to be updated per international standards. To this end, EPA has also decided to retain the
separate emission factors and calculations for CH4 and N20. EPA believes that using fuel-based
default emission factors to report these gases separately provides an appropriate balance between
easing the reporting burden on facilities and collecting useful data on GHG emissions.
Commenter Name: Karen St. John
Commenter Affiliation: BP America Inc. (BP)
Document Control Number: EPA-HQ-OAR-2008-0508-0631.1
Comment Excerpt Number: 57
Comment: Section 98.32 states: "You must report C02, CH4, and N20 mass emissions from
each stationary fuel combustion unit." This could be read to mean that all emissions must be
reported on an individual unit basis rather than the other options afforded in Subpart C. BP
requests that EPA clarify the requirement in Subpart C as an inclusive scope rather than a
reporting form requirement.
Response: In the final rule, C02, CH4, and N20 mass emissions from each stationary fuel
combustion unit must be reported separately, by unit, if the calculations are done at the unit
99
-------
level. This requirement is necessary for transparency and verification purposes. If an aggregated
unit, common pipe, or common stack approach is used, then CO2, CH4, and N2O mass emissions
can be reported collectively for the applicable units.
Commenter Name: Craig S. Campbell
Commenter Affiliation: Lafarge North America
Document Control Number: EPA-HQ-OAR-2008-0508-0674.1
Comment Excerpt Number: 15
Comment: Proposed 40 CFR §98.33(c) requires calculation of methane (CH4) and nitrous
oxide (N20) emissions from all stationary combustion units. As documented in the WBCSD
CO2 Cement protocol, cement industry data indicate that CH4 emissions are typically about
0.01% of kiln C02 emissions in a C02e basis, and N20 emissions are also very small.
Consequently, the WBCSD protocol does not require inclusion of these de minimis emissions.
There would be little if any value of collecting data on these two pollutants, since their C02-
equivalent emissions would be an insignificant fraction of the total C02e emissions from the
cement facility and would be less than the confidence interval around the C02e emissions
calculated without accounting for CH4 and N20. In light of their de minimis nature, Lafarge
recommends that cement kilns not be required to calculate and report CH4 and N20.
Response: CH4 and N20 are covered under the UNFCCC, are emitted from stationary sources
that would report under Subpart C, and while the national greenhouse gas inventory tracks
overall trends of these emissions, this reporting requirement will provide EPA with valuable
additional information relating to these gases such as trends over time in specific industries.
Emissions data at the facility level for CH4 and N20 are also useful for researchers who need to
know where the gases are emitted. EPA is also seeking information to make informed decisions
regarding whether, what and how to address GHG emissions from particular sectors. While EPA
may not end up addressing CH4 and N20 from boilers in a standard or a program, the Agency
needs the information to make an informed decision. EPA believes that the use of fuel-specific
emission factors for these pollutants strikes an appropriate balance between minimizing the
burden on reporters and obtaining valuable GHG emission data. EPA has, however, revised the
final rule to exclude CH4 and N20 emissions from fuels for which the rule does not provide
emission factors, and has deleted the provision allowing the owner or operator of a facility to
develop site-specific emission factors for such fuels. EPA believes that this change will reduce
the reporting burden on facilities.
Commenter Name: Marc J. Meteyer
Commenter Affiliation: Compressed Gas Association (CGA)
Document Control Number: EPA-HQ-OAR-2008-0508-0981.1
Comment Excerpt Number: 20
Comment: The preamble for the proposed rule states that C02 emissions far exceed the C02-e
contributions of combustion byproduct emissions of CH4 and N20, specifically "less than 1
percent of combined U.S. GHG emissions from stationary combustion, on a C02-e basis."
Despite this insignificant contribution, combustion sources are being required to estimate these
100
-------
emissions. In some instances, particularly where the lower tier methods for calculating C02
emissions are employed, the calculation of combustion byproduct CH4 and N2O is
straightforward. But in instances where more rigorous methods for calculating C02 emissions
are required (e.g. Tier 4), the calculation of combustion byproduct CH4 and N2O requires a
completely separate calculation process (and inherent process measurement data), comparable to
Tiers 1-3 for CO2 emissions. This is a burdensome requirement for an insignificant contribution
to a source's overall GHG footprint. CGA Comment: CGA does not support calculating the
combustion byproduct CH4 and N2O. However, if the agency feels these emissions are
significant, it should allow greater use of Tiers 1, 2, and 3 for estimating C02 emissions (per
comments on §98.33(b), above).
Response: CH4 and N2O are covered under the UNFCCC, are emitted from stationary sources
that would report under Subpart C, and while the national greenhouse gas inventory tracks
overall trends of these emissions, this reporting requirement will provide EPA with valuable
additional information relating to these gases such as trends over time in specific industries.
Emissions data at the facility level for CH4 and N2O are also useful for researchers who need to
know where the gases are emitted. EPA is also seeking information to make informed decisions
regarding whether, what and how to address GHG emissions from particular sectors. While EPA
may not end up addressing CH4 and N20 from boilers in a standard or a program, the Agency
needs the information to make an informed decision.
EPA believes that the use of fuel-specific emission factors for these pollutants strikes an
appropriate balance between minimizing the burden on reporters and obtaining valuable GHG
emission data. EPA has, however, revised the final rule to exclude CH4 and N2O emissions
from fuels for which the rule does not provide emission factors, and has deleted the provision
allowing the owner or operator of a facility to develop site-specific emission factors for such
fuels. EPA believes that this change will reduce the reporting burden on facilities.
The Agency has clarified the requirements to report under Tier 4, and has made several changes
to reporting dates, extensions, and exceptions, that may indirectly address these concerns. While
the EPA does not find the methodologies for calculating CH4 and N2O emissions burdensome,
the EPA has clarified in the final rule that reporting of these emissions is required only for the
fuels listed in Table C-2 of Subpart C. When more than one type of fuel is combusted in a unit,
direct measurements or engineering estimates of the annual heat input from each fuel are needed
to calculate the CH4 and N2O emissions. Consequently, when CEMS (which are not fuel-
specific) are used to monitor the CO2 emissions and heat input for a multi-fuel unit, the total heat
input measured by the CEMS must be apportioned to each fuel type. The owner or operator
should use the best available information (e.g., fuel feed rates, GCV values, etc.) to do the
necessary heat input apportionment.
Commenter Name: Marc J. Meteyer
Commenter Affiliation: Compressed Gas Association (CGA)
Document Control Number: EPA-HQ-OAR-2008-0508-0981.1
Comment Excerpt Number: 21
Comment: The proposed rule offers an equation for calculating the contribution of CO2
emissions from flue gas desulfurization sorbents, equation C-l 1, which does not appear to be
101
-------
dimensionally (units) correct. Specifically, the "R" term in the equation appears to be incorrectly
defined. CGA Comment: Insure the definitions of terms for equation C-l 1 are dimensionally
correct.
Response: EPA has corrected this error in the final rule. The R term has been redefined as
"1.00, the calcium-to-sulfur stoichiometric ratio."
Commenter Name: J. P. Blackford
Commenter Affiliation: American Public Power Association (APPA)
Document Control Number: EPA-HQ-OAR-2008-0508-0661.1
Comment Excerpt Number: 23
Comment: EPA distinguishes C02 and biogenic C02 emissions from stationary combustion
sources. In the preamble, EPA notes that this distinction is consistent with international policy
developed by the International Panel on Climate Change, California Air Resources Board
Reporting Rule and European Union Emissions Trading System. APPA supports distinguishing
C02 and biogenic C02. Electric generation facilities which are subject to the Acid Rain
Program do not appear to have the opportunity to distinguish C02 from biogenic C02, since the
proposed rule requires that total mass emissions be reported. APPA requests that electric
generation facilities subject to the Acid Rain Program be allowed to report biogenic C02,
consistent with other stationary combustion sources.
Response: It is EPA's intent that Acid Rain Program units will be able to continue to measure
and report C02 emissions as they do under the Acid Rain Program. EPA believes that this will
reduce the reporting burden on sources, and for this reason has not required Acid Rain Program
units to report biogenic emissions separately. However, EPA has provided a method for Acid
Rain Program units which choose to separately quantify their biogenic C02 emissions; see
§98.33(e) of the final rule.
Commenter Name: Juanita M. Bursley
Commenter Affiliation: GrafTech International Holdings Inc. Company (GrafTech)
Document Control Number: EPA-HQ-OAR-2008-0508-0686.1
Comment Excerpt Number: 25
Comment: On page 16480 of the preamble, although EPA notes that C02 emission generated
by fuel combustion far exceeds the CH4 and N20 emissions (< 1% of total), EPA nevertheless
has proposed that facilities must also estimate and report emissions of these two lessor GHGs.
While GrafTech agrees that all combustion GHGs should be accounted for in the national GHG
database for accuracy, it supports the use of a combined C02/CH4/N20 emission factor used by
some of the internationally recognized GHG emissions estimating protocols. This would
simplify the calculation methods and reduce the burden on reporting facilities, without
significantly compromising the accuracy of the emissions data.
Response: Reporting gases individually increases transparency, provides atmospheric
researchers who are concerned with actual radiative forcing individual gases more useful data for
102
-------
their work, and allows EPA to retroactively apply updated GWPs more easily should they need
to be updated per international standards. EPA believes that the use of fuel-specific emission
factors for these pollutants strikes an appropriate balance between minimizing the burden on
reporters and obtaining valuable GHG emission data. EPA has, however, revised the final rule to
exclude CH4 and N20 emissions from fuels for which the rule does not provide emission factors,
and has deleted the provision allowing the owner or operator of a facility to develop site-specific
emission factors for such fuels. EPA believes that this change will reduce the reporting burden
on facilities.
Commenter Name: See Table 10
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0635
Comment Excerpt Number: 53
Comment: We also request that EPA clarify in its final rule that power companies subject to
reporting CO2 emissions for Acid Rain Program units also must report SF6 emissions. While
EPA addresses SF6 emissions in its proposal and proposes a separate reporting threshold, EPA
should also specify that power companies with Acid Rain Program units are subject reporting
obligations for SF6. The "electric power industry uses roughly 80% of all SF6 produced
worldwide" through the transmission and distribution of electricity. Further, SF6 is a highly
potent greenhouse gas: With a global warming potential 23,900 times greater than C02 and an
atmospheric life of 3,200, one pound of SF6 has the same global warming impact of 11 tons of
C02. In 2002, U.S. SF6 emissions from the electric power industry were estimated to be 14.9
TgCC>2[e]. [footnote: See US EPA, http://www.epa.gov/electricpower-sf6/. Id.] EPA should
therefore ensure that this important emissions source is covered in this context.
Response: EPA believes that it is made clear in §98.2 that the GHG emission report for
facilities containing Acid Rain Program units must include emissions from all sources in any
source category for which Calculation Methodologies are provided in Subparts B through JJ.
However, at this time EPA is not going final with the electrical equipment subpart. See the
Preamble section on Subpart DD for more information related to this decision.
Commenter Name: Chris Greissing
Commenter Affiliation: Industrial Minerals Association - North America (IMA-NA)
Document Control Number: EPA-HQ-OAR-2008-0508-0705.1
Comment Excerpt Number: 6
Comment: IMA-NA requests the elimination of CH4 and N2O calculations entirely due to their
minimal impact on the total greenhouse gas inventory and on a facility's emissions. Based on the
formulae provided, less than 0.00001 percent of the greenhouse gas emissions would be CH4 or
N2O. EPA should not require calculation and reporting of these emissions because their
contribution to the total is clearly insignificant.
Response: CH4 and N2O are covered under the UNFCCC, are emitted from stationary sources
that would report under Subpart C, and while the national greenhouse gas inventory tracks
103
-------
overall trends of these emissions, this reporting requirement will provide EPA with valuable
additional information relating to these gases such as trends over time in specific industries.
Emissions data at the facility level for CH4 and N20 are also useful for researchers who need to
know where the gases are emitted. EPA is also seeking information to make informed decisions
regarding whether, what and how to address GHG emissions from particular sectors. While EPA
may not end up addressing CH4 and N2O from boilers in a standard or a program, the Agency
needs the information to make an informed decision.
EPA believes that the use of fuel-specific emission factors for these pollutants strikes an
appropriate balance between minimizing the burden on reporters and obtaining valuable GHG
emission data. EPA has, however, revised the final rule to exclude CH4 and N20 emissions
from fuels for which the rule does not provide emission factors, and has deleted the provision
allowing the owner or operator of a facility to develop site-specific emission factors for such
fuels. EPA believes that this change will reduce the reporting burden on facilities.
104
-------
4. SELECTION OF PROPOSED GHG EMISSIONS CALCULATION AND
MONITORING METHODS
Commenter Name: Michael W. Stroben
Commenter Affiliation: Duke Energy Corporation
Document Control Number: EPA-HQ-OAR-2008-0508-0407.1
Comment Excerpt Number: 10
Comment: Most coal-fired sources which measure CO2 using CEMS under Part 75 measure the
total C02 and are not typically set up to distinguish between C02 (or other emissions) emitted by
fuel type. Altering the CEMS to record heat input by fuel type would add significant cost
without any real benefit, and does not seem to be necessary to fulfill the obligations under the
legislative mandate. If EPA retains the requirement to show the heat input for each fuel, it
should include procedures which would allow a reasonable estimate to be made of the GHG
emissions related to a secondary fossil fuel. For example, the emissions related to oil use in a
coal fired boiler for startup and other miscellaneous uses (such as flame stabilization) can be
calculated based on total fuel consumption and the emission factors in Tables C-l through C-3.
This amount can be subtracted from the total heat input for a unit that exclusively burns fossil
fuels. For a unit that co-fires biogenic fuels, the fuel specific CO2 emissions can be derived from
equations C-l2 and C-l3.
Response: EPA acknowledges the commenter's concerns, and has addressed this issue. EPA
has added provisions to the final rule requiring units subject to Part 75 to report total emissions
by unit, not by fuel. EPA believes that these provisions effectively address the concerns of the
commenter
The final rule specifies that, for Tier 4 units, the annual CO2 emissions will be reported for all
fuels combined, and that any biogenic CO2 emissions will also be reported separately. It also
states that CH4 and N2O emissions are to be reported for each type of fuel combusted, calculated
in accordance with §98.33(c). EPA has specified that reporters using Tier 4 are to calculate CH4
and N2O emissions for each fuel type using the best available estimates of the annual heat input
from each type of fuel combusted in the unit during the reporting year. This can be from CEMS
data or engineering calculations.
Commenter Name: Kerry Kelly
Commenter Affiliation: Waste Management (WM)
Document Control Number: EPA-HQ-OAR-2008-0508-0376.1
Comment Excerpt Number: 6
Comment: Consistent with the WCI and DOE GHG reporting rules, EPA's final MRR should
eliminate the requirement that large MWCs use the Tier 4 methodology. The DOE 1605 (b)
approach is very similar to the calculation methodology used for reporting annual emissions of
criteria pollutants and HAPs as required by Title V operating permits. Each year MWC facilities
must conduct multiple stack or performance tests (under NSPS Subpart Eb/Cb) on all MWC
units, over several days using EPA Methods 1 - 29. Some MWC facilities stack test twice per
year, as some state requirements are more restrictive than the federal standards. The DOE
105
-------
approach would take advantage of these extensive testing requirements. The modified Tier 2
methodology would utilize multiple stack results over several days as follows: (1) Calculate
facility average C02 concentration (%), stack gas flow rate (DSCF/Hour) and boiler load or
steam production (Klbs/hour); (2) calculate a Stack Flow to Load Ratio (SFLR) or DSCF/Hr per
Klbs/hr steam production. The SFLR is analogous to the proposed Tier 2 "B" design heat input
to steam ratio used in Equation C-2b, but could be considered more representative since it is
based on actual test data; (3) obtain biogenic/non-biogenic C02 fractions using ASTM Methods
D 7459 and D 6866-06a from integrated gas samples collected during stack testing; and (4) use
C02 concentration, total steam production and SFLR to calculate MWC unit and facility wide
annual C02 emissions. The above approach modifies the Tier 2 methodology slightly since
actual C02 concentrations are used (not a fixed emission factor), and mass C02 emissions are
calculated from actual stack gas flow and actual steam production rather than using a fixed
design heat input. Table 2 [seeDCN: EPA-HQ-OAR-2008-0508-0376.1] summarizes 2008
non-biogenic C02 emissions from WM Wheelabrator large (i.e., greater than 250 tpd) MWC
facilities calculated in accordance with the proposed alternative methodology. See DCN: EPA-
HQ-OAR-2008-0508-0376.1 for a proposed third equation to Tier 2 Calculation Methodology.
We recommend that the ASTM D6866-06a non-biogenic carbon fraction results be directly
included in the calculation methodology for Municipal Solid Waste combustion. This will
improve transparency in reporting GHG C02 emissions and eliminate potential for error in
apportioning non-biogenic and biogenic C02 emission.
Response: EPA believes that it is appropriate to require the use of CEMS on the largest MSW
combustion sources and any smaller MSW combustion source which already has C02
concentration monitors and stack gas volumetric flow rate monitors in place. EPA has, however,
clarified that all of the criteria in §98.33(b)(4)(ii) or (iii) must be present to require the use of
Tier 4. EPA believes that it is appropriate for MSW combustion units to use ASTM D6866-06a
and D7459-08 on a quarterly basis to determine the relative proportions of biogenic and non-
biogenic C02 emissions from the MSW combusted. Where Tier 2 is used, EPA has provided for
MSW combustion units to determine total C02 emissions from the amount of steam produced,
boiler design, and a default C02 emission factor. EPA believes that this is more appropriate than
determining site-specific factors during annual testing. Where Tier 4 is used, C02 emissions are
determined using a C02 concentration monitor and a stack gas volumetric flow rate monitor.
EPA does not believe that it is appropriate to estimate stack flow based on steam production in
Tier 4, and does not believe it is appropriate to use an 02 monitor for MSW combustion, since it
is not a fuel listed in Table 1 in Section 3.3.5 of Appendix F to Part 75. Biogenic emissions for
the MSW combustion unit are then calculated by multiplying the total C02 emissions for the
year, determined using Tier 2 or 4, by the fraction of biogenic emissions, determined using the
ASTM methods.
Commenter Name: Stephen E. Woock
Commenter Affiliation: Weyerhaeuser Company
Document Control Number: EPA-HQ-OAR-2008-0508-0451.1
Comment Excerpt Number: 18
Comment: Weyerhaeuser does not agree with the provisions requiring direct measurement of
fuel use or the requirements to fuel test to calculate GHG emissions. Direct measurement of fuel
usage, fuel carbon content and fuel heat content is an unnecessary activity, which can not be
106
-------
justified by any purported improvement in accuracy and would impose significant unnecessary
costs. Instead, as allowed under most, if not all other GHG reporting systems, we propose that
the activity data and emissions factor approach described in Tier 1 be allowed as an approach to
calculate the GHG emissions from all stationary combustion sources. Emission factors are
already conservative by design and will ensure the integrity of the reported emissions. Fuel
purchase records, and facility or vendor provided default values for carbon and heat content can
provide the level of accuracy necessary. Therefore, EPA should allow the use of accepted
industry and vendor provided emission factors rather than mandating that the final consumer of
the fuel undertake these new and costly analyses - which EPA should note, will generate it's own
new and sizable carbon footprint as nationwide a very large new activity of sampling, shipping
and testing samples comes on-line. There is no technical basis that would suggest that a facility
level fuel test is more accurate than one done by the fuel vendor. The preferred approach would
be to follow the conventions established by the Canadian and European Union's programs and
allow either national average fuel-specific emission factors, those factors published by the IPCC,
or site specific factors determined (through experience) to be even more appropriate for the
specific example under evaluation. Direct measurement, as required by Tier 2 and 3 in the
proposal, should be optional. Most regulated facilities have internal control procedures to
determine which method is the most consistent and accurate for its operations given its fuels and
fuel systems and multiple data analysis and reporting requirements.
Response: See the Preamble, Section II. L., on General Monitoring Requirements for the overall
rationale for methodologies required under this rule, and the response to comment EPA-HQ-
OAR-2008-0508-0909.1 for the rationale for methodologies required under Subpart C.
EPA has significantly expanded the use of Tier 1 and Tier 2 Calculation Methodologies. Units
of any size combusting only pipeline quality natural gas and/or distillate oil may now use Tier 2,
and most units combusting biogenic fuels may use Tier 1. The mandatory fuel sampling and
analysis requirements for Tiers 2 and 3 have been considerably revised. The final rule requires
that natural gas be sampled semiannually. For fuel oil and coal, a representative sampling is
required for each fuel lot, i.e., for each shipment or delivery. For other liquid fuels and biogas,
quarterly sampling is required. For other solid fuels, excluding municipal solid waste, weekly
composite sampling with monthly analysis is required. For other gaseous fuels, the daily
sampling requirement has been retained, but only for facilities with existing equipment in place
that is capable of providing the data. Otherwise, weekly sampling is required. The final rule
also clarifies that fuel sampling and analysis data provided by the supplier may be used in the
emission calculations, and that fuel billing meters may be used to quantify fuel consumption.
Commenter Name: Kathleen M. Sgamma
Commenter Affiliation: Independent Petroleum Association of Mountain States (IPAMS)
Document Control Number: EPA-HQ-OAR-2008-0508-0521.1
Comment Excerpt Number: 17
Comment: IPAMS members prefer the use of fuel-based CH4 and N2O emission factors, which
is consistent with aggregation of combustion sources using common meters.
Response: EPA appreciates the supportive feedback, and has maintained these specifications in
the final rule.
107
-------
Commenter Name: Michael W. Stroben
Commenter Affiliation: Duke Energy Corporation
Document Control Number: EPA-HQ-OAR-2008-0508-0407.1
Comment Excerpt Number: 16
Comment: EPA proposes to require monthly sampling of the carbon content of propane for Tier
2 and Tier 3 reporting methodologies. Propane is a very homogeneous fuel. The monthly
sampling of the carbon content of propane is not going to provide materially different estimates
of emissions that would result from applying a default emission factor. Duke Energy therefore
recommends that facilities be allowed to use the default HHV and C02, CH4, and N20 emission
factors for Tier 2 and Tier 3 reporting. If a facility is currently sampling propane for other
purposes it could be allowed to use that information if it chose to do so, but this rule should not
create a new requirement that facilities begin propane sampling.
Response: EPA has provided a default emission factor (kg CCh/mmBtu) and HHV
(mmBtu/gallon) in Table C-l for propane. EPA expects that most units combusting propane will
have maximum rated heat input capacities less than 250 mmBtu/hr, and will thus be allowed to
use Tier 1 or Tier 2. Tier 1 does not require any fuel sampling or analysis. Tier 2 will only be
required if the owner or operator of the unit already performs sampling and analysis for HHV, or
receives the result of such analysis from the fuel supplier, at the minimum frequency. If a unit
larger than 250 mmBtu/hr combusts propane, Tier 3 will be required, and fuel sampling and
analysis for carbon content will be required.
EPA agrees with the commenter that for a relatively homogeneous fuel such as propane, monthly
sampling is not necessary. For liquid fuels other than fuel oil, quarterly sampling is required in
the final rule. However, regardless of the sampling frequency, the owner or operator must use
the results of all available valid fuel analyses in the emissions calculations. The final rule also
clarifies that fuel sampling and analysis data provided by the supplier may be used in the
emission calculations.
Commenter Name: Michael Bradley
Commenter Affiliation: The Clean Energy Group (CEG)
Document Control Number: EPA-HQ-OAR-2008-0508-0479.1
Comment Excerpt Number: 15
Comment: The Clean Energy Group suggests including thermal energy in the inventory as well
to calculate greenhouse gas intensity for combined heat and power (CHP) facilities. The Clean
Energy Group requests that EPA allow CHP facilities to utilize the emission calculation protocol
used by EPA's Climate Leaders program to apportion greenhouse gas emissions from thermal
energy production in order to more accurately account for greenhouse gas emissions from such
facilities.
Response: See the Preamble, Section II. D., and separate comment response document volumes
for the responses on the selection of source categories to report and on the relationship of this
rule to other programs.
108
-------
In response to the comment, EPA does not believe that any additional language is needed to
address the issue of greenhouse gas emissions calculation methods for combined heat and power
facilities. While EPA recognizes the benefits associated with thermal energy production and its
effect on GHG emissions, we believe that the Calculation Methodologies discussed in detail in
§98.33 of the final rule provide accurate results to appropriately account for emissions data from
general stationary combustion sources required to report GHG emissions.
Commenter Name: Thomas Siegrist
Commenter Affiliation: Koch Nitrogen Company LLC
Document Control Number: EPA-HQ-OAR-2008-0508-0351.1
Comment Excerpt Number: 15
Comment: The Proposed Rule would also require that process gas, which presumably would
include purge gas from the ammonia process synthesis loop at the KNC ammonia production
plants, be sampled and analyzed daily to determine the carbon content and molecular weight of
the gas when used as a fuel (proposed §98.34(d)(3)). Synthesis loop purge gas composition is
stable over time, and it provides a very small percentage of the overall fuel value consumed in
the ammonia production facility. Whereas daily sampling and analyses of this stream would not
significantly improve the quality of resulting emissions estimates, and would impose an
unwarranted cost and operational burden, the Proposed Rule should be revised to reflect a
required frequency of sampling and analyses of ammonia production purge gas, when used as a
fuel for stationary combustion, of once per quarter.
Response: See the Preamble, Section II. L., on General Monitoring Requirements for the overall
rationale for methodologies required under this rule, and the response to comment EPA-HQ-
OAR-2008-0508-0909.1 for the rationale for methodologies required under Subpart C.
EPA has revised the sampling frequency requirement for gaseous fuels other than natural gas or
biogas in Tier 3 from daily to weekly for facilities where equipment for daily sampling is not in
place. EPA also has limited the mandatory use of Tier 3 to determine emissions from fuels for
which no default values are provided to fuels that make up at least ten percent of the average
annual heat input for a unit with maximum rated heat input capacity greater than 250 mmBtu/hr.
Otherwise, emissions from the alternative fuels need not be reported unless CEMS are used.
Commenter Name: Laurie Burt
Commenter Affiliation: Massachusetts Department of Environmental Protection
Document Control Number: EPA-HQ-OAR-2008-0508-0453.1
Comment Excerpt Number: 14
Comment: Under Section V C of the Preamble, General Stationary Fuel Combustion Sources,
Subsection 3d: Selection of Proposed Monitoring Methods: CH4 and N2O Emissions From All
Fuel Combustion, EPA proposes to use default emission factors and annual heat input values to
estimate CH4 and N2O emissions. Massachusetts suggests that EPA perform studies to improve
these AP-42 emissions factors, which currently have a very low rating.
109
-------
Response: EPA believes the CH4 and N20 emission factors provided in Subpart C are
appropriate for use in this mandatory reporting rule. EPA has reviewed the values, and finds that
they are consistent with Climate Leaders. Values brought in from IPCC were converted in the
same manner as the Climate Leaders factors. EPA is using mostly IPCC values because we are
aware that the AP-42 non-C02 factors haven't been reviewed in-depth recently.
Commenter Name: Thomas Siegrist
Commenter Affiliation: Koch Nitrogen Company LLC
Document Control Number: EPA-HQ-OAR-2008-0508-0351.1
Comment Excerpt Number: 14
Comment: The Proposed Rule would require facilities under Tier 2 to conduct monthly
sampling and analysis of incoming natural gas fuel for higher heating value ("HHV") and would
require facilities under Tier 3 to conduct monthly sampling and analyses for fuel carbon content
and molecular weight. Both of these proposed calculation methods are costly and unnecessary.
Ample historical data are available across industries that characterize HHV, carbon content, and
molecular weight for common fuels such as pipeline-quality natural gas. Default values for these
parameters could reliably be used to estimate combustion-related emissions with minimal
reduction in overall emissions data quality. Use of default values is allowed under several
accepted GHG reporting protocols, including those of the WRI/WBCSD and TCR. EPA should
look to these established programs and eliminate the proposed requirement to sample and
analyze for these parameters in common fuels, such as pipeline-quality natural gas. If EPA
believes it necessary to require site-specific data, the reporting entity should be allowed to use
data generated by the fuel supplier, rather than imposing an additional sampling and analytical
burden on individual manufacturing sites.
Response: See the Preamble, Section II. L., for the response on the general monitoring
approach. See the Preamble and separate comment response document volume for the response
on the relationship of this rule to other programs.
The commenter should note that EPA has revised the rule to allow the use of Tier 2 to calculate
emissions from a unit of any size in which pipeline quality natural gas and/or distillate oil are the
only fossil fuels combusted. EPA agrees with the commenter that for a homogeneous fuel such
as pipeline natural gas, monthly sampling is not necessary. The rule has been revised to require
that natural gas be sampled semiannually. The final rule also clarifies that fuel sampling and
analysis data provided by the supplier may be used in the emission calculations.
Commenter Name: Michael Bradley
Commenter Affiliation: The Clean Energy Group (CEG)
Document Control Number: EPA-HQ-OAR-2008-0508-0479.1
Comment Excerpt Number: 13
Comment: The Clean Energy Group understands that EPA is proposing that the electric utility
industry continue to report CO2 emissions on a quarterly basis to the Clean Air Markets Division
(CAMD) and then sum the emissions at the end of the year and quantify CH4 and nitrous oxide
(N2O) emissions. However, in some cases, total heat input values from oil and natural gas are
110
-------
recorded at the hourly level, but are not summed up separately on an annual basis. The Clean
Energy Group requests that EPA provide methodologies to report CH4 and N2O for multiple fuel
units on Acid Rain units.
Response: EPA acknowledges the concerns of commenters, and has added language to clarify
the methodology for reporting CH4 and N2O for multiple fuel units under the Acid Rain
Program. Please refer to §98.33(c) for detailed instructions.
Commenter Name: Thomas Siegrist
Commenter Affiliation: Koch Nitrogen Company LLC
Document Control Number: EPA-HQ-OAR-2008-0508-0351.1
Comment Excerpt Number: 12
Comment: KNC agrees with EPA's decision to allow the use of default emission factors to
estimate CH4 and N20 emissions from fuel combustion given the low levels of these emissions
and the high relative degree of accuracy of the emission factor method. The Proposed Rule
would allow the use of default emission factors, in combination with annual heat input values, to
estimate methane ("CH4") and N2O emissions from fuel combustion. Considering the relatively
low combustion-related emission levels of CH4 and N20, compared to those of C02, neither
stack testing nor CEMs would provide a cost-effective alternative that would significantly
improve upon the accuracy of a GHG emission inventory. KNC recommends that EPA retain
the use of default emission factors for estimating combustion-related CH4 and N2O emissions in
the final rule.
Response: EPA appreciates the supportive feedback, and has maintained these specifications in
the final rule.
Commenter Name: Steven D. Meyers
Commenter Affiliation: General Electric Company (GE)
Document Control Number: EPA-HQ-OAR-2008-0508-0532.1
Comment Excerpt Number: 18
Comment: Section 98.33 of the proposed regulations provides a four-tiered GHG emissions
calculation methodology for fuel combustion sources. These calculation methodologies range
from use of default fuel specific heating value and CO2 emission factors (Tier 1) to use of CEMS
on large coal-fired units that are already equipped with CEMS (Tier 4). While GE understands
the benefits of CEMS for those sources already employing CEMS; however, additional
opportunities for error and data inconsistency are potentially introduced by Tier 2 and Tier 3
requirements. GE currently uses Tier 1 exclusively in calculating GHG emissions from its fuel
combustion sources all over the world. In fact, GE is using factors that combine the fuel heating
and emissions factors into a single factor. GHG emission can be simply calculated by
multiplying the fuel volume, weight or mass times the appropriate factor. This has also allowed
GE to preprogram these factors into our web-based data collection tool so that our sites do not
need to calculate GHG emissions. In addition, GE's fuel combustion GHG emissions are
calculated in a consistent manner throughout the US and the rest of the world so that meaningful
comparisons can be made between sources and facilities. GE's GHG inventory also allows sites
to combine all of their fuel combustion sources that fire the same fuel and apply the factor only
111
-------
once, greatly simplifying the data collection and emissions calculation processes because the
sites must only collect the total quantity of each type of fuel used on site and enter this data into
the web-based tool. Everything else is done for the site electronically. The proposed Mandatory
Program provides three non-CEMS calculation methodologies. In Tier 1, the reporting site
would have to select a default high heat value and C02 emission factor from a table and plug
these values with the quantity of fuel consumed into the provided equation. In Tier 2, the
reporting site would have to measure the actual high heat value of the fuel or obtain this
information on a periodic basis from the fuel supplier, select a default CO2 emission factor from
a table and plug these values with the quantity of fuel consumed into the provided equation.
Finally, in Tier 3, the site would have to periodically measure the fuel carbon content (molecular
weight for gaseous fuels) and plug this information with the fuel use into an equation that
assumes that all of the carbon is converted to CO2. In each case the level of effort and
complexity increases. Also, the opportunity for data error increases. GE understands that the
accuracy of reporting theoretically increases as one moves from Tier 1 to Tier 2 to Tier 3.
However, in Tier 1, EPA could program the default heat content and emission factors into its
electronic tool so that the reporting facility only has to collect information on the quantity of fuel
consumed and enter this data into the electronic tool. The reporting facility would only have to
certify the quantity of fuel consumed. This would make the data quality assurance much easier,
both for the reporting facility and for EPA. No mistakes could be made in the data calculations
since the electronic reporting tool would do them all. When one moves to Tier 2, the site now
has to obtain actual fuel heat content values on a periodic basis either by measuring and
analyzing the fuel heat content or obtaining this information from the fuel supplier. This may
introduce fuel sampling and analysis errors. Also the laboratory may not report the fuel heat
content data accurately. Finally the site needs to enter another piece of data into the electronic
tool, which could introduce data entry errors. GE presumes that the calculations could still be
preprogrammed into the electronic reporting tool so that the sites would not have to do all of the
calculations. This method is theoretically more accurate than Tier 1. However, the additional
error opportunities that result from Tier 2 may cancel out any increase in theoretical accuracy.
The move to Tier 3 requires the site to obtain actual fuel carbon content (molecular weight for
gaseous fuels) data. This would force the reporting site to do fuel sampling and analysis since
this data may not be reported by the fuel supplier (coal suppliers may report this data but oil and
gas suppliers may not). This would introduce fuel sampling, analysis and reporting errors as
discussed above for Tier 2. GE also presumes that the calculations could still be preprogrammed
into the electronic reporting tool so that the sites would not have to do all of the calculations.
Again this method is theoretically more accurate than Tier 1, however the additional error
opportunities may cancel out any increase in theoretical accuracy. GE has learned that GHG
reporting errors increase as the complexity of reporting increases. We have endeavored to make
our process as simple as possible. We are concerned about the increase in complexity that is
represented by Tiers 2 and 3. In addition, the three tiers will introduce variability as various
reporting facilities select their calculation methodology. It is possible that three different
reporting facilities with three identical units using the same source of natural gas may report
three different GHG emission numbers because they have selected different calculation
methodologies. GE recommends that EPA select a Tier 1 methodology for most standard fuels
such as natural gas, distillate oil, propane, LPG, etc. that tend to have a more uniform
composition to promote simplicity, accuracy and consistency in reporting. GE understands the
need to go to Tiers 2 and 3 in cases where fuel variability may be more significant.
Response: See the Preamble, Section II. L., for the response on the general monitoring
approach.
112
-------
EPA did not choose to adopt a simplified calculation method approach (e.g., using default
emission factors) for all units because the data would be less accurate than under the selected
option and would not make use of site-specific data that many facilities already have available
and refined calculation approaches that many facilities are already using.
However, EPA has significantly expanded the use of Tier 1 and Tier 2 Calculation
Methodologies. Units of any size combusting only pipeline quality natural gas and/or distillate
oil may now use Tier 2, and most units combusting biogenic fuels may use Tier 1. Furthermore,
the mandatory fuel sampling and analysis requirements for Tiers 2 and 3 have been considerably
revised. The final rule requires that natural gas be sampled semiannually. For fuel oil and coal,
a representative sampling is required for each fuel lot, i.e., for each shipment or delivery. For
other liquid fuels and biogas, quarterly sampling is required. For other solid fuels, excluding
municipal solid waste, weekly composite sampling with monthly analysis is required. For other
gaseous fuels, the daily sampling requirement has been retained, but only for facilities with
existing equipment in place that is capable of providing the data. Otherwise, weekly sampling is
required. The final rule clarifies that fuel sampling and analysis data provided by the supplier
may be used in the emission calculations.
Please see Section V. of the Preamble on "Collection, Management, and Dissemination of GHG
Emissions Data" for additional information on how EPA plans to approach electronic reporting
and software tools.
Commenter Name: Rechelle Hollowaty
Commenter Affiliation: Tyson Foods, Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-0379.1
Comment Excerpt Number: 10
Comment: Tyson agrees that EPA should allow the fuel supplier to provide fuel heating values
for both Tier 1 and Tier 2 calculation methodologies. For EPA to require individual facilities to
have tested either internally or externally is redundant to what fuel supply companies routinely
assess and provide to their customers.
Response: The final rule clarifies that fuel sampling and analysis data provided by the supplier
may be used in the emission calculations for both Tier 2 and Tier 3, while Tier 1 calculations use
default heating values and emission factors.
Commenter Name: Traylor Champion
Commenter Affiliation: Georgia-Pacific, LLC (GP)
Document Control Number: EPA-HQ-OAR-2008-0508-0380.1
Comment Excerpt Number: 19
Comment: There is no need for Tier 4 Methodology. Under the proposed rule, a unit rated
greater than 250 MMBtu burning solid fossil fuel that already has a CEMS installed for any
pollutant would need to install a CEMS to determine CO2 emissions and install a flow monitor
113
-------
system to enable the specified Tier 4 calculations. For almost all solid fossil fuels, there has
been a large amount of data collected over many years on the HHV and CO2 emissions
associated with those fuels. Facilities that use solid fossil fuels track the amount of fuel
purchased very closely since it is, in most cases, a significant part of the overall energy cost.
Therefore, requiring a CEMS and flow meter for these units would be an unnecessarily
burdensome and expensive new requirement that would not significantly improve the accuracy
of C02 measurement over fuel-use based calculations.
Response: See the Preamble, Section II. L., for the response on the general monitoring
approach.
The Tier 4 requirement described by the commenter is limited to larger solid fossil fuel units
with an existing pollutant CEMS or volumetric flow rate monitor. EPA is requiring the use of
CEMS due to the complexity of monitoring solid fuel consumption and the heterogeneous nature
of the solid fuels, which reduces the accuracy of calculation methodologies. Many of these fossil
fuel-fired units with a pollutant CEMS have an existing diluent monitor (O2 or CO2) that can be
used to determine C02 emissions (General Stationary Combustion Technical Support Document,
EPA-HQ-OAR-2008-0508-0004).
Commenter Name: Doug MacTaggart
Commenter Affiliation: C-Lock Technology, Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-0502.1
Comment Excerpt Number: 10
Comment: We have developed an uncertainty analysis for CEMS emissions data that has been
reviewed by several leading consultants in CEMS emissions measurements and statistical
analysis. The uncertainty analysis C-Lock has developed calculates the uncertainty of a
reference value compared with an instrument measurement and determines the uncertainty
associated with the difference between the two values. Our uncertainty analysis includes the
following data: (1) Measurement values obtained from both the CEMS and relative accuracy test
audit (RATA) equipment during the RATA tests. Also, the number of accepted/passed RATA
tests performed since 1997. (2) Measurement values from both CEMS instruments and reference
instruments for high, low, and zero levels during daily calibrations. (3) Average hourly values
measured by CEMS. (4) Cumulative number of concentration standard bottles used for daily
calibrations since the last RATA test. (5) The number of RATA tests performed. The automated
uncertainty analysis is built into our software to calculate the uncertainty for any unit in the Part
75 database. The overall finding is that mass flow rate of CO2 (a combination of CO2 flow rate
and concentration) typically indicates errors with a magnitude of 4 - 5%. Note that no "absolute"
measurements exist, therefore, no measurement method can be absolutely accurate in a scientific
sense. Because there are no absolute measures with which to compare CEMS data, only
repeated measurements of the same component using independent methods can approximate the
latent value. Also note that our uncertainty analysis does not account for differences between the
CEMS field measurements, reference values, and the "absolute measurement" because it is
impossible to determine the "absolute measurement." This principle has been affirmed on
several occasions by our consultants who have significant experience with CEMS systems. We
have found that uncertainty estimates provided through this type of analysis are definitely biased
low. Therefore, the "absolute" uncertainty is likely greater than the 4-5% uncertainty specified
114
-------
by our calculations. A summary of CEMS bias studies drawing from publications by several
organizations shows that the potential for measurement bias found by multiple authors ranges
between 3-30%, depending on the equipment used, equipment maintenance, and set-up [See
DCN: EPA-HQ-OAR-2008-0508-0502.1 for Appendix references 3-9], C-Lock engineers have
also performed extensive data mining of the Part 75 database. As a result, we have observed
many indicators of CEMS data discrepancies. For example, one key variable analyzed is CO2
emission intensity (C02 generated per gross unit power produced) and its variability over time.
In well-operated and maintained units, the CO2 emission intensity does not change significantly
over time. Our investigations indicate that changes in C02 emission intensity can be attributable
to one or more of the following factors: (1) Changes in plant heat rate over time including
seasonal changes. (2) Changes in coal quality over time. (3) Changes in steam usage over time
(i.e., steam is used for some other purpose than to generate electricity). (4) Change in the
measurement systems. Although plants in the US that use steam for purposes other than
generating electricity exist, they are few and far between. Therefore, in most cases item #3 can
be eliminated as a contributor to changes in emission intensity. C-Lock has also analyzed the
reported heat rate data in the Part 75 database. We recognize that the reported heat rate in this
database is calculated based on reported C02 emissions data, unit power output data, and
standardized F-factors. Therefore, this heat rate data most likely will not align with actual heat
rate data calculated by plant operators using methods independent of the F-factor approach.
However, the Part 75 database [1] heat rate data, particularly changes in heat rate over time, do
provide an indicator of the validity of the CEMS C02 data. Our analysis of the Part 75 database
indicates many irregular changes in C02 intensity and heat rate. Some examples are shown in
the series of plots in Attachment 1. Our analysis of the data from the 422 single-units with single
stacks that burn coal and emitted more than one million metric tons of CO2 in 2007 indicates the
following for the 2007 year: (1) Of the 422 single-units with single stacks, 212 (50%) of those
units indicate greater variations in CO2 intensity than 10%. [Footnote: This is after accounting
for constant plant load conditions (greater than 90% load) and calculating 14 day rolling
averages. The difference reported is the difference between the minimum and maximum 14-day
averaged value for the 2007 year] (2) Out of the 422 units, 56 units (13%) were determined to
have 14-day CO2 intensity variations of greater than 20%. [see footnote above] (3) Most of the
changes in intensity are not likely to represent real changes in emission intensity because the
intensity swings in many cases aren't logical. Relative to heat rate, the data in the Part 75
database indicate many irregular changes as well. Our analysis of the data from the same units,
show the following: (1) Of the 422 single-units with single stacks, 199 (47%) of those units
indicate greater changes in heat rate than 1,000 BTU/KWh. [see footnote above] (2) Of the 422
single-units with single stacks, 49 (12%) of those units indicate greater changes in heat rate than
2,000 BTU/KWh. [see footnote above] (3) Because the changes are so large, most of the
changes in intensity are not likely to represent real changes in heat rate. We have also made
other observations based on data from the Part 75 database: (1) In most cases, the variations in
"apparent" intensity can not be correlated with major plant outages and the variations often
appear to be random with no logical explanation (i.e., the CO2 intensity degrades over time, an
outage occurs, then the CO2 intensity is recovered). (2) Differences of 6% in CO2 intensity and
heat rate based on CEMS measurement data have been observed for facilities with identical units
burning coal from the same fuel source. If this was an actual emissions intensity change, this
would represent approximately a 600 BTU difference among identical units; this is a highly
unlikely occurrence. [See DCN: EPA-HQ-OAR-2008-0508-0502.1 for table illustrating 2007
yearly average heat rates associated with average emission intensities] (3) Data from older, less
efficient units operating from the same coal source are often reporting a 5-10% better heat rate
and CO2 intensity than units that are newer and have been reported as performing more
115
-------
efficiently. [See DCN: EPA-HQ-OAR-2008-0508-0502.1 for figures illustrating filtered
intensity of two different units] Unit 1 began operation in 1978, while Unit 2 began in 1994.
These units have the same emission controls, coal source, and are both dry-bottom units.
However, the older unit shows a more efficient performance throughout 2007. [See DCN: EPA-
HQ-OAR-2008-0508-0502.1 for table summarizing the trends of the two units according to
average yearly emissions intensity in 2007. Unit #1 at 30 years of age contains a 2007 yearly
average intensity of 0.86 mtC02/MWh; Unit #2 at 14 years of age contains a 0.93 mtC02/MWh
yearly average intesnity. Commenter points out a 7% difference between the two units.]
Response: See the Preamble, Section II. L., for the response on the general monitoring
approach.
See the response to comment EPA-HQ-OAR-2008-0508-0502.1 excerpt 9 for an explanation of
EPA's analysis of the use of the mass balance approach for emissions from solid fuels such as
coal.
The Tier 4 CEMS requirement is limited to larger solid fossil fuel units with an existing pollutant
CEMS or volumetric flow rate monitor. EPA is requiring the use of CEMS due to the
complexity of monitoring solid fuel consumption and the heterogeneous nature of the solid fuels.
Many of these fossil fuel-fired units with a pollutant CEMS have an existing diluent monitor (O2
or C02) that can be used to determine C02 emissions (General Stationary Combustion Technical
Support Document, EPA-HQ-OAR-2008-0508-0004).
Commenter Name: John L. Wittenborn et al.
Commenter Affiliation: Steel Manufacturers Association (SMA) and Specialty Steel Industry
of North America (SSINA)
Document Control Number: EPA-HQ-OAR-2008-0508-0518.1
Comment Excerpt Number: 9
Comment: SMA/SSINA support the use of default emission factors for estimating methane and
nitrous oxide emissions from combustion. Given that these emissions are insignificant at steel
mills, we agree that the additional costs and burdens of using CEMS or developing site-specific
emissions factors is not warranted.
Response: EPA appreciates the supportive feedback and has maintained these specifications in
the final rule.
Commenter Name: Gary Moore
Commenter Affiliation: Pensacola Plant of Ascend Performance Materials LLC
Document Control Number: EPA-HQ-OAR-2008-0508-0366.1
Comment Excerpt Number: 9
Comment: Allowances should be made to subtract fugitive emissions of natural gas, calculated
according to the procedures in Subpart W, from the total amount combusted on a single site.
116
-------
Response: Subpart C allows for combustion emission calculations based only on the fuel
combusted. Subpart C has been revised to allow units of any size combusting only pipeline
quality natural gas to use Tier 2 to calculate emissions. Tier 2 requires facilities to determine
fuel use from company records. EPA intends that this provision will allow a reporting facility to
accurately determine the quantity of fuel combusted using the most appropriate methods for that
facility. EPA points out that it is not finalizing Subpart W at this time.
Commenter Name: Doug MacTaggart
Commenter Affiliation: C-Lock Technology, Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-0502.1
Comment Excerpt Number: 9
Comment: C-Lock promotes and supports that the intent of the EPA reporting rule to maintain
scientific credibility and transparency in reporting emissions data. However, based on the
uncertainty observed in Continuous Emission Monitoring Systems (CEMS) emissions data
contained in the EPA's Part 75 database, it can be reasonably concluded that CEMS can be
relatively uncertain and not sensitive enough to reliably quantify changes in C02 emissions that
result from feasible, but relatively small (1% - 3%) improvements in unit heat rate. Heat rate
improvements of 1 - 3% are simply "lost in the noise" of the larger uncertainty associated with
CEMS data. C-Lock has developed an uncertainty analysis for the Part 75 CEMS CO2
emissions data that has been reviewed by several leading consultants in CEMS emissions data
and statistical analysis. While analyzing the uncertainty of numerous units in the EPA's Part 75
emissions database, it was found that, in general, mass flow rate of C02 (a combination of C02
flow rate and concentration) typically has an uncertainty of at least 4 - 5%, and is likely higher
after considering the unknown variables that were not available for our analysis. This
uncertainty is simply too large to accurately and reliably quantify efficiency improvements that
will lead to reduced CO2 emission rates. We have also noted numerous inconsistencies in the
historical CEMS CO2 emission data, these inconsistencies indicate that reported data may be
inaccurate for many US coal-fired units, by as much as 20%. Inaccuracies in reported data will
make it difficult to establish credible baselines, which will, in turn, impact future reduction goals.
Measurement error will also have significant effects on the integrity of any trading platform.
The current requirements and procedures employed in the US to measure and report CO2 have
evolved primarily from the rules that govern the measurement and reporting of SO2 and NOx
emissions. C-Lock does not endorse applying this "cookie-cutter" approach to CO2 emissions
monitoring. Managing CO2 emissions is different than managing SO2 and NOx emissions
because CO2 is a process emission. For example, when monitoring SO2 emissions, the sulfur
content of coal is 25 - 100 times less than the carbon content and much more variable. Also, flue
gas desulfurization equipment ("scrubbers") can be used to remove SO2 from the flue gas,
therefore making mass-balance calculations more difficult and less certain. Similar issues exist
for the management of NOx emissions. NOx is formed from the oxidation of nitrogen in the
boiler as a result of the combustion process, and scrubbers are can also be used to remove NO2
from the exit gas stream. Because of these issues, CEMS is probably the most accurate, smallest
"headache," and most cost-effective method for determining NOx and SO2 emissions, but the
same is not necessarily true for CO2. The most important point is that there are alternate,
independent, and relatively low-cost methodologies to compute CO2 emissions from a coal-fired
unit that can be used to compare with CEMS data. Two accepted, and relatively inexpensive
methods that can be used to calculate CO2 emissions are a carbon mass balance calculation
117
-------
based on coal quality and quantity data and C02 emissions calculated using plant heat rate and
statistically valid emissions factors for coal. In addition, comparing independent process
indicators, such as comparing coal feed rates and induced-draft fan flows with emissions output,
can indicate potential for error in a CEMS CO2 monitoring system. Process variables can also
be used to reliably show that actions to reduce C02 emissions translate into a quantifiable
benefit. Many plants already use real-time, on-line monitoring systems that perform these
measurements on a continuous basis for performance reasons. Combining these techniques
could significantly reduce the variations and associated uncertainty of any single measurement
technique.
Response: See the Preamble for the response on the general monitoring approach.
The Tier 4 CEMS requirement is limited to larger solid fossil fuel units with an existing pollutant
CEMS or volumetric flow rate monitor. EPA is requiring the use of CEMS due to the
complexity of monitoring solid fuel consumption and the heterogeneous nature of the solid fuels.
Many of these fossil fuel-fired units with a pollutant CEMS have an existing diluent monitor (O2
or C02) that can be used to determine C02 emissions (General Stationary Combustion Technical
Support Document, EPA-HQ-OAR-2008-0508-0004).
Commenter Name: Douglas P. Scott
Commenter Affiliation: The Climate Registry
Document Control Number: EPA-HQ-OAR-2008-0508-0567.2
Comment Excerpt Number: 8
Comment: The Registry recommends requiring the use of emissions factors based on
combustion technology to quantify CH4 and N2O emissions from stationary combustion. EPA
currently prescribes the use of default emission factors for CH4 and N2O based on fuel type.
The Registry has worked with a variety of stakeholders on this issue and based on those
discussions believes it is more accurate to quantify these emissions using emission factors based
on combustion technology.
Response: The use of fuel-specific emission factors is in accordance with methods used in other
programs. The approach provides data of sufficient accuracy for the purposes of this rule, given
that CH4 and N2O emissions from stationary combustion are much less than CO2 emissions.
Commenter Name: Steven M. Maruszewski
Commenter Affiliation: Pennsylvania State University (Penn State)
Document Control Number: EPA-HQ-OAR-2008-0508-0409.1
Comment Excerpt Number: 8
Comment: Penn State agrees that the approach to allow facilities to aggregate emissions from
small units is the appropriate approach. It allows EPA to obtain the data required but with a
reasonable amount of effort on the reporter's part.
118
-------
Response: EPA appreciates this comment, and believes that the final rule includes further
clarification and flexibility regarding aggregation and common pipe provisions that will reduce
the burden on sources.
Commenter Name: Kerry Kelly
Commenter Affiliation: Waste Management (WM)
Document Control Number: EPA-HQ-OAR-2008-0508-0376.1
Comment Excerpt Number: 7
Comment: If EPA decides to use thresholds to determine the applicability of the various
calculation methodologies, then the MRR should include an alternative threshold for use of Tier
4 for MWCs. EPA should base the threshold on non-biogenic CO2 emissions equivalent to a
250 MMbtulhr natural gas fired combustion source. Using the emission factors and assumptions
in the calculations above, we propose the following: "(5) Tier 4 Calculation Methodology: ...(ii)
Shall be used if: ..., or if the unit combusts municipal solid waste, and if non-biogenic C02
emissions are greater than 13,255 kilograms per hour calculated using maximum permitted heat
input in MMBtu per hour, Table C-2 default emission factor and the non-biogenic fraction from
ASTM D 6866-06a results."
Response: EPA appreciates your comment but has kept the 250 ton MSW/day size
determination. Both the 250 mmBtu/hr and 250 tons MSW/day are size determinations for
considering large sources in other EPA programs (e.g., 40 CFR 60 Subpart Ea and Eb for
Municipal Solid Waste Combustors). These size determinations were not considered to be
directly comparable, but rather to reflect consistency with other EPA programs.
Commenter Name: See Table 4
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0455.1
Comment Excerpt Number: 7
Comment: Under Subpart C of the Proposal, the Agency proposes to subject large solid fuel-
fired combustion sources with existing Continuous Emission Monitoring Systems ("CEMS")
equipment to Tier Four monitoring requirements and emissions calculation methods, which are
the most stringent of the proposed monitoring requirements. In the Preamble, the Agency
justifies this stringency based on "the complexity of monitoring solid fuel consumption and the
heterogeneous nature of solid fuels." The Class of '85 disagrees with the assertion that the nature
of solid fuels justifies such stringent monitoring requirements and emissions calculation methods
for CO2. Large stationary combustion units fired with solid fuels are subject to stringent
monitoring requirements and emissions calculation methods under the Acid Rain Program. The
Group agrees that stringent monitoring and emissions calculations are justified under the Acid
Rain Program, as the primary pollutant to track is sulfur dioxide ("SO2"). The Group does not
believe, however, that the same justification applies with regard to CO2 emissions. The
variability of sulfur in coal is significant, but variation in the carbon content of coal is much less.
Because of the homogenous carbon content of coal, the Class of'85 believes that a solid fuel-
fired combustion source should be allowed to calculate CO2 emissions based on carbon content
119
-------
measurements and the amount of coal burned, so long as a facility can certify its coal quantity
measurements. The Class of '85 urges EPA to consider this rationale when evaluating the
stringency of its monitoring requirements and emissions calculation methods for large solid fuel-
fired combustion sources.
Response: EPA believes that while variability in the carbon content may be of concern, the
more significant issue is the ability to accurately determine the quantity of solid fossil fuel
consumption. EPA notes that the commenter also adds the following caveat to the suggested
technique of calculating C02 emissions based on carbon content measurements and the amount
of coal burned, "so long as a facility can certify its coal quantity measurements." EPA refers the
commenter to the report DCN: EPA-HQ-OAR-2008-0508-0696.2 submitted to the docket by
Clean Air Engineering (CAE), which states the use of a mass balance technique for determining
C02 mass emissions can result in significant underestimation of emissions (between 18-77
percent lower than CO2 mass emissions determined using CEMS). While a mass balance
approach may be useful for providing a "ball park" check on the reasonability of the data
collected, EPA believes that there is ample evidence to show that properly operated and
maintained CEM systems provide the best available real-time data. EPA has not seen any
evidence that mass balance data are of high enough quality to be considered an equivalent to
CEMS data. Recent information presented at forums such as Air and Waste Management
Association (AWMA) conferences suggests that a 20 percent error in the measurement of solid
fuel consumption is not uncommon, without taking into account any additional calibration drift
that may occur in the belt scales and gravimetric feeders in-between calibration checks.
Commenter Name: Steven M. Maruszewski
Commenter Affiliation: Pennsylvania State University (Penn State)
Document Control Number: EPA-HQ-OAR-2008-0508-0409.1
Comment Excerpt Number: 7
Comment: EPA has proposed a 4-tiered system for calculating emissions from stationary
sources. Emissions from smaller sources/units can be calculated from measured fuel use and
default heat values. This avoids the cost burden of adding continuous emissions monitoring
systems (CEMS) for smaller units. Large emitters involved in ARP already have these systems.
Penn State agrees with this approach.
Response: EPA appreciates your support and thanks you for your comment. See the Preamble,
Section II. L., for the response on the general monitoring approach.
Commenter Name: Doug MacTaggart
Commenter Affiliation: C-Lock Technology, Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-0502.1
Comment Excerpt Number: 7
Comment: Under the proposed rule, electricity generation units (EGU) falling under the EPA
Acid Rain Program (i.e., large coal-fired plants) would be required to report CO2 emissions
using their existing Continuous Emission Monitoring System (CEMS). For general stationary
120
-------
fuel combustion sources not including EGUs, the proposed rule stipulates a four-tier approach
for determining the methodology to be used to quantify CO2 emissions. Tier 4 would apply to
large facilities that combust solid fossil fuel (i.e., coal) and require reporters to use CEMS if it is
already installed at their facility. Tier 3 would apply mainly to combustion of more
homogeneous liquid and gaseous fossil fuels and would require periodic determination of the
carbon content of the fuel combined with direct measurement of the amount of fuel combusted.
EPA states that they evaluated calculation methods for coal combustion used in other emissions
reporting programs. EPA found that these methods would introduce significant uncertainty into
the reported C02 emissions estimates based on the heterogeneous nature of coal, the relative
infrequency of coal sampling required by the methods (often only monthly), their lack of
inclusion of heat input capacity of stationary combustion equipment, and the use of company
records to estimate fuel consumption. C-Lock has found that relying solely on CEMS for
quantification of power plant emissions can result in significant uncertainty and that the key to
reducing this uncertainty is inclusion of additional data feeds and calculation methods into the
quantification process [See DCN: EPA-HQ-OAR-2008-0508-0502.1 Appendix A for details].
In addition, C-Lock has found that the issues with coal sampling identified by EPA can be
rectified by more rigorous sampling and analysis methodologies. In particular, ASTM
International standards specifying much more frequent sampling of coal [See DCN: EPA-HQ-
OAR-2008-0508-0502.1 for references for ASTM standards D7430, D6883, D6609,
D2234/D2234M, and D2013] are commonly used to control business transactions related to
buying and selling of coal. Thus, C-Lock advocates providing coal-fired EGUs and other large
stationary fuel combustion facilities with the opportunity to use emission quantification methods
based on consumed fuel as long as the more rigorous ASTM procedures are followed. This will
result in increased accuracy of the reported emissions and a more accurate baseline for future
programs.
Response: The commenter did not explain what is meant by "more rigorous ASTM procedures"
for quantifying solid fossil fuel consumption, or the basis for believing that these procedures are
capable of providing CO2 emissions estimates equivalent to direct measurement of CO2
emissions with a CEMS. The commenter does refer to a number of ASTM coal sampling
techniques, which could be used to measure the carbon content of the fuel, but are not suitable
for quantifying solid fossil fuel consumption.
Commenter Name: David A. Buff
Commenter Affiliation: Florida Sugar Industry (FSI)
Document Control Number: EPA-HQ-OAR-2008-0508-0500.1
Comment Excerpt Number: 11
Comment: The FSI agrees with EPA that requiring periodic stack testing to derive site-specific
emission factors for CH4 and N2O is too costly and thus not justified. Stack testing for this
purpose is not likely to produce any meaningful improvement in the quality of the emissions
data. As EPA acknowledged in the Preamble to the proposed rule, the CH4 and N2O emissions
from stationary combustion sources are relatively low compared to the CO2 emissions. The
proposed approach, i.e., using fuel-specific default emission factors to calculate CH4 and N2O
emissions, is in accordance with methods used in other programs and provides data of sufficient
accuracy. Moreover, EPA also should recognize that many sources may have CH4 stack test
data available, because of requirements in their Title V or construction permits to measure VOC
121
-------
emissions. Where a facility has CH4 stack test data available, it makes sense to require such data
to be used.
Response: EPA acknowledges the concerns of the commenters. For the purpose of the rule,
which is data collection for policy development, we would prefer consistent use of default CH4
and N2O emission factors. In this case, we provide the values we would like reporters to use in
Table C-2, and for verification purposes, would prefer consistent use of these factors. Additional
factors may be brought into future programs, but for this rulemaking, given the very small
comparative amounts of CH4 and N20 emitted compared to C02, we have chosen to use the
defaults provided in Table C-2. The commenter should note that EPA has revised the final rule
to exclude CH4 and N20 emissions from fuels for which the rule does not provide emission
factors, and has deleted the provision allowing the owner or operator of a facility to develop site-
specific emission factors for such fuels. EPA believes that this change will reduce the reporting
burden on facilities.
Commenter Name: Doug MacTaggart
Commenter Affiliation: C-Lock Technology, Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-0502.1
Comment Excerpt Number: 11
Comment: C-Lock advocates using CEMS data, coal analysis data, and plant heat rate, along
with other parameters, simultaneously and in near-real-time. If comparison of these data reveals
inconsistencies, the operator has the responsibility to identify the measurement problem and to
resolve the differences quickly. By relating C02 emissions to multiple plant processes and data
feeds, the performance of a unit can be closely monitored and small, incremental improvements
can be documented in multiple transparent, accurate, and verifiable ways, thus increasing market
credibility and value. [See DCN: EPA-HQ-OAR-2008-0508-0502.1 for figure illustrating how
additional data feeds can be used to check for potential errors in plant process and monitoring
data] Coal Data Coal is a valuable commodity, and samples are taken and analyzed from nearly
100% of coal shipments. Analysis of SO2 emission potential is reported in each weigh-bill, and
checked prior to unloading. ASTM standards [10-21] are used daily around the world to control
business transactions related to coal buying and selling. Standardization by adherence to
accepted ASTM procedures is the key to improved value and understanding between buyer and
seller. We advocate following ASTM procedures whenever possible. Fossil power plants are
required by United States law to report coal analysis and mass consumption to the Federal
Energy Regulatory Commission (FERC). Under these requirements, every power plant must
report basic coal analysis and mass burned. FERC requires proximate analysis of extrinsic
properties which includes moisture, volatile matter, fixed carbon, ash (by difference), sulfur, and
BTU/lb determination. In order to determine carbon dioxide from combustion, ultimate analysis
of intrinsic properties, for carbon, hydrogen, nitrogen, oxygen (by difference) is required. These
properties can be obtained from the same sample, but each requires additional laboratory
expense. C-Lock is also working in the European Union (EU) to quantify GHG emissions and
reductions under the EU Emissions Trading System (EU ETS). In the EU, CEMS data are not
typically used to quantify CO2 emissions. The EU methodology utilizes coal quantity and
quality as a basis for CO2 emission determinations. The relevant European directive instructs
that if CEMS data are used to determine emissions, it must be clearly demonstrated that results
provide a more accurate representation of annual emissions than using coal data and the
122
-------
measurements must still be verified with calculations based on fuel [See references 22-23 in
Appendix of DCN: EPA-HQ-OAR-2008-0508-0502.1], There is a justifiable need to compare
accuracy of CEMS and Carbon Mass Balance (CMB) calculations over time because they are
completely independent methods to estimate CO2 emissions. By comparing the two, errors in
either method can be identified and problems can be solved immediately. We advocate stringent
quality assurance and quality control requirements as laid out by the EPA and ASTM for both
CEMS and CMB because the uncertainty of the calculated emission rates is directly related to
the quality of the data. Heat Rate Data The Electric Power Research Institute (EPRI) stated in
March 2009 that, "the only cost-effective, near-term option for reducing net C02 emissions from
coal-fired power plants is to reduce the amount of coal used. Reducing plant heat rate is an
effective means of reducing coal consumption" [See reference 24 in Appendix of DCN: EPA-
HQ-OAR-2008-0508-0502.1], Unit heat rate is presently widely measured and used to
determine the efficiency of a power plant as it depends on the unit design, fuel, and capacity
factor. With sufficient unit data, CO2 emissions can be computed accurately using unit heat rate
measurements and statistical valid emissions factors for the coal being burned. The quality of
heat rate data used to calculate CO2 emissions will have a significant impact of their accuracy.
Multiple techniques for measurement of unit heat rate are available, and studies have been
conducted by the Lehigh University Energy Research Center (ERC) to compare them. For
example, one study [See reference 25 in Appendix of DCN: EPA-HQ-OAR-2008-0508-0502.1]
examines heat rates computed using the Input/Output, Output/Loss, Boiler/Turbine-Cycle
Efficiency (BTCE), and F-factor approaches. During this study, the ERC found that because the
accuracy of the F-factor method is directly dependent on the accuracy of flue gas flow rate
measurements and errors in CEMS flow rate ranged between 5 and 20 percent at many
installations, the F-factor approach is the least accurate. The study also found the Input/Output
method to be more accurate with typical unit measurement uncertainty in the 1.5 to 3 percent
range (it is important to note that in a coal-fired unit the error is largely a random error). The
Output/Loss and BTCE methods are significantly more accurate than the Input/Output Method,
with typical measurement uncertainties in the 0.75 to 1.5 percent range (the errors in measured
turbine cycle heat rate are typically systematic or bias errors). Both the Output/ Loss and BTCE
methods can be used fairly easily to obtain highly accurate results on heat rate differences. The
ERC study also found it is possible, with minimal effort, to implement two or more of the
methods at once, and the simultaneous use of several performance measurement methods greatly
increases confidence in the results. Process Variables Comparing independent process data, such
as comparing trends in coal feed rates and induced-draft fan flows with trends in CEMS
emissions, mass flow rate and intensity can indicate potential for error in a CEMS CO2
monitoring system. Unlike SO2 and NOx emissions, with CO2 emissions, there are typically
many process data points that should trend well with CEMS data that should be considered to
help validate emissions data. Process variables can also be used to accurately quantify
incremental reductions related to actions that result in 1 - 3% efficiency improvements. With the
larger uncertainty associated with total unit or facility emissions rates, 1 - 3% efficiency
improvements are simply "lost in the noise" of the larger emissions uncertainty. This is further
compounded when multiple units are connected to a single stack. The incentive to increase plant
efficiencies becomes minimal when the ability to link actions to incentives is lost by using only
total emissions rates. Efficiency improvements are often measurable using process specific data
related to the improvement. Using specific process data, determination of increased efficiency
related to a specific improvement can be made. Once the increase in efficiency is determined,
the incremental decrease in CO2 emissions associated with the improvement can be determined.
This approach has been successfully used before in the carbon markets, and has been approved
under the Clean Development Mechanism (CDM) of the Kyoto protocol [See references 26-27 in
123
-------
Appendix of DCN: EPA-HQ-OAR-2008-0508-0502.1], However, the entire process needs to
be documented in a straight-forward, transparent way. The approach for quantifying increased
efficiency of specific components (and associated emissions reductions) is not new and there are
many specific ASME standards defining the best accepted practice on how to determine
efficiencies of various components within a power plant [See reference 28-35 in Appendix of
DCN: EPA-HQ-OAR-2008-0508-0502.1],
Response: EPA refers the commenter to the report DCN: EPA-HQ-OAR-2008-0508-0696.2
submitted to the docket by Clean Air Engineering (CAE), which states the use of a mass balance
technique for determining CO2 mass emissions can result in significant underestimation of
emissions (between 18-77 percent lower than C02 mass emissions determined using CEMS).
While a mass balance approach may be useful for providing a "ball park" check on the
reasonability of the data collected, EPA believes that there is ample evidence to show that
properly operated and maintained CEM systems provide the best available real-time data. EPA
has not seen any evidence that mass balance data are of high enough quality to be considered an
equivalent to CEMS data. Recent information presented at forums such as Air and Waste
Management Association (AWMA) conferences suggests that a 20 percent error in the
measurement of solid fuel consumption is not uncommon, without taking into account any
additional calibration drift that may occur in the belt scales and gravimetric feeders in-between
calibration checks.
Commenter Name: Edward N. Saccoccia
Commenter Affiliation: Praxair Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-0977.1
Comment Excerpt Number: 5
Comment: EPA should not require the use of the Tier 4 method where alternative fuel
consumption data is available. Tier 1, 2, and 3 offer viable alternatives for many combustion
sources that will yield comparable, and in many cases, more accurate emission estimates. Allow
optional use of the Tier 4 method where, at the source's discretion. This may be a suitable
calculation method where a source uses multiple fuels and/or non-commercial fuels or where
existing CEMS systems include CO2 measurement or can be modified at lower cost than
alternative fuel consumption and/or characterization devices/practices. In any case, let the
regulated source determine which method is most cost effective for their particular situation.
Response: See the Preamble, Section II. L., for the response on the general monitoring
approach.
EPA has considerably revised §98.33(b), describing which tier a reporter is to use. Tier 2 is now
available to units combusting only pipeline natural gas and/or distillate fuel oil, and most units
combusting only biogenic fuels may now use Tier 1. EPA has revised §98.33(b)(4)(ii) of the
final rule to clarify that all six criteria specified in subparagraphs (A) through (F) must be met
before Tier 4 is required. The Tier 4 CEMS requirement is limited to larger solid fossil fuel units
with an existing pollutant CEMS or volumetric flow rate monitor. EPA is requiring the use of
CEMS due to the complexity of monitoring solid fuel consumption and the heterogeneous nature
of the solid fuels.
124
-------
Commenter Name: Jeffrey L. Clark
Commenter Affiliation: Environmental Coordinator, Teck Alaska Incorporated
Document Control Number: EPA-HQ-OAR-2008-0508-0142
Comment Excerpt Number: 5
Comment: The definitions of Tier 1, 2, 3, and 4 are nebulous and will result in confusion over
which calculation methods should apply. Two of the Tiers regulate sources less than 250
mmBtus. Perhaps there should be a lower level cutoff exempting the use of the more complex
calculations and analysis of fuels for smaller facilities. Are all GHG sources rated in mmBtus?
If not, some of the EPA's calculation will not work. If one has a MSW incinerator with no co-
generated steam, the Tier 1 MSW GHG calculation will yield 0.
Response: EPA acknowledges the commenter's concerns, and has substantially revised
§98.33(b) in the final rule, relaxing tier and calculation method applicability. EPA believes that
the revised language makes it clear which tier calculation method(s) a reporter may use. The
revised rule also adds considerable flexibility, allowing more reporters to use the lower tiers.
EPA has allowed units that combust MSW but do not produce steam to calculate their emissions
using Tier 1 methods, which do not use the quantity of steam generated.
Commenter Name: Keith A. Nagel
Commenter Affiliation: ArcelorMittal USA and Severstal North America
Document Control Number: EPA-HQ-OAR-2008-0508-0496.1
Comment Excerpt Number: 10
Comment: Section 98.33(c)(4) requires owners/operators to develop site-specific CH4 and N2O
emissions factors based on source testing where default factors are not provided for particular
fuel types. Since the Proposed Rule does not contain default factors for either blast furnace gas
or coke oven gas, this provision would obligate steel plants to generate site-specific emissions
factors for these fuels based on testing. Such testing would be very difficult (if not impossible)
because many of our combustion sources simultaneously fire multiple fuels at constantly
changing levels or are flares which are impossible to test. While the burden of developing site-
specific factors is high, the CH4 and N2O emissions at issue are orders of magnitude less
significant than related CO2 emissions at these sources. Since the vast majority of process gas
combustion at steel mills occurs at very high temperatures, very little N2O is created. With
respect to methane, "CH4 emissions from stationary combustion are primarily a function of the
CH4 content of the fuel and combustion efficiency." See Inventory of U.S. Greenhouse Gas
Emissions and Sinks: 1990 - 2007 at p. 3 - 7. While comparatively more difficult to combust
(due to its lower Btu value), blast furnace gas contains almost no CH4 to begin with. See The
Making, Shaping and Treating of Steel, 11th ed. (1999) at p. 347 (indicating that blast furnace
gas only contains "approximately 0.2% CH4"). Coke oven gas contains significantly more CH4
but is combusted very efficiently due to its much higher Btu content. Since both the presence of
CH4 and inefficient combustion are necessary, neither coke oven gas combustion nor blast
furnace gas combustion emits meaningful amounts of methane. Given the significant challenges
associated with the development of site-specific factors in this context and the very small relative
amount of CH4 and/or N2O emissions that results from the combustion of blast furnace gas and
125
-------
coke oven gas, we request that EPA delete the requirement to report CH4 and N20 emissions
from sources primarily combusting blast furnace gas and/or coke oven gas. Alternately, if EPA
declines to delete this requirement, we request that EPA defer such reporting pending the
development of industry-wide default factors. ArcelorMittal and Severstal stand ready to work
with EPA to develop such factors if the final rule is so amended.
Response: EPA acknowledges the concerns of the commenters. EPA has revised the rule so
that CH4 and N2O emission calculations are only required for those fuels listed in Table C-2 of
Subpart C. Default factors for coke oven and blast furnace gases have been added to Table C-2.
Commenter Name: John H. Skinner
Commenter Affiliation: Solid Waste Association of North America (SWANA)
Document Control Number: EPA-HQ-OAR-2008-0508-0659.1
Comment Excerpt Number: 10
Comment: The Tier 3 methodology requires monthly direct measurements of fuel carbon
content, which would require extremely large samples in order to be representative for MSW and
is not technically feasible for WTE operations. As the rule is currently written WTE facilities
without monitors are only given the option of Tier 3 for 2010, but Tier 2 is more appropriate for
WTE facilities. We recommend that the Tier 2 method be used by all WTE operations.
Response: EPA has revised the rule so that those units that must upgrade their existing CEMS
to meet Tier 4 requirements may use either Tier 2 or 3 in 2010, if all the required monitors have
not been installed and certified by January 1, 2010.
Commenter Name: Michael DiMauro
Commenter Affiliation: Massachusetts Municipal Wholesale Electric Company (MMWEC)
Document Control Number: EPA-HQ-OAR-2008-0508-0580
Comment Excerpt Number: 10
Comment: The Tiered Monitoring Scheme presented in the Proposed Rule (Section 98.33) is
overly complicated, does not represent a real progression in measurement accuracy, and contains
overly burdensome fuel sampling requirements for units with a heat input > 250 MMBtu/hr. a)
The Four Tier Approach - Shortcomings/Misconceptions i. 02 Monitoring using a FI0W/CO2
Monitor CEMS vs. a Fuel Metering Monitoring System: In the Tiered Monitoring approach for
stationary sources presented in Section 98.33, the Part 75 Flow Monitor/CC^ CEMS
measurement method is assigned the highest accuracy Tier (IV). However, as far as I am aware,
no justification for this assumption is provided in the rule Preamble, and several factors suggest
that CO2 emissions derived from Fuel Meter measurements are of comparable accuracy to those
determined from Part 75 FI0W/CO2 CEMS. In particular: 1. CEMS Flow Monitors are
essentially calibrated to match Reference Method flow measurements determined in accordance
with procedures detailed 40 CFR 60 Appendix A Method 1 and 2. These Reference Method
flow measurements are normally performed using standard Pitot tubes, which are subject to
inaccuracies if there are any cyclonics in the stack flow [Part 75 does provide an option to
perform flow testing using 3-D probes, which can eliminate much of this inaccuracy, however
126
-------
there is no requirement to use such 3-D Probes], 2. The Part 75 RATA accuracy threshold for
flow monitors and for CO2 monitors are each + / -10%, so that the resulting CO2 emissions
measurement error using this flow/C02 CEMS method is potentially significantly higher than
10%. 3. Part 75 RATA flow testing is only performed at 2 or 3 loads, and ongoing QA for flow
monitors is limited. 4. In contrast, most oil and gas fuel meters used at EGU sites have
accuracies of better than 1% across the meter scale range, and if fuel meter measurements begin
to drift, such excursions will typically be noticed quickly as the overall operation of the
combustion unit will be adversely affected. 5. It might also be noted that under the original 40
CFR 75 rule, oil fired combustion units were not permitted to monitor C02 emissions using fuel
meters, however based on evidence provided to EPA showing that CO2 emissions determined by
fuel metering closely tracked emissions determined using Flow/C02 monitors, along with other
supporting information, the 40 CFR 75 rule was revised to allow oil fired units to monitor CO2
using fuel meters. In general then, there is no reason to expect C02 determined from fuel
metering to be any less accurate than that determined from FI0W/CO2 CEMS. ii. CO2
Monitoring using a Flow/02 Monitor CEMS: Inclusion of the Part 75 Flow/02 Monitor CEMS
in the highest accuracy Tier (IV) is particularly inappropriate and inconsistent with the Tiered
accuracy concept, as this CEMS system relies on the very default C02 emission factors that are
the basis for relegating sources in the Tier II category to a lower accuracy status - see Formulas
F- 14a and F 14b in 40 CFR 75 Appendix F. iii. Fuel Usage from Company Records vs. Direct
Fuel Metering: when determining fuel usage on a long term (annual) basis, there is no reason to
expect data values derived from meter measurements to be inherently more accurate than values
extracted from company records, particularly if the company records are based on fuel delivery
billings or billing invoices provided by the supplier. For the same reasons that billing meters are
assumed accurate (see Part 75 Appendix D), fuel delivery data can be presumed equally accurate.
And over the course of a year, any inaccuracies introduced in the process of converting fuel
delivery data to fuel consumption values (e.g. accounting for changes in Oil Tank levels) should
be relatively small, and even these small sources of error can be largely eliminated in most cases
(i.e. by measuring Tank oil levels at the beginning and end of the year). Overall, then, there does
not appear to be any compelling evidence to support the notion that the four Tiers (I to IV)
established in the Proposed Rule represent a progressive trend toward increased accuracy.
Rather, at least for long term emissions tracking, they may simply represent four different
approaches that differ in methodology more than inherent quality. The idea of allowing different
monitoring approaches is strongly supported, however the idea of classifying them in a
progressive hierarchy does not seem justified.
Response: EPA does not agree with the commenter's assessment. Tier 4 is required only for the
combustion of solid fossil fuel and municipal solid waste, whereas Tier 3 requires the use of
calibrated fuel flow meters to quantify the consumption of liquid and gaseous fuels. The fuel
flow meters that the commenter believes will provide more accurate data than a CEMS, cannot
be used for solid fuels. So the basic premise of the commenter's argument does not apply in this
context. The only direct comparison that can be made between the accuracy of Tiers 3 and 4 is
for solid fossil fuel combustion. Tier 3 requires the use of "company records" to quantify solid
fossil fuel usage. As discussed in the preamble to the proposed rule, EPA has serious concerns
about the accuracy of coal belt scales and other equipment used to measure coal feed rates.
Therefore, the Agency maintains its position that the Tier 4 method is more accurate than Tier 3,
when the two Tiers are compared on an equivalent basis.
127
-------
Commenter Name: Keith A. Nagel
Commenter Affiliation: ArcelorMittal USA and Severstal North America
Document Control Number: EPA-HQ-OAR-2008-0508-0496.1
Comment Excerpt Number: 9
Comment: The other major impediment to application of Tier 1 and Tier 2 methods at many
steel plant combustion sources is the Proposed Rule's limitation of these methods to units "with a
maximum rated heat input capacity of 250 mmBtu/hr or less." See §§98.33(b)(1) and (3). That
threshold is arbitrary in that it has no direct link to GHG emissions. For example, a 249
mmBtu/hr boiler combusting coal would have a much more significant carbon footprint than a
300 mmBtu/hr boiler burning blast furnace gas and/or coke oven gas. Thus, as currently written,
this requirement would disproportionately impact sources that intentionally promote the reuse of
waste gases in lieu of additional fossil fuel consumption. To avoid that unintended impact, we
request that EPA either delete the 250 mmBtu/hr threshold requirement entirely for units
combusting process gases (which would strongly encourage energy conservation) or link the use
of Tier 1 and Tier 2 methodology to a specific C02e threshold.
Response: EPA has significantly expanded the use of Tier 2 calculation methods for units that
combust natural gas and distillate oil, in view of the homogeneous nature and low variability in
the characteristics of these fuels. Furthermore, Tier 1 is available to units of all sizes combusting
biomass fuels from Table C-l. However, the Tier 3 methodology is still required for large 250
mmBtu/hr units that combust other fuels, including blast furnace gas and coke oven gas.
For gaseous fuels other than natural gas and biogas, due to variability, the daily sampling
requirement has been retained, but only for facilities with existing equipment in place that is
capable of providing the data. Otherwise, weekly sampling is required.
The 250 mmBtu/hr size determinations is used for considering large sources in other EPA
programs, and EPA believes that the use of tiers based on this determination is appropriate.
Commenter Name: Alexander D. Menotti
Commenter Affiliation: Kelley Drye & Warren et. al LLP on behalf of the Steel Manufacturers
Association (SMA) and Specialty Steel Industry of North America (SSINA)
Document Control Number: EPA-HQ-OAR-2008-0508-0656.1
Comment Excerpt Number: 9
Comment: SMA/SSINA support the use of default emission factors for estimating methane and
nitrous oxide emissions from combustion. Given that these emissions are insignificant at steel
mills, we agree that the additional costs and burdens of using CEMS or developing site-specific
emissions factors is not warranted.
Response: EPA appreciates the supportive feedback, and has maintained these specifications in
the final rule.
128
-------
Commenter Name: John H. Skinner
Commenter Affiliation: Solid Waste Association of North America (SWANA)
Document Control Number: EPA-HQ-OAR-2008-0508-0659.1
Comment Excerpt Number: 8
Comment: SWANA believes the threshold applied to WTE facilities for Tier 4 reporting must
be consistent with the reporting threshold applied to other stationary fuel combustion sources.
Tier 2 calculations may be used for stationary combustion units where the maximum rated heat
input capacity is 250 mmBtu/hr or less; however, a different threshold of 250 tons / day is
applied to units that combust MSW. Based on a nominal heat content of 5,000 Btu / lb, the 250
tons / day threshold is equivalent to 104 mmBtu/hr, less than half the standard applied to other
stationary combustion units. Conversely, a 250 mmBtu/hr threshold applied to nominal MSW
would translate into a mass rate threshold of approximately 600 tons / day. According to EPA's
most recent national GHG inventory (Inventory of U.S. Greenhouse Gas Emissions and Sinks:
1990-2007, April 2009) WTE facilities emit very small amounts of GHG relative to other
electricity producing sources. Of total C02e emissions from the Combustion Source sector in
EPA's proposed reporting rule, waste-to-energy facilities account for only 0.55 percent. Unless a
facility is already equipped with both a stack gas volumetric flow rate monitor and a C02 CEM,
Tier 4 reporting should not be required. Instead facilities should be allowed to use the Tier 2
reporting method. Installation of these additional reporting methods will not extensively
improve the accuracy of the data reported, in a manner in which to justify the substantial
additional costs. SWANA requests consistency amongst all the stationary fuel combustion
sources and recommends that WTE be allowed to use the Tier 2 method to calculate their
emissions regardless of tons per day received.
Response: EPA appreciates your comment but has kept the 250 ton MSW/day size
determination. Both the 250 mmBtu/hr and 250 tons MSW/day are size determinations for
considering large sources in other EPA programs (40 CFR 60 Subpart Ea and Eb for Municipal
Solid Waste Combustors.). These size determinations were not considered to be directly
comparable, but rather to reflect consistency with other EPA programs. However, EPA believes
that it is appropriate to require the use of CEMS on the largest MSW combustion sources and
any smaller MSW combustion source which already has CO2 concentration monitors and stack
gas volumetric flow rate monitors in place.
Commenter Name: Kyle Pitsor
Commenter Affiliation: National Electrical Manufacturers Association (NEMA) Magnet Wire
Section
Document Control Number: EPA-HQ-OAR-2008-0508-0622.1
Comment Excerpt Number: 8
Comment: The NEMA Magnet Wire EHS Committee is supportive of EPA's thinking as to
allowing calculation of aggregate CO2 equivalents from oil-fired and/or gas-fired units
combusting the same fuel.
129
-------
Response: EPA appreciates this comment, and believes that the final rule includes further
clarification and flexibility regarding aggregation and common pipe provisions that will reduce
the burden on sources.
Commenter Name: Kyle Pitsor
Commenter Affiliation: National Electrical Manufacturers Association (NEMA) Magnet Wire
Section
Document Control Number: EPA-HQ-OAR-2008-0508-0622.1
Comment Excerpt Number: 7
Comment: The NEMA Magnet Wire EHS Committee requests greater clarification as to the
EPA's thinking about "reducing volume of waste by removing combustible matter" as it relates to
EPA's expectations for reporting C02 equivalents. Specific to the magnet wire industry as
related to stationary fuel combustion sources, magnet wire ovens generally serve two noteworthy
functions: production of useful heat and thermal treatment of solvent-laden gases. The NEMA
Magnet Wire EHS Committee believes that it would be reasonable to exclude CO2 equivalents
resulting from combustion of solvent-laden gases as a function of controlling volatile organic
compound (VOC) air emissions, and thus limit calculations in such cases to CO2 from
supplemental burner gas alone. This will focus the calculations, and the additional C02 from
combusting solvent-laden gases should be light relative to supplemental burner fuel. If,
however, EPA insists that C02 equivalents from combusting solvent-laden gases must be
included, then the reporting entity should be allowed to calculate CO2 emissions based on
engineering calculations of estimated chemical stoichiometry of typical solvents destroyed.
Response: EPA acknowledges the concerns of the commenter and has revised §98.33 to deal
with certain unconventional combustion processes and types of fuel. In the Preamble, EPA has
explained that "devices such as thermal oxidizers and pollution control devices . . . would report
only the GHG emissions from the firing of supplemental fossil fuels." EPA believes that these
provisions satisfy the intent of Part 98, to collect accurate and consistent GHG emissions data
that can be used to inform future decisions.
Commenter Name: Kyle Pitsor
Commenter Affiliation: National Electrical Manufacturers Association (NEMA) Magnet Wire
Section
Document Control Number: EPA-HQ-OAR-2008-0508-0622.1
Comment Excerpt Number: 6
Comment: Carbon dioxide (CO2) equivalent emissions from industrial boilers and process
heaters combusting natural gas and/or common industrial fuels (i.e., #2 and #6 fuel oil) should be
calculated using existing standard emission factors and/or fundamentals of chemical
stoichiometry. Demanding analysis for carbon content is excessive when calculating emissions
from burning natural gas and common industrial fuels in industrial boilers and process heaters,
and there is certainly no cause for warranting continuous emissions monitoring systems (CEMS)
for this exercise when considering industrial boilers and process heaters burning common
industrial fuels.
130
-------
Response: EPA has revised the rule to allow the use of Tier 2 methods (with default carbon
contents per HHV) for calculating emissions from units of any size in which the only fossil fuels
combusted are pipeline quality natural gas and/or distillate fuel oil. Furthermore, the mandatory
fuel sampling and analysis requirements for Tiers 2 and 3 have been considerably revised. The
final rule requires that natural gas be sampled semiannually. For fuel oil and coal, a
representative sampling is required for each fuel lot, i.e., for each shipment or delivery.
The Tier 4 CEMS requirement is limited to larger solid fossil fuel units with an existing pollutant
CEMS or volumetric flow rate monitor. EPA is requiring the use of CEMS due to the
complexity of monitoring solid fuel consumption and the heterogeneous nature of the solid fuels.
Many of these fossil fuel-fired units with a pollutant CEMS have an existing diluent monitor (O2
or C02) that can be used to determine C02 emissions.
Commenter Name: Traylor Champion
Commenter Affiliation: Georgia-Pacific, LLC (GP)
Document Control Number: EPA-HQ-OAR-2008-0508-0380.1
Comment Excerpt Number: 18
Comment: The proposed tiered approach for calculating emissions from stationary combustion
sources is complex and burdensome, and does not lead to better data. GP requests the use of Tier
1 for all emissions reporting. GP has experience in conducting GHG inventories according to
reputable protocols such as WRI/WBCSD and ISO 14064.1. We satisfactorily use the method of
activity data multiplied by default emission factors as used in these established protocols and
standards as well as The Climate Registry's (TCR) General Reporting Protocol, which is
analogous to EPA's proposed Tier 1 calculation methodology for general stationary combustion
sources. All these protocols and standards are accurate and sufficient. GP believes that CO2
continuous emissions monitoring systems (CEMS) should only be required for purposes of this
greenhouse gas reporting rule where the CO2 CEMS and stack gas volumetric flow rate monitors
are already installed as required by an applicable Federal or State regulation or the unit's
operating permit, similar to the proposed requirement under the Western Climate Initiative's,
Final Draft Essential Requirements of Mandatory Reporting for the Western Climate Initiative.
For all other cases, regardless of the fuel combusted or the size of the combustion units at a
facility, emission calculations should be based on the use of activity data, default emission
factors, and default HHVs (as applicable). This method is essentially EPA's proposed Tier 1
calculation methodology, which should apply to all incoming fuels, both fossil and biogenic,
"across the fence" rather than at the unit level. Unit specific data provides no additional value in
terms of facility emissions, yet add a significant and unnecessary reporting burden.
Response: See the Preamble, Section II. L., on General Monitoring Requirements for the overall
rationale for methodologies required under this rule, and the response to comment EPA-HQ-
OAR-2008-0508-0909.1 excerpt 4 and EPA-HQ-OAR-2008-0508-0580 excerpt 10 for the
rationale for methodologies required under Subpart C.
The Tier 4 CEMS requirement is limited to larger solid fossil fuel and MSW units with an
existing pollutant CEMS or volumetric flow rate monitor. EPA is requiring the use of CEMS
due to the complexity of monitoring solid fuel consumption and the heterogeneous nature of the
131
-------
solid fuels. Many of these fossil fuel-fired units with a pollutant CEMS have an existing diluent
monitor (O2 or CO2) that can be used to determine CO2 emissions.
EPA has attempted to reduce the burden on reporters using the Tier 2 and Tier 3 methodologies.
The mandatory fuel sampling and analysis requirements for Tiers 2 and 3 have been considerably
revised. EPA agrees with the commenters that for a homogeneous fuel such as pipeline natural
gas, monthly sampling is not necessary. For other fuels such as oil and coal, which are delivered
in shipments or lots, requiring monthly sampling may be impractical; new fuel lots or deliveries
may not be received on a monthly basis. Therefore, §98.34 has been revised to require that
natural gas be sampled semiannually. For fuel oil and coal, a representative sampling is required
for each fuel lot, i.e., for each shipment or delivery. For other liquid fuels and biogas, quarterly
sampling is required. For other solid fuels, excluding municipal solid waste, weekly composite
sampling with monthly analysis is required. For other gaseous fuels, the daily sampling
requirement has been retained, but only for facilities with existing equipment in place that is
capable of providing the data. Otherwise, weekly sampling is required. The final rule clarifies
that fuel sampling and analysis data provided by the supplier may be used in the emission
calculations, and that fuel billing meters may be used to quantify fuel consumption. To simplify
the emission calculations in Tiers 2 and 3, averaging of HHV and carbon content data is
permitted if these data are obtained at least at the minimum frequency specified in §98.34, but
less frequently than monthly (see §98.33(a)(2)(ii)). If sampling is more frequent, the reporter
must calculate a weighted average according to Equation C-2b. However, regardless of the
sampling frequency, the owner or operator must use the results of all available valid fuel
analyses in the emissions calculations.
EPA does not agree with the commenter's assertion that the amount of unit-level data and
verification information to be reported is excessive, burdensome, or unnecessary. For this
mandatory GHG emissions reporting rule, two main approaches to data verification were
considered, i.e., EPA verification and third-party verification. EPA decided on the former
approach. In view of this, additional, unit-level information is deemed necessary to provide
assurance that the reported facility-wide GHG emissions data are both credible and accurate.
However, EPA has dropped the cumulative 250 mmBtu/hr heat input capacity limit on the
aggregation of units. Rather, the 250 mmBtu/hr restriction applies only to the individual units in
the group. Therefore, for reporting purposes, individual units with maximum rated heat input
capacities of 250 mmBtu/hr or less may be aggregated without limit into a single group, provided
that the Tier 4 methodology is not required for any of the units, and all units in the group use the
same tier for any common fuel(s) that they combust. Units with maximum rated heat inputs
greater than 250 mmBtu/hr using Tiers 1, 2, and 3 must report as individual units, unless they
burn the same type of fuel, and the fuel is provided by a common pipe or supply line; in that
case, the owner or operator may opt to use the common pipe reporting provisions in
§98.36(c)(3). Units using Tier 4 must report as individual units unless they share a monitored
common stack or duct; in that case, the common stack or duct reporting provisions may be used.
132
-------
Commenter Name: Duplicate of 0481.2
Commenter Affiliation: Duplicate of 0481.2
Document Control Number: EPA-HQ-OAR-2008-0508-0506.2
Comment Excerpt Number: 5
Comment: In the Preamble, EPA states that flares, not explicitly identified in another subpart,
are to be reported under Subpart C. For most of the chemical industry that use flares, the carbon
content of the waste gases will not be listed in either Table C-l or C-2. Therefore, reporting of
flare greenhouse gas emissions would be done under Tier III of Subpart C, under which flares
would be treated the same as boilers or process heaters rather than as a unique source category.
The Tier III procedure is not consistent with the flare estimation procedures described in Subpart
Y for refinery flares, nor is it representative as drafted for these sources as explained below.
INVISTA recommends that the emission reporting for flares that are subject to Subpart C follow
a procedure that, to the extent applicable, follows the refinery flare methodology. When
adopting the refinery flare methodology, it is important to note that there are two major
differences between flares at chemical plants and those at refineries. First, for the non-refinery
industry, the higher heating value (HHV) of the fuel is not an accurate indicator of the carbon
content of the waste gas stream due to the high hydrogen content. Specifically, if a waste gas
stream has hydrogen as a constituent at significant levels, the heating value of the waste gas
stream will be high, but, the greenhouse gas emission rate will not increase. Facilities that have
hydrogen content in their waste gas streams cannot accurately use any of the existing formulas in
the proposed rule that are based on HHV. Second, the waste gas streams for chemical plants,
among other facility types, have the potential to contain many complex hydrocarbons. Given the
complexity of the waste gas streams, continuous monitoring of the carbon content may be widely
variable and technically challenging, if not infeasible. A gas chromatograph-based (GC) monitor
would have to be programmed to detect many potential components, lengthening the analysis
time and leading to smaller concentrations, thus decreasing accuracy of the monitoring results.
Given these monitor performance expectations, the GC will require more frequent maintenance
and consequent loss of monitor uptime. These factors indicate that a continuous monitoring of
carbon content is not a practical requirement for these waste gas streams. Finally, it is
anticipated that the flare contributions to a facility's overall greenhouse gas emissions will be
insignificant. Therefore, annual sampling of the waste gas streams is recommended and would
be sufficiently representative of carbon content, based upon the existing refinery flare calculation
procedures in Subpart Y, with modifications to address the differences between refinery and non-
refinery flares, discussed above. To address the concerns discussed above and to modify the
calculation procedures in Subpart Y, INVISTA recommends that EPA insert a new subparagraph
(c) in section 98.33, between existing subparagraphs (b) and (c); existing subparagraph (c) and
following subparagraphs would be changed accordingly. This inserted paragraph would specify
the greenhouse gas emission calculations for non-refinery flares based on the refinery flare
calculation procedure found in section 98.253(b). The recommended text would read as follows:
(c) For flares, calculate GHG emissions according to the requirements in paragraphs (b)(1) and
(2) of this section for combustion systems fired with process waste gases. (1) Calculate the CO2
emissions according to the applicable requirements in paragraphs (c)(l)(i) through (iii) of this
section, (i) Flow measurement. If you have a continuous flow monitor on the flare, you must
use the measured flow rates when the monitor is operational, to calculate the flare gas flow. If
you do not have a continuous waste gas flow monitor on the flare, or the flow monitor is down
during a waste gas combustion period, you must use engineering calculations, company records,
or similar estimates of volumetric flare gas flow, (ii) Carbon content. Complete annual carbon
133
-------
analysis of the combined waste gas stream being routed to the flare. Calculate the C02
emissions from the flare using Equation C-x. (iii) Startup, shutdown, malfunction. If you do not
measure the higher heating value or carbon content of the flare gas at least daily, determine the
quantity of gas discharged to the flare separately for periods of routine flare operation and for
periods of start-up, shutdown, or malfunction, and calculate the C02 emissions as specified in
paragraphs (c)(l)(iii)(A) and (B) of this section. (A) For periods of start-up, shutdown, or
malfunction, use engineering calculations and process knowledge to estimate the carbon content
of the flared gas for each start-up, shutdown, or malfunction event. (B) Calculate the CO2
emissions using Equation C-x of this section. [See submittal DCN: EPA-HQ-OAR-2008-508-
0506.2 for the equation and variables.]
Response: EPA has exempted flares from GHG emissions reporting under Subpart C, except
where reporting flare emissions is required under another subpart of the rule.
Commenter Name: W. Walter Tyler
Commenter Affiliation: INVISTA S.a r.l. (INVISTA)
Document Control Number: EPA-HQ-OAR-2008-0508-0481.2
Comment Excerpt Number: 5
Comment: Clarify emission calculation for Waste Gases to Flares at non-Refinery facilities. In
the Preamble, EPA states that flares, not explicitly identified in another subpart, are to be
reported under Subpart C. For most of the chemical industry that use flares, the carbon content
of the waste gases will not be listed in either Table C-l or C-2. Therefore, reporting of flare
greenhouse gas emissions would be done under Tier III of Subpart C, under which flares would
be treated the same as boilers or process heaters rather than as a unique source category. The
Tier III procedure is not consistent with the flare estimation procedures described in Subpart Y
for refinery flares, nor is it representative as drafted for these sources as explained below.
INVISTA recommends that the emission reporting for flares that are subject to Subpart C follow
a procedure that, to the extent applicable, follows the refinery flare methodology. When
adopting the refinery flare methodology, it is important to note that there are two major
differences between flares at chemical plants and those at refineries. First, for the non-refinery
industry, the higher heating value (HHV) of the fuel is not an accurate indicator of the carbon
content of the waste gas stream due to the high hydrogen content. Specifically, if a waste gas
stream has hydrogen as a constituent at significant levels, the heating value of the waste gas
stream will be high, but, the greenhouse gas emission rate will not increase. Facilities that have
hydrogen content in their waste gas streams cannot accurately use any of the existing formulas in
the proposed rule that are based on HHV. Second, the waste gas streams for chemical plants,
among other facility types, have the potential to contain many complex hydrocarbons. Given the
complexity of the waste gas streams, continuous monitoring of the carbon content may be widely
variable and technically challenging, if not infeasible. A gas chromatograph-based (GC) monitor
would have to be programmed to detect many potential components, lengthening the analysis
time and leading to smaller concentrations, thus decreasing accuracy of the monitoring results.
Given these monitor performance expectations, the GC will require more frequent maintenance
and consequent loss of monitor uptime. These factors indicate that a continuous monitoring of
carbon content is not a practical requirement for these waste gas streams. Finally, it is
anticipated that the flare contributions to a facility's overall greenhouse gas emissions will be
insignificant. Therefore, annual sampling of the waste gas streams is recommended and would
134
-------
be sufficiently representative of carbon content, based upon the existing refinery flare calculation
procedures in Subpart Y, with modifications to address the differences between refinery and non-
refinery flares, discussed above. To address the concerns discussed above and to modify the
calculation procedures in Subpart Y, INVISTA recommends that EPA insert a new subparagraph
(c) in section 98.33, between existing subparagraphs (b) and (c); existing subparagraph (c) and
following subparagraphs would be changed accordingly. This inserted paragraph would specify
the greenhouse gas emission calculations for non-refinery flares based on the refinery flare
calculation procedure found in section 98.253(b). The recommended text would read as follows:
(c) For flares, calculate GHG emissions according to the requirements in paragraphs (b)(1) and
(2) of this section for combustion systems fired with process waste gases. (1) Calculate the CO2
emissions according to the applicable requirements in paragraphs (c)(l)(i) through (iii) of this
section, (i) Flow measurement. If you have a continuous flow monitor on the flare, you must
use the measured flow rates when the monitor is operational, to calculate the flare gas flow. If
you do not have a continuous waste gas flow monitor on the flare, or the flow monitor is down
during a waste gas combustion period, you must use engineering calculations, company records,
or similar estimates of volumetric flare gas flow, (ii) Carbon content. Complete annual carbon
analysis of the combined waste gas stream being routed to the flare. Calculate the C02
emissions from the flare using Equation C-x. (iii) Startup, shutdown, malfunction. If you do not
measure the higher heating value or carbon content of the flare gas at least daily, determine the
quantity of gas discharged to the flare separately for periods of routine flare operation and for
periods of start-up, shutdown, or malfunction, and calculate the C02 emissions as specified in
paragraphs (c)(l)(iii)(A) and (B) of this section. (A) For periods of start-up, shutdown, or
malfunction, use engineering calculations and process knowledge to estimate the carbon content
of the flared gas for each start-up, shutdown, or malfunction event. (B) Calculate the CO2
emissions using Equation C-x of this section [See DCN: EPA-HQ-OAR-2008-0508-0481.2 for
equation calculating CO2 emissions from flare gas].
Response: EPA has exempted flares from GHG emissions reporting under Subpart C, except
where reporting flare emissions is required under another subpart of the rule.
Commenter Name: Duplicate of 0481.2
Commenter Affiliation: Duplicate of 0481.2
Document Control Number: EPA-HQ-OAR-2008-0508-0506.2
Comment Excerpt Number: 2
Comment: Like many other companies, INVISTA has taken steps to determine estimates of
total GHG emissions through established industry standards and protocols that utilize fuel
consumption data and recognized emission factors. For example, the Climate Registry (TCR),
the WRI/WBCSD and ISO 14064.1 standards and protocols utilize well-recognized and well-
established default emission factors for estimating GHG emissions that are comparable to the
proposed methodology in Tier 1 of the Proposed Rule. This data has shown to be a reliable
indicator, not only for tracking inventory and product manufacturing costs, but also in some
instances for emissions estimates needed under other environmental regulatory programs, such as
the Clean Air Act's Title V program. The Proposed Rule, however, specifies a 4-Tier reporting
structure that is much more complex than other GHG reporting systems. The requirements in the
Proposed Rule - including enhanced direct emissions monitoring, total carbon content analysis,
and fuel-flow meters - demand significant additional investments at manufacturing sites with
little gain in accuracy of emissions estimates over that which can be obtained by using current,
135
-------
accepted industry practice. In addition, the Tier 3 and 4 categories require an unspecified level
of precision and accuracy to estimate and report GHG emissions based upon devices,
measurements, or data that either do not exist currently at many facilities or have not been used
historically for reporting or compliance purposes. For example, many facilities subject to this
rule back-calculate fuel usage based on accepted industry standards and techniques such as
inventory reconciliation, steam flow, or process knowledge which have been used for other
reporting and accounting purposes. If EPA determines that this proposed Tiered approach is the
preferred vehicle for reporting, then INVISTA recommends that EPA clarify that current
industry standards and practice, such as inventory reconciliation, are within the meaning and
intent of "company records" upon which many of the emission calculations in the Proposed Rule
are based. However, simplifying the current scheme and basing it on recognized reporting
methodologies, such as default emission factors, will alleviate much of the uncertainty in the
Rule while sacrificing little if any of the accuracy EPA hopes to achieve in this reporting
scheme. For these reasons, INVISTA recommends that Tier I methodology be adopted for all
source categories.
Response: See the Preamble, Section II. L., on General Monitoring Requirements for the overall
rationale for methodologies required under this rule, and the response to comment EPA-HQ-
OAR-2008-0508-0909.1 excerpt 4 and EPA-HQ-OAR-2008-0508-0580 excerpt 10 for the
rationale for methodologies required under Subpart C.
EPA has significantly expanded the use of Tier 1 and Tier 2 Calculation Methodologies. The
250 mmBtu/hr restriction on the use of Tier 2 has been lifted for units in which the only fossil
fuels combusted are natural gas and/or distillate oil, in view of the homogeneous nature of these
fuels. Most units combusting the biogenic fuels in Table C-l may use Tier 1. However, the 250
mmBtu/hr unit size cutoff remains for units that combust other fuels. EPA has considerably
revised the Tier 2 and Tier 3 fuel sampling requirements in an effort to reduce the burden on
reporters. Furthermore, the final rule clarifies that fuel sampling and analysis data provided by
the supplier may be used in the emission calculations, and that fuel billing meters may be used to
quantify fuel consumption.
EPA has defined the term "company records" in §98.6 of the final rule. EPA believes that the
revised definition provides appropriate guidance as to what records a facility may use to
determine fuel consumption.
Commenter Name: Edward N. Saccoccia
Commenter Affiliation: Praxair Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-0977.1
Comment Excerpt Number: 2
Comment: The proposed rule defines the applicability of the alternate calculation method
"tiers" based on combustion unit size and availability of data, with a general trend to require
more rigorous calculation methods (e.g. increasing from Tier 1 to Tiers 2, 3, and 4) for higher
operating capacity units and facilities that currently employ certain process or emission
measurements. Higher tiers often require a more costly, laborious measurement/calculation
method that does not improve the accuracy or completeness of the emission estimate. In many
instances, less rigorous calculation methods (e.g. "lower" Tiers) will yield comparable (or better)
136
-------
accuracy emission estimates, with higher reliability and at lower cost. There is an implied
assumption that directly measured emissions will yield a better emission estimate. This
presumption is not true, as evidenced by an acceptable level of (in)accuracy tolerance under
CEMS certification/calibration procedures (> 5 - 7%) versus levels of fuel consumption metering
employed for invoice billing (typically < 2%). EPA has previously recognized the concept of
approving alternative monitoring approaches under the New Source Performance Standards
(NSPS), 40 CFR Part 60, and the MACT regulations found at 40 CFR Part 63. This program has
shown to be highly successful in providing an adequate balance between regulatory flexibility
for the operating facilities and the need for rigorous process monitoring for compliance
demonstration purposes. However, EPA has not included this allowance in the current proposed
rule. EPA should allow more flexibility as it relates to the applicability to the alternate
combustion emission calculation methods. In particular: 1. Allow use of the Tier 1 method for
units of any size (currently restricted to units < 250 mmBTU/hr or less), particularly for standard
fuels of commerce such as natural gas, LP gas and fuel oils, where billing-quality consumption
data is accurate and readily available and the default HHV and C02 emission factors are well
known constants (as noted in the Preamble for the proposed rule - natural gas carbon content is
always within 1% of the default ratio). 2. Do not require the use of the Tier 4 method where
alternative fuel consumption data is available. Allow optional use of the Tier 4 method where, at
the source's discretion. This may be a suitable calculation method where a source uses multiple
fuels and/or non-commercial fuels or where existing CEMS systems include CO2 measurement
or can be modified at lower cost than alternative fuel consumption and/or characterization
devices/practices. In any case, let the regulated source determine which method is most cost
effective for their particular situation. This option is available in California's GHG mandatory
reporting program. 3. EPA should incorporate into the final rule a mechanism for authorizing
alternative monitoring plan requests submitted on a facility by facility basis consistent with its
current program under NSPS and MACT.
Response: See the Preamble, Section II. L., for the response on the general monitoring
approach.
EPA did not choose to adopt a simplified calculation method approach (e.g., using default
emission factors) for all units because the data would be less accurate than under the selected
option and would not make use of site-specific data that many facilities already have available
and refined calculation approaches that many facilities are already using. Methodologies that
reflect the variability of fuels across units and facilities through sampling and measurement are
more accurate than methodologies that do not account for this variability. The gains from
measurement vary by fuel type (i.e., heterogeneity of carbon content and heat rate is lower in
some fuels) and the final rule accounts for this difference by varying the requirements for units,
with due consideration of burden and cost.
EPA has significantly expanded the use of Tier 1 and Tier 2 Calculation Methodologies. The
250 mmBtu/hr restriction on the use of Tier 2 has been lifted for units that combust only natural
gas and/or distillate oil, in view of the homogeneous nature of these fuels. Units of any size
combusting only biomass fuels listed in Table C-l may use Tier 1 methods. However, the 250
mmBtu/hr unit size cutoff remains for units that combust other fuels.
The Tier 4 CEMS requirement is limited to larger solid fossil fuel units with an existing pollutant
CEMS or volumetric flow rate monitor. EPA is requiring the use of CEMS due to the
complexity of monitoring solid fuel consumption and the heterogeneous nature of the solid fuels.
137
-------
Many of these fossil fuel-fired units with a pollutant CEMS have an existing diluent monitor (02
or CO2) that can be used to determine CO2 emissions.
Commenter Name: Ted Michaels
Commenter Affiliation: Energy Recovery Council (ERC)
Document Control Number: EPA-HQ-OAR-2008-0508-0544.1
Comment Excerpt Number: 1
Comment: All Municipal Waste Combustors Should be Allowed to use the Tier 2 Calculation
Methodology for Reporting GHG Emissions under the Mandatory Reporting Rule (MRR) The
MRR proposes to require all municipal waste combustors (MWC) with a maximum rated input
capacity of greater than 250 tons per day of MSW to use the Tier 4 calculation methodology.
This requirement is problematic as it does not reflect current regulatory requirements or best
management practices for MWCs. In addition, it will be very costly and while failing to result in
commensurate enhancements in reporting accuracy. Further, the GHG emission calculation
methodology imposed on MWCs is out of proportion to the sector's relative GHG emissions
when compared to other electricity generators. As we note below, other GHG reporting
programs allow MWCs to use the Tier 2 calculation methodology. In fact, EPA proposes in the
MRR to allow fossil fuel-fired, stationary combustion sources with far greater GHG emissions
than MWCs to use the Tier 2 calculation methodology. We urge the Agency to reconsider
requiring MWCs to use the Tier 4 methodology and recommend that MWCs use a modified Tier
2 methodology analogous to the Title V program methods used for annual reporting of criteria
pollutants and hazardous air pollutants (HAP). MWCs, Also Known as Waste To Energy (WTE)
Facilities are Very Small Emitters of GHG EPA's most recent national GHG inventory
(Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007, April 2009) reports WTE
facilities emit very small amounts of GHG relative to other electricity producing sources.
Municipal waste combustors account for only 0.34 percent of total CO2 equivalent emissions
from all Energy Related Activities (20.8 Tg CC^e from a total of 6170.3 Tg CC^e from the
entire source category) and only 0.55 percent of total CC^e emissions from the Combustion
Source sector in EPA's proposed reporting rule. Based on WTE's relatively small contribution to
GHG emissions in their sector, ERC suggests that more flexible and cost effective GHG
reporting requirements are appropriate and would result in data of sufficient accuracy and
reliability to meet EPA's needs. The Western Climate Initiative Mandatory Reporting
Requirements and the U.S. Department of Energy's 1605 (b) Voluntary Reporting Program
Employ Tier 2 Calculation Methods The Tier 4 calculation methodology proposed in the
mandatory reporting rule is very similar to the initial method proposed in the January 2009 draft
Western Climate Initiative (WCI) Mandatory Reporting Requirements. Subsequently in May
2009, after extensive public comments, the WCI concluded that requiring the installation of
CEM components for CO2 and stack gas flow measurement at facilities, which had not
previously installed them, was extremely onerous and expensive and would not improve overall
reporting accuracy. Accordingly, the WCI adopted a methodology for the General Stationary
Combustion category that eliminated the use of 40 CFR Part 75 type CEMS unless a unit was
already equipped with both a stack gas volumetric flow rate monitor and a CO2 CEM. WCI also
eliminated the use of Part 75 CEMS for municipal solid waste combustion units and established
the use of Tier 2 calculation methodologies. The U.S. Department of Energy (DOE) 1605(b)
Voluntary Reporting program offers similar flexibility in its "A-Rated Measurement and
Estimation Method" for stationary combustion sources. The DOE approach includes: 1. Use of
138
-------
continuous direct measurement of C02 at facilities that have already installed CEMs for C02; 2.
Use of emission factors based on multiple, regularly repeated, on-site direct measurement of
source emissions; and 3. Use of measured source activity data (e.g., amount of MSW processed,
steam production) ERC recommends that EPA incorporate similar requirements for municipal
waste combustors in the final MMR. As WCI concluded, accurate annual GHG emissions result
when using the Tier 2 calculation methodology, including use of actual steam generation or
waste throughput data, C02 emission factors, heat input to steam output or stack flow rate to
steam output ratios, and fuel HHV. The Proposed 250 Tons Per Day (tpd) Threshold for
Applying the Tier 4 Methodology to MWCs is Inappropriate and Inequitable EPA is proposing
to require MWC units with a maximum rated capacity of greater than 250 tons per day of MSW
to use the Tier 4 methodology, while other stationary combustion units of 250 MMBtu/hr may
use Tier 2. ERC recommends that the EPA allow large and small capacity MWCs to use the Tier
2 calculation methodologies, particularly as MWCs have significantly lower GHG emissions
than the 250 MMBtu/hr combustion sources as shown in Table 1. [See submittal for data table
provided by commenter.] It is readily apparent that a 250 ton per day MWC emits only 18
percent of the C02 emitted by a 250 MMBtu/hr oil-fired unit or only 25 percent of the C02
emitted by a gas-fired combustion unit. Even a larger, 750 ton per day municipal waste
combustor emits only 54 percent as much as a 250 MMBtu/hr oil-fired combustion unit and 75
percent as much C02 as a 250 MMBtu/hr gas-fired combustion unit. Consequently, a large
MWC unit's cost to implement the Tier 4 methodology is disproportionate with respect to their
relative GHG emissions. In addition, unlike typical 250 MMBtu combustion units, MWCs are
subject to extensive source testing, and requirements to install Part 60 CEMS equipment that
provides accurate and reliable GHG reporting. We question the need to impose costly,
alternative monitoring equipment on these relatively small sources, particularly when far larger
sources may utilize the far less expensive Tier 2 methods.
Response: EPA believes that it is appropriate to require the use of CEMS on the largest MSW
combustion sources, provided that all of the criteria in §98.33(b)(4)(ii) or (iii) are met. EPA has
kept the 250 ton MSW/day size determination. Both the 250 mmBtu/hr and 250 tons MSW/day
are size determinations for considering large sources in other EPA programs (General Stationary
Combustion Technical Support Document, EPA-HQ-OAR-2008-0508-0004). These size
determinations were not considered to be directly comparable, but rather to reflect consistency
with other EPA programs, particularly where the challenge of monitoring is substantially
different, as it is for MSW versus more homogenous fossil fuels.
EPA believes that it is appropriate for MSW combustion units to use ASTM D6866-06a and
D7459-08 on a quarterly basis to determine the relative proportions of biogenic and non-biogenic
C02 emissions from the MSW combusted. Where Tier 2 is used, EPA has provided for MSW
combustion units to determine total C02 emissions from the amount of steam produced, boiler
design, and a default C02 emission factor. EPA believes that this is more appropriate than
determining site-specific factors during annual testing. Where Tier 4 is used, C02 emissions are
determined using a C02 concentration monitor and a stack gas volumetric flow rate monitor.
EPA does not believe that it is appropriate to estimate stack flow based on steam production in
Tier 4. Biogenic emissions for the MSW combustion unit are then calculated by multiplying the
total C02 emissions for the year, determined using Tier 2 or 4, by the fraction of biogenic
emissions, determined using the ASTM methods.
139
-------
Commenter Name: Lawrence W. Kavanagh
Commenter Affiliation: American Iron and Steel Institute (AISI)
Document Control Number: EPA-HQ-OAR-2008-0508-0695.1
Comment Excerpt Number: 7
Comment: Tier 2 relies on monthly measured heat values and default emission factors (from
Tables C-l or C-2), and the quantity of fuel combusted based on company records. Tier 3
requires the use of monthly measurements for fuel carbon content, molecular weight, and fuel
quantities. However, we believe that both of these requirements are unnecessary and believe that
Tier 1 (based on annual emissions and default emission factors) is an acceptable calculation
methodology for the following reasons. Requirements for efficient and productive operation of
coke ovens and rigid specifications for coke quality dictate a very stable operation - from the
blending of coal charged into the oven to heating practices. This means that the chemistry and
heating value of coke oven gas and the resulting products of combustion will be fairly consistent
over time. Accordingly, if reporting of coke oven combustion stack CO2 emissions is retained in
the final rule, we respectfully request that Tier 1 methodology apply. Total annual C02
emissions can be determined with sufficient certainty and accuracy by averaging routine coke
oven gas carbon analyses or documented default values and known coke oven gas consumption
rates. However, since the frequency and type of sampling and analysis of coke oven gas
employed by coke producers varies substantially from company to company, we urge EPA not to
specify the sampling frequency in the rule. We believe the incentive for companies to sample
and analyze the gas for operational purposes is sufficient for establishing a basis for GHG
reporting.
Response: EPA has retained the requirement to use the Tier 3 methodology for large 250
mmBtu/hr units that combust gaseous fuels other than natural gas and biogas. Methodologies
that reflect the variability of fuels across units and facilities through sampling and measurement
are more accurate than methodologies that do not account for this variability. The gains from
measurement vary by fuel type (i.e., heterogeneity of carbon content and heat rate is lower in
some fuels) and the final rule accounts for this difference by varying the requirements for units,
with due consideration of burden and cost. Process gas potentially has more variability over
time, compared to a consistent commercial fuel like natural gas or distillate fuel oil, indicating
that Tier 1 would be less accurate than higher tiers. A higher tier for process gases over
commercially marketed fuels is consistent with the EU ETS, and CARB program.
The daily sampling requirement has been retained, but only for facilities with existing equipment
in place that is capable of providing the data. Otherwise, weekly sampling is required.
Commenter Name: Lawrence W. Kavanagh
Commenter Affiliation: American Iron and Steel Institute (AISI)
Document Control Number: EPA-HQ-OAR-2008-0508-0695.1
Comment Excerpt Number: 5
Comment: If it is EPA's intent to require duplicative reporting of emissions from coke oven
combustion stacks, we urge other considerations. Coke ovens are unique and unlike traditional
combustion sources such as boilers, incinerators or process heaters. Heat is transferred to the
140
-------
coking chamber of individual ovens indirectly through refractory walls from a combustion
chamber or flue. Each oven has multiple burners firing coke oven gas or a blend of coke oven
gas and blast furnace gas, and a coke battery contains multiple ovens. Combustion products are
collected in a gas main and discharged through a stack serving the entire battery. Since the total
heat input at a typical coke battery exceeds 250 MMBTUH for all ovens combined, Subpart C
would require the use of Tier 2 or Tier 3 calculation methodology.
Response: EPA intends that the stationary combustion source category include any device that
meets the definition included in §98.30 for which emissions are not accounted for in the report
through a separate subpart of the rule. Per the requirements in 40 CFR Part 98, Subpart A,
facilities have to report GHG emissions from all source categories located at their facility,
including stationary combustion and process emissions. EPA does not intend that emissions be
double reported, and has revised the various subparts of the final rule to clarify the intent of the
stationary combustion source category. EPA understands that if process and combustion
emissions are not easily or logically separated, that combustion emissions may be reported in
combination with process emissions, as in the case of coke ovens and in the use of blast gas.
EPA has also removed the cumulative 250 mmBtu/hr restriction on unit aggregation, and has
clarified the common pipe reporting option for use where a metered pipe serves the same fuel to
multiple units.
Commenter Name: Dale Backlund, Regulatory Affairs Leader, The DOW Chemical Company
and Victoria Evans, National Practice Leader for Greenhouse Gases, URS Corporation
Commenter Affiliation: None
Document Control Number: EPA-HQ-OAR-2008-0508-1338
Comment Excerpt Number: 5
Comment: The tier system would function more efficiently if EPA were to set emissions
thresholds over which individual source emissions were required to be reported under data Tier 3
or Tier 4; below those thresholds, data Tiers 3 or 4 would be optional.
Response: EPA has retained capacity based thresholds as they apply to the use of tiers, but has
revised the final rule to allow aggregated reporting for any number of units, each of which has a
maximum rated heat input capacity of 250 mmBtu/hr or less. EPA has also increased the
flexibility of the tier system, allowing more reporters to use the lower tiers. Tier 4 is not required
unless all of the criteria in §98.33(b)(4)(ii) or (iii) are met, and Tier 3 is required only for units
with a maximum rated heat input capacity greater than 250 mmBtu/hr meeting the other
specified criteria.
141
-------
Commenter Name: Geoffrey Cullen
Commenter Affiliation: Can Manufacturers Institute (CMI)
Document Control Number: EPA-HQ-OAR-2008-0508-0703.1
Comment Excerpt Number: 5
Comment: For facilities that will be covered by the reporting requirements, CMI supports
allowing the use of utility bills to calculate the amount of natural gas combusted.
Response: EPA appreciates your comments and has changed the final rule to allow natural gas-
fired units of any size to use Tier 2 calculations, in which company records are used to determine
fuel use. A definition of "company records," as it pertains to quantifying fuel consumption, has
been added to §98.6. It specifies that fuel billing meters may be used to quantify fuel
consumption. Furthermore, the final rule specifies that fuel billing meters may be used to
quantify the use of liquid and gaseous fuels in Tier 3.
Commenter Name: Jay M. Dietrich
Commenter Affiliation: IBM
Document Control Number: EPA-HQ-OAR-2008-0508-0978.1
Comment Excerpt Number: 5
Comment: IBM is supportive of the proposed measurement and calculation methods for
determining the C02 emissions from fuel use. The combustion unit size distinctions are
appropriate for IBM operations and the proposed CO2 emissions calculation methods are
reasonable. For fossil liquid fuel, IBM would recommend a variation on the Tier 1 methodology.
IBM uses fossil liquid fuel as a back-up fuel to its natural gas supply. Depending on the weather,
supply availability and contract requirements, facilities burn varying quantities of fuel during a
heating season. Higher heating values (HHVs) are provided by the supplier with each shipment
of fuel, and the estimated HHV for the storage tank is calculated on a periodic basis using this
data. The proposed recommendation would be to establish a Tier la methodology by which a
company could update the HHV value of its storage tank on a monthly basis based on the fuel
shipment volumes, the supplier's HHV for the shipment, and the current, calculated HHV value
of the tank. Contact Jay Dietrich at idietric@us.ibm.com for additional information on this
proposal.
Response: EPA has modified the sampling requirements for oil or other fuels received in lots.
Rather than a monthly sample, a representative sample for each shipment or delivery is now
required, and the final rule clarifies that fuel sampling and analysis data provided by the supplier
may be used in the emission calculations.
142
-------
Commenter Name: Chris Greissing
Commenter Affiliation: Industrial Minerals Association - North America (IMA-NA)
Document Control Number: EPA-HQ-OAR-2008-0508-0705.1
Comment Excerpt Number: 5
Comment: The manner in which the proposed rule is currently drafted, it is unclear whether all
of the described conditions must be applicable before the Tier 4 Calculation is mandatory, or if
just a single condition is all that is necessary. This language should be clarified. We would also
request that all of the described conditions must be applicable before Tier 4 Calculation is
mandatory. If only one condition is necessary, this would result in potentially huge costs to the
industry, as continuous emissions monitoring systems are extremely expensive to install. IMA-
NA proposes the following language be inserted at §98.33 (b)(5)(ii) of the proposed rule: "Shall
be used for a unit if all of the conditions below are met:"
Response: EPA acknowledges the commenters' concerns regarding Tier 4 applicability. EPA
has revised §98.33(b)(4)(ii) of the final rule to clarify that all six criteria specified in
subparagraphs (A) through (F) must be met before Tier 4 is required.
Commenter Name: H. Allen Faulkner
Commenter Affiliation: Ascend Performance Materials, LLC, Decatur Plant
Document Control Number: EPA-HQ-OAR-2008-0508-1578
Comment Excerpt Number: 5
Comment: Ascend Decatur facility uses the following method for determining the coal usage
for the site's boilers and coking units: (1) Monthly physical coal inventory taken via coal yard
and bunker observations; (2) Daily BTU output and coke production yields are reconciled
monthly; (3) Removal of coal used during month is taken from accounting closure; (4) Annual
physical coal inventory is taken at 12 noon on September 30 of each year by way of a flyover;
and (5) Monthly reconciliation is based on usage, bunkers and coal deliveries. While this
method has proven to be extremely accurate, it is subjective and does not rely on weighing
equipment or fuel flow meters. Therefore, calibrations are not practical. Ascend is requesting
that the current language be revised to be less restrictive and allow a facility to use methods such
as described above.
Response: EPA has retained the provisions in Tier 3 allowing facilities to determine solid fuel
combustion using company records for the purposes of Tier 3 calculations. EPA has defined the
term "company records" in §98.6 of the final rule, and believes that the revised definition
provides appropriate guidance as to what records a facility may use to determine fuel
consumption. EPA believes that these provisions provide an appropriate balance between
reducing the reporting burden and gathering accurate data.
143
-------
Commenter Name: H. Allen Faulkner
Commenter Affiliation: Ascend Performance Materials, LLC, Decatur Plant
Document Control Number: EPA-HQ-OAR-2008-0508-1578
Comment Excerpt Number: 4
Comment: Ascend Decatur Alabama Plant combusts several chemical byproduct wastes,
generated on-site, as fuels in stationary fuel combustion units. 98.33(c)(4) requires a site to
develop site specific CH4 and N20 emission factors for each fuel. Ascend is requesting that
EPA develop guidance for the development of these factors. Are factors based on process
conditions, chemistry and thermodynamics sufficient and acceptable or would source testing be
required?
Response: EPA acknowledges the commenter's concerns, and has revised the rule to state that
any fuels for which default emission factors are not provided can be excluded from calculations
of CH4 and N2O. EPA is no longer requiring facilities which combust other fuels to develop
site-specific emission factors, and thus does not believe it is necessary to provide any guidance in
this matter.
Commenter Name: Thomas M. Ward
Commenter Affiliation: Novelis Corporation
Document Control Number: EPA-HQ-OAR-2008-0508-0561.1
Comment Excerpt Number: 6
Comment: The use of fuel-specific emission factors for fuel combustion sources is sufficient to
meet the goals and objectives of the reporting protocol and should be incorporated in the
proposed rule. Since EPA has already developed and established such a reporting mechanism
under the Climate Leaders program (i.e. Stationary Source Combustion Guidance) that has been
successfully used by a collection of industries for most of the past decade, it is reasonable to
adopt this proven approach here as well. Accordingly, EPA should incorporate the Climate
Leaders stationary combustion source reporting guidance in the mandatory GHG reporting
program for three important reasons: (1) it provides a suitable technical means to ensure
continuity of data for reporting that is accurate and cost-effective; (2) it provides continuity with
the industries that have been reporting and will continue to report under the Climate Leaders
program, and thereby reduce reporting confusion that might come with enacting differing
reporting and recordkeeping requirements. (3) it is consistent with international reporting
requirements. In summary, Novelis supports adoption of Climate Leaders protocol for all the
preceding reasons but also to the extent that it is a recognition of the proactive efforts of Climate
Leader participants that pursued emission reduction through the implementation of related
programs, while not unfairly benefiting those parties or facilities that have chosen not to
participate in voluntary beneficial GHG reduction programs.
Response: See the Preamble, Section II. O., for the response on the relationship of this rule to
other programs. The reporting requirements under the voluntary Climate Leaders partnership
were created in the context of that specific voluntary program, with different goals and
requirements than reporting under the Clean Air Act.
See the Preamble, Section II. L., for the response on the general monitoring approach.
144
-------
EPA did not choose to adopt a simplified calculation method approach (e.g., using default
emission factors) for all units because the data would be less accurate than under the selected
option and would not make use of site-specific data that many facilities already have available
and refined calculation approaches that many facilities are already using. Methodologies that
reflect the variability of fuels across units and facilities through sampling and measurement are
more accurate than methodologies that do not account for this variability. The gains from
measurement vary by fuel type (i.e., heterogeneity of carbon content and heat rate is lower in
some fuels) and the final rule accounts for this difference by varying the requirements for units,
with due consideration of burden and cost.
Commenter Name: Angela Burckhalter
Commenter Affiliation: Oklahoma Independent Petroleum Association (OIPA)
Document Control Number: EPA-HQ-OAR-2008-0508-0386.1
Comment Excerpt Number: 22
Comment: EPA needs to allow reporters to use best estimates so they don't have to install fuel
flow meters on each of their combustion sources.
Response: EPA has considerably revised §98.33(b), describing which tier a reporter is to use.
Tier 2, which allows facilities to determine fuel use from company records, is now applicable to
units of any size in which the only fossil fuels combusted are pipeline quality natural gas and/or
distillate fuel oil. Units with a maximum rated heat input capacity less than 250 mmBtu/hr,
combusting any fuel for which default values are provided, may also report using Tier 1 or Tier
2, and may determine fuel use through company records. EPA has defined the term "company
records" in §98.6 of the final rule, and believes that the revised definition provides appropriate
guidance as to what records a facility may use to determine fuel consumption. While fuel flow
meters may be used where company records are required, they are certainly not mandatory. EPA
has also clarified in the final rule that fuel billing meters may be used for the purpose of directly
measuring combustion of liquid and gaseous fuels in Tier 3. Meanwhile, EPA has retained the
provisions in Tier 3 allowing facilities to determine fuel oil consumption using tank drop
measurements and solid fuel combustion using company records for the purposes of Tier 3
calculations. EPA believes that these provisions provide an appropriate balance between
reducing the reporting burden and gathering accurate data.
Commenter Name: Susan Amodeo Cathey
Commenter Affiliation: Air Liquide USA, LLC
Document Control Number: EPA-HQ-OAR-2008-0508-0464.1
Comment Excerpt Number: 6
Comment: The Proposed Rule defines the emissions calculations deemed by EPA as
appropriate for hydrogen production facilities, however, the applicability of which "tier" of
calculation method required needs to be clarified. The proposed rule identifies 4 tiers of
calculation methods with each successive tier requiring more rigorous requirements. EPA
should modify the language in the proposed rule to remove the apparently unintended
requirement for all facilities to use the most rigorous Tier 4 calculation method. The proposed
145
-------
language would imply that all affected sources would be required to use the most rigorous
calculation method imposed by Tier 4. Instead EPA should clarify that only the most significant
of sources (i.e. utilities) should be required to use Tier 4, while other less significant sources (i.e.
H2 plants) should be able to use one of the other, less rigorous calculation methods.
Response: EPA acknowledges the commenters' concerns regarding Tier 4 applicability. EPA
has revised the final rule to clarify that all of the criteria specified in §98.33 (b)(4)(ii) or (iii) must
be met before Tier 4 is required.
Commenter Name: Lorraine Krupa Gershman
Commenter Affiliation: American Chemistry Council (ACC)
Document Control Number: EPA-HQ-OAR-2008-0508-0423.2
Comment Excerpt Number: 40
Comment: EPA has not provided a de minimis threshold below which the greenhouse gas
emissions from a stationary combustion source can be determined using simplified emission
estimation techniques. The emissions from the de minimis combustion units would still be
reported. However, the de minimis exemption would avoid the very costly and unnecessary
requirement to install flowmeters and perform frequent monitoring on truly insignificant sources
such as comfort hot water heaters, gas furnaces for buildings, gas stoves, etc. ACC recommends
that EPA add a de minimis threshold in §98.31 or §98.32 to allow for the use of simplified
emission estimates for emissions from equipment whose emissions fall under the threshold
which we recommend to be at least 3 MM Btu/hour.
Response: See the Preamble, Section II. K., for the response on de minimis reporting for small
emission points.
EPA does not agree that there should be a de minimis emissions exclusion. EPA's general
approach across the entire rule was not to establish de minimus thresholds, and to require
reporting for any source where methods are given. For data collection for future policies, it is
important to understand the full suite of stationary combustion sources and the fuels being
consumed regularly at a facility — future policies could then provide exemptions or not. Setting
a minimum heat capacity rating would add unnecessary complexity to the rule because there
would need to be additional cumulative limitations on the amount of units that could be
exempted under a heat capacity threshold. This is why EPA is allowing aggregation of units for
all units < 250 mmBtu/hr with no limitation on the combined heat input capacity of those units
(versus a more complex exemption of all units <10 mmBtu/hr but not in excess of a combined
heat input of > 250 mmBtu/hr, for example).
However, the commenter should note that the rule excludes portable equipment, as defined in
§98.6, emergency generators and emergency equipment, as defined in §98.6, and irrigation
pumps at agricultural operations. Additionally, most units smaller than 250 mmBtu/hr may
report using Tier 1 or Tier 2, which do not require fuel flow meters. EPA has also revised the
Tier 2 and Tier 3 sampling requirements to reduce the burden on reporters. EPA has also
removed the cumulative 250 mmBtu/hr restriction on unit aggregation, and has clarified the use
of common pipe metering. EPA believes that the expanded availability of these options will
reduce the reporting burden on facilities.
146
-------
Commenter Name: Jeff A. Myrom
Commenter Affiliation: MidAmerican Energy Holdings Company
Document Control Number: EPA-HQ-OAR-2008-0508-0581.1
Comment Excerpt Number: 29
Comment: MidAmerican believes that using the fuel heating value is reasonable given that it is
a test that is much more commonly run on fuels than carbon content.
Response: EPA appreciates the commenter's support, and has significantly expanded the use of
the Tier 2 calculation methodology based on fuel heating value for units that combust pipeline
quality natural gas and/or distillate oil, in view of the homogeneous nature of these fuels.
However, the Tier 3 methodology which includes carbon content measurements is still required
for units with a maximum rated heat input capacity greater than 250 mmBtu/hr that combust
other fossil fuels.
Commenter Name: Michael DiMauro
Commenter Affiliation: Massachusetts Municipal Wholesale Electric Company (MMWEC)
Document Control Number: EPA-HQ-OAR-2008-0508-0580
Comment Excerpt Number: 5
Comment: If EPA does not establish DeMinimus Thresholds, or if any adopted DeMinimus
Threshold only excludes very small units, EPA should allow, as an option, the use of estimation
procedures to approximate annual fuel usage in lieu of requiring fuel metering or direct
documentation of fuel consumption. Such an estimation methodology might utilize the design
heat input of the unit, in conjunction with a typical load and annual operating time to
approximate annual fuel consumption or annual heat input. This type of approach should be
made available for units of a size up to 20 - 50 MMBtu/hr. It should be noted that the option to
aggregate emissions from these small combustion sources does not provide any significant
benefit so long as total fuel flows must be directly measured or otherwise directly documented,
as this information is typically no easier to obtain on an aggregate level than for an individual
unit.
Response: See the Preamble, Section II. K., for the response on de minimis reporting for small
emission points.
EPA acknowledges the concerns of the commenter, but believes that the Tier 1 and Tier 2
Calculation Methodologies provide sufficiently simple methods of determining CO2 emissions
from small sources. These methods are based on default emission factors and fuel consumption
from company records (they do not require any direct measurements of fuel consumption). The
methods are available to units with a maximum rated heat input capacity of less than 250
mmBtu/hr combusting any type of fuel listed in Table C-l of Subpart C, as well as to units of
any size combusting only pipeline quality natural gas, distillate oil, or biogenic fuels listed in
Table C-l. EPA believes that the availability of these methods addresses the commenter's
concerns. EPA recommends that the commenter check the definition of company records to
assess whether or not a particular alternative approach (e.g., estimation procedures) is consistent.
147
-------
Commenter Name: Ted Michaels
Commenter Affiliation: Energy Recovery Council (ERC)
Document Control Number: EPA-HQ-OAR-2008-0508-0544.1
Comment Excerpt Number: 4
Comment: Alternative Thresholds for Methodologies If EPA decides that thresholds should be
used to determine the applicability of the various calculation methodologies, then an alternative
threshold for use of Tier 4 for MWCs should be included. An appropriate threshold should be
based on non-biogenic CO2 emissions equivalent to a 250 MMbtu/hr natural gas fired
combustion source. Using the emission factors and assumptions in the calculations above, we
propose the following: "(5) Tier 4 Calculation Methodology: ... (ii) Shall be used if: ..., or if
the unit combusts municipal solid waste, and if non-biogenic C02 emissions are greater than
13,255 kilograms per hour calculated using maximum permitted heat input in MMBtu per hour,
Table C-2 default emission factor b nvcb and the non-biogenic fraction from ASTM D 6866-06a
results." Section 98.33(b)(5)(ii) Should be Modified to Clarify Conditions Under Which Units
Must Use the Tier 4 Calculation Methodology Section 98.33(b)(5)(ii) outlines the conditions
under which a reporter must use the Tier 4 calculation methodology to estimate a unit's
emissions. As drafted, it lists a series of conditions, (A) through (F), with no conjunctions
between conditions. We assume the Agency intends that all conditions must be met for the Tier
4 method to apply. Otherwise, the application of just one condition — the unit has operated for
more than 1,000 hours in any calendar year since 2005 — would require the vast majority of
stationary combustion units to use Tier 4. We do not believe the EPA intended such a far-
reaching result. We urge the EPA to insert the word "and" between each of the conditions to
clarify that all conditions must be met before a unit is subject to Tier 4. Further, per our
comments above concerning application of Tier 4 to municipal solid waste combustion, we urge
the Agency to delete the second half of condition (A) referring to units that combust MSW and
have a maximum rated input capacity greater than 250 tons per day of MSW.
Response: EPA acknowledges the commenter's concerns regarding Tier 4 applicability, and has
revised §98.33(b)(4)(ii) and (iii) of the final rule to clarify that all specified criteria must be met
before Tier 4 is required. However, EPA has kept the 250 ton MSW/day size determination.
Both the 250 mmBtu/hr and 250 tons MSW/day are size determinations for considering large
sources in other EPA programs (General Stationary Combustion Technical Support Document,
EPA-HQ-OAR-2008-0508-0004). These size determinations were not considered to be directly
comparable, but rather to reflect consistency with other EPA programs, particularly where the
challenge of monitoring is substantially different, as it is for MSW versus more homogenous
fossil fuels.
148
-------
Commenter Name: Scott Evans
Commenter Affiliation: CleanAir Engineering (Clean Air)
Document Control Number: EPA-HQ-OAR-2008-0508-0696.1
Comment Excerpt Number: 3
Comment: We encourage EPA to consider the use of thermodynamic models to determine
boiler heat rate. Real-time thermodynamic modeling, in combination with routine plant
measurements, can be used to accurately estimate C02 emissions. This approach relies on
electrical power measurement as the primary Flow measurement, which has the advantage of
having significantly lower uncertainty than the fuel and Flue gas Flow measurements employed
by other methods. As shown in the attached report [see DCN: EPA-HQ-OAR-2008-0508-
0696.2], one of the greatest sources of uncertainty in the calculation approach to GHG estimation
is fuel Flow. This is particularly true of solid fuel boilers. Many electric utility boiler operators
are turning to thermodynamic modeling as a more accurate means to determine heat rate. The
technique employed is to utilize a thermodynamic model of the power plant in which mass and
energy are conserved. The model is bounded by measured process conditions that have a direct
impact on plant capacity and executed on a real-time basis to predict heat input from fuel and
C02 production. C02 production is a function of the fuel type and quality, which can be indexed
on a real-time basis to a known analysis based on routine process measurements to determine the
appropriate carbon factor. This step further reduces the uncertainty associated with varying fuel
quality. A thermodynamic model may have sufficient fidelity to predict a range of operating
parameters, which provides opportunities for independent feedback mechanisms to assure
accuracy and repeatability. This method relies on measurement of the product being sold,
electricity, which for practical and financial reasons, receives greater attention from instrument
and control personnel. Furthermore, the measurement of electricity has the least uncertainty of
all the primary "Flows" in a power plant. This approach combined with site-specific (not
generic) emission factors or fuel carbon content, will likely provide more reliable GHG emission
data than with the fuel-Flow/generic emission factor approach. We feel this approach is
definitely more accurate than Tier 2, however, at this time, we do not have data to support its
inclusion in Tier 4. Therefore, we feel the most appropriate classification would be in Tier 3
(assuming use of a site specific emission factor or fuel carbon content).
Response: EPA's approach makes use of existing data and methodologies to the extent feasible,
and is consistent with the types of methods contained in other GHG reporting programs (e.g., the
California mandatory reporting rule, WCI, RGGI, TCR, and Climate Leaders). Because this
approach specifies methods for each source category, it will result in data that are comparable
across facilities. The Agency is not opposed to innovative, alternative approaches for CO2
emissions calculation, such as the thermodynamic modeling described by the commenter.
However, the commenter did not provide any supplementary information, proposed rule
language, or cost analysis to explain how this proposed methodology could be implemented. In
view of this, EPA has not incorporated the commenter's suggested approach into the final rule,
but is willing to consider it in a future rulemaking, if the necessary technical details of the
method are provided for Agency review.
149
-------
Commenter Name: Thomas M. Ward
Commenter Affiliation: Novelis Corporation
Document Control Number: EPA-HQ-OAR-2008-0508-0561.1
Comment Excerpt Number: 3
Comment: Tiered Reporting Protocol: Although Novelis Corp. agrees that the GHG reporting
rule should include direct emissions from significant combustion sources within a facility, it has
some concerns with the approach proposed in the rule. Specifically, the proposed tiered
reporting protocol included is overly complex and burdensome. In effect, many facilities with
various sized combustion units will have to comply with an array of reporting tiers at the process
unit level that are extremely complex and expensive to conduct. Reporting at a unit level is
unduly costly and burdensome and grouping systems may not be feasible due to logistics and the
cost of metering. The difference in measured values between the main billing meter and any unit
and/or grouped measures would serve to adequately quantify such units to reduce cost the cost
burden associated with additional measuring equipment.
Response: See the Preamble, Section II. L., for the response on the general monitoring
approach.
See the Preamble and the response to comment EPA-HQ-OAR-2008-0508-0520.1 excerpt 16 for
the rationale for level of reporting and the additional flexibility provided to reporters, particularly
for common pipe and aggregated unit circumstances.
EPA does not agree with the commenter's assertion that the amount of unit-level data and
verification information to be reported is excessive, burdensome, or unnecessary. For this
mandatory GHG emissions reporting rule, two main approaches to data verification were
considered, i.e., EPA verification and third-party verification. The Agency decided on the
former approach. In view of this, additional, unit-level information is deemed necessary to
provide assurance that the reported facility-wide GHG emissions data are both credible and
accurate.
However, EPA has modified the rule to make it clearer the conditions under which specific tiers
should be used. EPA has also dropped the cumulative 250 mmBtu/hr heat input capacity limit
on the aggregation of units. Rather, the 250 mmBtu/hr restriction applies only to the individual
units in the group. Therefore, for reporting purposes, individual units with maximum rated heat
input capacities of 250 mmBtu/hr or less may be aggregated without limit into a single group,
provided that the Tier 4 methodology is not required for any of the units, and all units in the
group use the same tier for any common fuel(s) that they combust. Units with maximum rated
heat inputs greater than 250 mmBtu/hr using Tiers 1, 2, and 3 must report as individual units,
unless they burn the same type of fuel, and the fuel is provided by a common pipe or supply line;
in that case, the owner or operator may opt to use the common pipe reporting provisions in
§98.36(c)(3). Units using Tier 4 must report as individual units unless they share a monitored
common stack or duct; in that case, the common stack or duct reporting provisions may be used.
The commenter should note that Tiers 1 and 2, which have been expanded to include units of any
size in which the only fossil fuels combusted are pipeline quality natural gas and/or distillate oil,
do not require fuel metering but instead rely on company records to quantify fuel consumption.
150
-------
Commenter Name: Blair Wheeler
Commenter Affiliation: Aspen Technology, Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-0488.2
Comment Excerpt Number: 2
Comment: In Subsection 7.1 Stationary Combustion Sources, we propose adding an additional
option (Option 5) that would be based on direct measurement (minute or hour) and calculation of
carbon emissions based upon fuel type, fuel flow, exhaust stack temperature and stack gas excess
oxygen utilizing a steady state engineering model specific to that process unit. However, based
upon our real world experience, this carbon emission calculation must be verified with an energy
balance (compare fired side heat release with process or steam side heat absorption) around the
Stationary Combustion Source to ensure the most accurate calculation of carbon emissions. If
the heat balance is off more than a predetermined percentage or absolute amount, the system
should notify the refinery staff for timely investigation of the cause and correction (i.e.,
instrument recalibration).
Response: EPA's approach makes use of existing data and methodologies to the extent feasible,
and is consistent with the types of methods contained in other GHG reporting programs (e.g., the
California mandatory reporting rule, WCI, RGGI, TCR, and Climate Leaders). Because this
approach specifies methods for each source category, it will result in data that are comparable
across facilities. The Agency is not opposed to innovative, alternative approaches for CO2
emissions calculation, such as the one described by the commenter. However, the commenter
did not provide any supplementary information, proposed rule language, or cost analysis to
explain how the proposed methodology could be implemented. In view of this, EPA has not
incorporated the commenter's suggested approach into the final rule, but is willing to consider it
in a future rulemaking, if the necessary technical details of the method are provided for Agency
review.
Commenter Name: W. Walter Tyler
Commenter Affiliation: INVISTA S.a r.l. (INVISTA)
Document Control Number: EPA-HQ-OAR-2008-0508-0481.2
Comment Excerpt Number: 2
Comment: Tier I methodology for all reporting facilities will provide a reasonable level of
certainty and accuracy. Like many other companies, INVISTA has taken steps to determine
estimates of total GHG emissions through established industry standards and protocols that
utilize fuel consumption data and recognized emission factors. For example, the Climate
Registry (TCR), the WRI/WBCSD and ISO 14064.1 standards and protocols utilize well-
recognized and well-established default emission factors for estimating GHG emissions that are
comparable to the proposed methodology in Tier 1 of the Proposed Rule. This data has shown to
be a reliable indicator, not only for tracking inventory and product manufacturing costs, but also
in some instances for emissions estimates needed under other environmental regulatory
programs, such as the Clean Air Act's Title V program. The Proposed Rule, however, specifies a
4-Tier reporting structure that is much more complex than other GHG reporting systems. The
requirements in the Proposed Rule - including enhanced direct emissions monitoring, total
carbon content analysis, and fuel-flow meters - demand significant additional investments at
151
-------
manufacturing sites with little gain in accuracy of emissions estimates over that which can be
obtained by using current, accepted industry practice. In addition, the Tier 3 and 4 categories
require an unspecified level of precision and accuracy to estimate and report GHG emissions
based upon devices, measurements, or data that either do not exist currently at many facilities or
have not been used historically for reporting or compliance purposes. For example, many
facilities subject to this rule back-calculate fuel usage based on accepted industry standards and
techniques such as inventory reconciliation, steam flow, or process knowledge which have been
used for other reporting and accounting purposes. If EPA determines that this proposed Tiered
approach is the preferred vehicle for reporting, then INVISTA recommends that EPA clarify that
current industry standards and practice, such as inventory reconciliation, are within the meaning
and intent of "company records" upon which many of the emission calculations in the Proposed
Rule are based. However, simplifying the current scheme and basing it on recognized reporting
methodologies, such as default emission factors, will alleviate much of the uncertainty in the
Rule while sacrificing little if any of the accuracy EPA hopes to achieve in this reporting
scheme. For these reasons, INVISTA recommends that Tier I methodology be adopted for all
source categories.
Response: See the Preamble, Section II. L., for the response on the general monitoring
approach.
EPA did not choose to adopt a simplified calculation method approach (e.g., using default
emission factors) for all units because the data would be less accurate than under the selected
option and would not make use of site-specific data that many facilities already have available
and refined calculation approaches that many facilities are already using.
Methodologies that reflect the variability of fuels across units and facilities through sampling and
measurement are more accurate than methodologies that do not account for this variability (e.g.,
Tier 1). The gains from measurement vary by fuel type (i.e., heterogeneity of carbon content and
heat rate is lower in some fuels) and the final rule accounts for this difference by varying the
requirements for units, with due consideration of burden and cost.
EPA has significantly expanded the use of Tier 1 and Tier 2 Calculation Methodologies. The
250 mmBtu/hr restriction on the use of Tier 2 has been lifted for units in which the only fossil
fuels combusted are natural gas and/or distillate oil, in view of the homogeneous nature of these
fuels. Most units combusting the biogenic fuels in Table C-l may use Tier 1. However, the 250
mmBtu/hr unit size cutoff remains for units that combust other fuels. EPA has considerably
revised the Tier 2 and Tier 3 fuel sampling requirements in an effort to reduce the burden on
reporters. Furthermore, the final rule clarifies that fuel sampling and analysis data provided by
the supplier may be used in the emission calculations, and that fuel billing meters may be used to
quantify fuel consumption.
EPA has defined the term "company records" in §98.6 of the final rule. EPA believes that the
revised definition provides appropriate guidance as to what records a facility may use to
determine fuel consumption.
152
-------
Commenter Name: Stephen E. Woock
Commenter Affiliation: Weyerhaeuser Company
Document Control Number: EPA-HQ-OAR-2008-0508-0451.1
Comment Excerpt Number: 23
Comment: Weyerhaeuser proposes that the C02 calculation methodology used for municipal
solid waste (MSW) combustion units should be allowed for Tier 3 combustion sources.
Currently the MSW C02 calculation methodology is only allowed for Tier 2 combustion units,
which applies to sources rated at ~ 250 mmBtu/hr in heat capacity. Tier 3 sources are defined as
> 250 mmBtu/hr. However, all of the elements within the MSW C02 calculation equation are
entirely independent of the combustion unit size. EPA illustrates this independence from
combustion unit size in the MSW equation for CH4 and N20 emissions, which is used for all
Tier 1, Tier 2 and Tier 3 combustion units. The MSW C02 equation is the same equation as the
CH4 and N20 emissions, except for the different C02, CH4 and N20 emission factors.
Therefore, since the MSW CH4 and N20 equations are suitable for all combustion units, the
MSW C02 calculation methodology should be allowed for all combustion unit sizes, including
Tier 3 combustion units.
Response: EPA has revised the rule to allow the use of steam production and combustion unit
efficiency to calculate C02 emissions under Tier 2 for other solid fuels in addition to municipal
solid waste (MSW). However, EPA does not believe that it is appropriate to calculate emissions
using the Tier 2 MSW equation for units that are required to use Tier 3. Given the nature of
MSW, the fuel sampling presents a much greater challenge than for many other combustion
sources. The Tier 3 methodologies for units with a maximum rated heat input capacity greater
than 250 mmBtu/hr that combusts any type of fuel listed in Table C-l are considered to provide
better information than the Tier 2 methodology for MSW. Also the comparison of C02
requirements to CH4 and N20 requirements is not appropriate given the much lower level and
significance of CH4 andN20 emissions from stationary combustion.
Commenter Name: Lorraine Krupa Gershman
Commenter Affiliation: American Chemistry Council (ACC)
Document Control Number: EPA-HQ-OAR-2008-0508-0423.2
Comment Excerpt Number: 52
Comment: The Tier 4 calculation methodology requires a "stack gas volumetric flow rate
monitor" (§98.33(a)(4)(i)). Many existing CEMS systems determine stack gas flow rate through
methods other than direct measurement of the exhaust stream. The requirement to install
volumetric flow rate monitors introduces an unnecessary cost and in many cases requires a
complete redesign of the stack in order to position a meter properly. The final rule should allow
calculation of the stack gas flow rate based on other methodologies. One method that should be
allowed involves calculation of the stack flow based on measurement of the oxygen
concentration in the stack, fuel flows, and temperature. Another method involves applying an air
feed to exhaust flow ratio established through testing. This improvement will encourage
facilities that have non C02 CEMS systems currently in place to enhance their system to
measure C02. Requiring a stack gas volumetric flow rate monitor in order to use a C02 CEMS
is a significant deterrent from voluntary use of the Tier 4 method.
153
-------
Response: The Tier 4 CEMS requirement is limited to larger solid fossil fuel-fired units and
MWC units that have an existing gas monitor of any kind or a volumetric flow rate monitor, or
both. EPA is requiring the use of CEMS due to the complexity of monitoring solid fuel
consumption and the heterogeneous nature of the solid fuels. The Agency does not agree that the
addition of a flow monitor will be excessively costly at an installation where there is an
established CEMS infrastructure in place. Redesign of the stack will be not be required "in many
cases," as asserted by the commenter. There are a number of different types of flow monitors
available commercially. One of the simplest is a differential pressure monitor, consisting of one
or more S-type pitot tube sensing elements. This type of monitoring system is relatively
inexpensive and can easily be installed on most existing stacks.
Commenter Name: Stephen E. Woock
Commenter Affiliation: Weyerhaeuser Company
Document Control Number: EPA-HQ-OAR-2008-0508-0451.1
Comment Excerpt Number: 22
Comment: Weyerhaeuser proposes that the CO2 calculation methodology EPA proposes at
§98.33(a)(2)(iii) for municipal solid waste (MSW) combustion units should also apply to other
solid fuel combustion units. The MSW CO2 calculation methodology is based on the steam
generated to calculate the C02 emissions. This steam approach provides an accurate and
streamlined approach to calculate the CO2 emissions, primarily because it eliminates the need to
measure fuel usage directly. All solid fuel boilers operate similarly with respect to fuel-steam
balance, therefore, the steam approach can be used to calculate the CO2 from all solid fuel
combustion units, such as coal and solid biomass fuels (e.g. wood bark). This accurate approach
is already in use for many solid fuel boilers at Weyerhaeuser and in the Forest Products Industry
in general. For boilers that use multiple fuels, the proposed rule is very clear as to how to track
all of the non-solid fuels. The non-solid fuels are to be measured directly. Therefore, the steam
generated by these fuels is easily and accurately determined using standard heat balance
equations, which are similar to the MSW equation in this proposed rule. Therefore, the steam
not generated by the non-solid fuels is generated by the solid fuels. This streamlined approach
ensures the heat balance around the combustion unit is always in balance. This approach also
eliminates the inaccuracies of having to measure the moisture content of the solid fuels, because
the results from this approach are reported in units of dry material combusted. This is very
important when combusting materials such as wood bark, which can have moisture contents
ranging from 10% to over 50%, which is very difficult to measure accurately. Therefore, use of
the proposed MSW CO2 calculation methodology should be allowed for all combustion units
that use solid fuels, whether it is MSW or other solid fuels. This methodology provides an
accurate and streamlined calculation option for the reporters.
Response: EPA has revised the rule to allow the use of steam production and combustion unit
efficiency to calculate CO2 emissions under Tier 2 for other solid fuels in addition to municipal
solid waste (MSW). These parameters may also be used to quantify the amount of solid biomass
combusted in a unit for the use in Tier 1 calculations.
154
-------
Commenter Name: Lorraine Krupa Gershman
Commenter Affiliation: American Chemistry Council (ACC)
Document Control Number: EPA-HQ-OAR-2008-0508-0423.2
Comment Excerpt Number: 53
Comment: In §98.33(b)(1), we believe that it is unnecessarily restrictive to limit the use of Tier
1 to units ~ 250 mmBTU/hr in size. EPA has not provided an explanation for this restriction and
we recommend that it be deleted in the final rule. The variations introduced in the calculations
will be very small compared to the size of the entire greenhouse gas inventory.
Response: EPA disagrees with the commenter's suggestion of allowing Tier 1 reporting for
fossil fuel-fired units with a maximum rated heat input capacity greater than 250 mmBtu/hr.
EPA did not choose to adopt a simplified calculation method approach (e.g., using default
emission factors) for all units because the data would be less accurate than under the selected
option and would not make use of site-specific data that many facilities already have available
and refined calculation approaches that many facilities are already using.
EPA's approach is to require the larger units to use the more accurate methodologies as part of an
effort to balance accuracy of reported data with burden. The 250 mmBtu/hr cutoff is used by
other EPA programs to denote larger units (e.g., NOx Budget Trading Program). Methodologies
that reflect the variability of fuels across units and facilities through sampling and measurement
are more accurate than methodologies that do not account for this variability. The gains from
measurement vary by fuel type (i.e., heterogeneity of carbon content and heat rate is lower in
some fuels) and the final rule accounts for this difference by varying the requirements for units,
with due consideration of burden and cost.
Commenter Name: William Fred Durham
Commenter Affiliation: West Virginia Department of Environmental Protection (DEP)
Document Control Number: EPA-HQ-OAR-2008-0508-0629.1
Comment Excerpt Number: 3
Comment: Recently, a question came up regarding the root source of the emission factors and
high heat values listed in EPA's Proposed MRR, Subpart C - General Stationary Fuel
Combustion Sources, Table C-l. The reference for the factors is contained in the Technical
Support Document for Stationary Fuel Combustion Emissions: Proposed Rule for Mandatory
Reporting of Greenhouse Gases. Regarding the Tier 1 Methodology on page 15, the document
states, "Default fuel-specific high heat values and CO2 emission factors are compiled in
Appendix D." Appendix D does not exist; the values are listed in Appendix C, Default CO2
Emission Factors and High Heat Values for Various Types of Fuel. Further, when Appendix C
is investigated it is found that heat values in question are from the draft U.S. EPA, Inventory of
Greenhouse Gas Emissions and Sinks: 1990 - 2005 (2007). The DAQ questions if EPA's use of
a draft document as a reference is sufficiently robust for its final rule.
Response: EPA appreciates the comment, and acknowledges that the Technical Support
Document for Stationary Fuel Combustion Sources incorrectly referred to Appendix D. The
fuel-specific high heat values and CO2 emission factors are from the draft U.S. EPA, Inventory
155
-------
of Greenhouse Gas Emissions and Sinks: 1990 - 2005 (2007) which is a published document
from EPA. EPA believes the values in this document can be referenced by the rule. However,
the commenter should note that EPA has reviewed and revised the emission factors provided in
Subpart C of the rule, in an effort to ensure that they are as appropriate as possible for the
purposes of this reporting rule.
Commenter Name: Michael DiMauro
Commenter Affiliation: Massachusetts Municipal Wholesale Electric Company (MMWEC)
Document Control Number: EPA-HQ-OAR-2008-0508-0580
Comment Excerpt Number: 3
Comment: For very small and/or low utilization stationary combustion units, the Rule should
provide either: (a) an exclusion from GHG Reporting; or (b) a simplified procedure for
determining GHG emissions that does not require direct documentation of fuel usage based on
fuel metering or fuel consumption records. The Preamble to the Proposed Rule seems to indicate
support for the use of simplified estimation procedures to determine fuel usage ["small stationary
combustion units could use a default emission factor and a heat rate to estimate emissions, and
no fuel measurements would be required" (FR page 16473 Column 3)], which would obviate the
need to obtain data (records or monitoring) directly documenting fuel consumption. However
none of the Four Tiers appears to allow the option of relying on a "heat rate" in lieu of fuel
records or fuel measurements to estimate fuel consumption for small combustion units.
Examples of the types of combustion units that should be eligible to adopt simplified CO2
emission estimation methods, or should qualify for an exemption from GHG Reporting, include:
1. Small diesels (~ 5 MMBtu/hr) engines whose sole function is to provide start-up power for a
Combustion Turbine. This arrangement provides the facility black start capability. The total
operating time of the starter diesel at each startup of the combustion turbine is < 15 minutes.
These starter diesel engines are not equipped with a fuel meter, and fuel records cannot be used
to determine fuel usage, as the oil storage tank is refilled only rarely due to the very limited
operating time of the engine. Requiring direct fuel monitoring for such a limited use, small
emission unit is unwarranted. 2. Auxiliary Boilers - Many EGU sites have installed small house
boilers, in the size range of 10 - 50 MMBtu/hr, to provide heating for the facility during periods
the EGU units are not operating (i.e. intervals when the EGUs are not dispatched, or are in an
outage). Fuel metering for such house boilers may be crude, data recording is typically on
hardcopy charts (which does not allows convenient fuel usage summation). Additionally,
segregation of fuel usage for these units based on fuel records may be problematic. Oftentimes,
then, fuel metering is poorer and fuel records less available or of lower quality for smaller units
than for larger more regulated units, and consequently it can take significantly more effort to
obtain reasonable fuel data for smaller units.
Response: See the Preamble, Section II. K., for the response on de minimis reporting for small
emission points.
EPA acknowledges the concerns of the commenters, but believes that the Tier 1 and Tier 2
Calculation Methodologies provide sufficiently simple methods of determining CO2 emissions
from small sources. These methods are based on default emission factors and fuel consumption
from company records (they do not require any direct measurements of fuel consumption). They
are available to units with a maximum rated heat input capacity of less than 250 mmBtu/hr
156
-------
combusting any type of fuel listed in Table C-l of Subpart C, as well as to units of any size
combusting only pipeline quality natural gas, distillate oil, or biogenic fuels listed in Table C-l.
EPA believes that the availability of these methods addresses the commenter's' concerns. The
commenter should note that the term "company records" is defined in §98.6, and provides
guidance as to what fuel use records are acceptable for the purposes of this reporting rule.
Commenter Name: Vince Brisini
Commenter Affiliation: RRI Energy Inc. (RRI)
Document Control Number: EPA-HQ-OAR-2008-0508-0618.1
Comment Excerpt Number: 2
Comment: In order to avoid an unnecessary burden on reporters, US. EPA should offer
flexibility with respect to carbon sampling of fuels, as required in Tier 3 data standards. Due to
the minor variability in carbon content of pipeline natural gas and fuel oils used by electricity
generators, U.S. EPA would not gain a significant amount of accuracy in GHG emissions
estimates through carbon sampling of these fuels. Consequently, RRI proposes that U.S. EPA
either make Tier 3 methodology optional (i.e., allow reporters to use either Tier 2 or Tier 3
methodology), or ask fuel suppliers—who are already required to submit high heating value
(HMV) data to their customers—to also submit data on the carbon content of their fuels.
Response: Some fuel suppliers may report carbon sampling results as part of the requirements
under other subparts. Note that EPA is not finalizing Subpart KK (Coal Suppliers) as part of this
final rule. EPA has expanded the use of the Tier 2 Calculation Methodology based on fuel
heating value to units of any size in which the only fossil fuels combusted are pipeline quality
natural gas and distillate oil, in view of the homogeneous nature of these fuels. The number of
reporters required to use Tier 3 will be reduced as a result.
The Tier 3 methodology which includes carbon content measurements is still required for units
with a maximum rated heat input capacity greater than 250 mmBtu/hr fuels other than MSW.
Methodologies that reflect the variability of fuels across units and facilities through sampling and
measurement are more accurate than methodologies that do not account for this variability. The
gains from measurement vary by fuel type (i.e., heterogeneity of carbon content and heat rate is
lower in some fuels) and the final rule accounts for this difference by varying the requirements
for units, with due consideration of burden and cost.
The final rule also clarifies that fuel sampling and analysis data provided by the supplier may be
used in the emission calculations. The commenter should note that fuel sampling frequencies for
Tiers 2 and 3 have been substantially revised: natural gas must be sampled semiannually, and
fuel oil must be sampled once per fuel lot.
157
-------
Commenter Name: Michael DiMauro
Commenter Affiliation: Massachusetts Municipal Wholesale Electric Company (MMWEC)
Document Control Number: EPA-HQ-OAR-2008-0508-0580
Comment Excerpt Number: 2
Comment: While the Part 98 Subpart C and D monitoring provisions provide significant
flexibility for Stationary Combustion sources, an approach which is which is strongly supported,
monitoring requirements should be simplified, streamlined and more appropriately targeted, and
the rule should allow, as an option, more general use of the established Part 75 procedures and
calculation methods.
Response: EPA believes that the structure of the final rule to a large extent mirrors this
suggestion. The owner or operator of a unit may elect to use a higher tier than required, allowing
any units to use Part 75 methodologies under Tier 4. Furthermore, in the final rule EPA has
provided alternative methods for units not subject to the Acid Rain Program, but which report
data to EPA under Part 75 (see §98.33(a)(5)). These alternative approaches rely heavily on Part
75 methods.
Commenter Name: Kerry Kelly
Commenter Affiliation: Waste Management (WM)
Document Control Number: EPA-HQ-OAR-2008-0508-0376.1
Comment Excerpt Number: 4
Comment: EPA is proposing to require MWC units with a maximum rated capacity of greater
than 250 tons per day of MSW to use the Tier 4 methodology, while other stationary combustion
units of 250 MMBtu/hr may use Tier 2. WM recommends that the EPA allow large and small
capacity MWCs to use the Tier 2 calculation methodologies, particularly as MWCs have
significantly lower GHG emissions than the 250 MMBtu/hr combustion sources as shown below
in Table 1. [SeeDCN: EPA-HQ-OAR-2008-0508-0376.1, Table 1, p.4.] It is readily apparent
that a 250 ton per day MWC emits only 18 percent of the CO2 emitted by a 250 MMBtu/hr oil-
fired unit or only 25 percent of the CO2 emitted by a gas-fired combustion unit. Even a larger,
750 ton per day municipal waste combustor emits only 54 percent as much as a 250 MMBtu/hr
oil-fired combustion unit and 75 percent as much CO2 as a 250 MMBtu/hr gas-fired combustion
unit. Consequently, a large MWC unit's cost to implement the Tier 4 methodology is
disproportionate with respect to their relative GHG emissions. In addition, unlike typical 250
MMBtu combustion units, MWCs are subject to extensive source testing, and requirements to
install Part 60 CEMS equipment that provides accurate and reliable GHG reporting. We
question the need to impose costly, alternative monitoring equipment on these relatively small
sources, particularly when far larger sources may utilize the far less expensive Tier 2 methods.
Response: See the response to comment EPA-HQ-OAR-2008-0508-0544.1, excerpt number 4.
158
-------
Commenter Name: Michael E. Van Brunt
Commenter Affiliation: Covanta Energy Corporation
Document Control Number: EPA-HQ-OAR-2008-0508-0548.1
Comment Excerpt Number: 4
Comment: Under the Clean Air Act, the EfW industry is subject to rigorous monitoring and
reporting requirements, including Continuous Emission Monitoring Systems (CEMS), and
extensive pollution control requirements. Adding additional monitoring equipment, in the form
of CO2 and flow CEMS would increase the regulatory burden without a commensurate increase
in the quality of C02 data. According to the 2009 EPA GHG Inventory, EfW represents less
than 0.3% of the total emissions; however, even this number is an overstatement. Comments
provided to the EPA over the past three years have indentified that EfW emissions over
overstated by a factor of roughly two. Based on the corrected emissions figure, emissions from
landfills alone are nearly thirteen times as great as emissions from EfW. In lieu of requiring the
installation of new equipment with little additional benefit, we request that the EPA establish two
revised Tier 4 methodologies for the EfW industry, both based on current stack testing and/or
CEMS requirements. Similar methodologies are expected to be included in The Climate
Registry's Electric Power Sector Protocol as an improvement over the emission factor (Tier 2)
approach. The first method would allow operators to calculate annual CO2 emissions based on
annual stack testing. Operators would calculate an average fossil & biogenic C02 emission rate
per unit of steam production based on average CO2 concentration, stack flow, and steam flow
over the test period. This average, when applied to the annual steam production from MSW
combusted for a unit and/or facility, would yield the total CO2 emissions for the year. In the
second method, operators would calculate an average stack flow per unit of steam production
during annual source testing. Hourly mass flow of CO2 emissions would be calculated from the
following: 1. Calculated stack flow based on the relationship established during the annual stack
test and the actual MSW-based steam output; and 2. Hourly CO2 concentrations. CO2
concentrations can either be measured directly using a CO2 CEM, or can be calculated from an
O2 CEM where annual source testing has demonstrated that CO2 concentrations calculated from
the O2 readings meet the Relative Accuracy Test Audit (RATA) requirements in 40 CFR,
Appendix B, Performance Specification 3. The calculation of CO2 from O2 can be completed
using equations F-14a or F-14b from Appendix F of 40 CFR 75, exactly as applied in the
proposed rule to other stationary combustion sources, together with the Fd and Fc F-factors for
Municipal Solid Waste (MSW) from Table 19-2 of EPA Method 19. Method 19 is specifically
referenced by the emission standards for Municipal Waste Combustors found in 40 CFR 60,
Subparts Cb and Eb. Consistent with the Proposed Rule, emissions of anthropogenic CO2 would
then be calculated by applying the annual average of quarterly analysis via ASTM method D-
6866-06a of stack samples collected in accordance with ASTM method D7459-08. We fully
support the inclusion of quarterly analysis via ASTM method D6866-06a of stack samples
collected in accordance with ASTM method D7459-08 to determine the split between
anthropogenic and biogenic carbon in §98.33(e)(3). We agree with the EPA's conclusion that a
manual sorting approach is not practical, and ASTM methods are more rigorous. Covanta has
significant experience with this methodology, having collected nearly 200 samples from sixteen
facilities located across the United States.
159
-------
Response: See the response to comment EPA-HQ-OAR-2008-0508-0544.1 excerpt 4.
EPA believes that it is appropriate to require the use of CEMS on the largest MSW combustion
sources and any smaller MSW combustion source which already has CO2 concentration
monitors and stack gas volumetric flow rate monitors in place. EPA has, however, clarified that
all of the criteria in §98.33(b)(4)(ii) or (iii) must be present to require the use of Tier 4. EPA
believes that it is appropriate for MSW combustion units to use ASTM D6866-06a and D7459-
08 on a quarterly basis to determine the relative proportions of biogenic and non-biogenic CO2
emissions from the MSW combusted. Where Tier 2 is used, EPA has provided for MSW
combustion units to determine total CO2 emissions from the amount of steam produced, boiler
design, and a default C02 emission factor. EPA believes that this is more appropriate than
determining site-specific factors during annual testing. Where Tier 4 is used, CO2 emissions are
determined using a C02 concentration monitor and a stack gas volumetric flow rate monitor.
EPA does not believe that it is appropriate to estimate stack flow based on steam production in
Tier 4, and does not believe it is appropriate to use an 02 monitor for MSW combustion, since it
is not a fuel listed in Table 1 in Section 3.3.5 of Appendix F to Part 75. Biogenic emissions for
the MSW combustion unit are then calculated by multiplying the total C02 emissions for the
year, determined using Tier 2 or 4, by the fraction of biogenic emissions, determined using the
ASTM methods. EPA appreciates the commenter's support of the ASTM D6866-06a and
D7459-08 methods.
Commenter Name: Kerry Kelly
Commenter Affiliation: Waste Management (WM)
Document Control Number: EPA-HQ-OAR-2008-0508-0376.1
Comment Excerpt Number: 3
Comment: The Tier 4 calculation methodology proposed in the mandatory reporting rule is
very similar to the initial method proposed in the January 2009 draft Western Climate Initiative
(WCI) Mandatory Reporting Requirements. Subsequently in May 2009, after extensive public
comments, the WCI concluded that requiring the installation of CEM components for C02 and
stack gas flow measurement at facilities, which had not previously installed them, was extremely
onerous and expensive and would not improve overall reporting accuracy. Accordingly, the
WCI adopted a methodology for the General Stationary Combustion category that eliminated the
use of 40 CFR Part 75 type CEMS unless a unit was already equipped with both a stack gas
volumetric flow rate monitor and a C02 CEM. WCI also eliminated the use of Part 75 CEMS
for municipal solid waste combustion units and established the use of Tier 2 calculation
methodologies. The U.S. Department of Energy (DOE) 1605 (b) Voluntary Reporting program
offers similar flexibility in its " A-Rated Measurement and Estimation Method" for stationary
combustion sources. The DOE approach includes: 1. Use of continuous direct measurement of
C02 at facilities that have already installed CEMs for C02; 2. Use of emission factors based on
multiple, regularly repeated, on-site direct measurement of source emissions; and 3. Use of
measured source activity data (e.g., amount of MSW processed, steam production.) WM
recommends that EPA incorporate similar requirements for municipal waste combustors in the
final MMR. As WCI concluded, accurate annual GHG emissions result when using the Tier 2
calculation methodology, including use of actual steam generation or waste throughput data,
C02 emission factors, heat input to steam output or stack flow rate to steam output ratios, and
fuel HHV.
160
-------
Response: See the response to comment EPA-HQ-OAR-2008-0508-0544.1 excerpt 4.
EPA believes that it is appropriate to require the use of CEMS on the largest MSW combustion
sources and any smaller MSW combustion source which already has C02 concentration
monitors and stack gas volumetric flow rate monitors in place. EPA has, however, clarified that
all of the criteria in §98.33(b)(4)(ii) or (iii) must be present to require the use of Tier 4. EPA
believes that it is appropriate for MSW combustion units to use ASTM D6866-06a and D7459-
08 on a quarterly basis to determine the relative proportions of biogenic and non-biogenic C02
emissions from the MSW combusted. Where Tier 2 is used, EPA has provided for MSW
combustion units to determine total C02 emissions from the amount of steam produced, boiler
design, and a default C02 emission factor. EPA believes that this is more appropriate than
determining site-specific factors during annual testing. Where Tier 4 is used, C02 emissions are
determined using a C02 concentration monitor and a stack gas volumetric flow rate monitor.
Biogenic emissions for the MSW combustion unit are then calculated by multiplying the total
C02 emissions for the year, determined using Tier 2 or 4, by the fraction of biogenic emissions,
determined using the ASTM methods.
Commenter Name: Gary Moore
Commenter Affiliation: Pensacola Plant of Ascend Performance Materials LLC
Document Control Number: EPA-HQ-OAR-2008-0508-0366.1
Comment Excerpt Number: 3
Comment: It was assumed that the requirement for process GC analyzers to measure carbon
content and molecular weight daily would not be burdensome as they were likely already
installed to optimize process operation (see page 16484). Off gas streams that are subject to
control requirements are not typically monitored as they are required to be controlled. The
addition of process GCs for the analyses required in §98.33(b)(3)(ii) and §98.34(d)(3) would be
expensive and invalidates the cost assumption in the Preamble.
Response: EPA has retained the daily sampling requirement for other gaseous fuels, due to
process gas variability, but only for facilities with existing equipment in place that is capable of
providing the data. Otherwise, weekly sampling is now required. EPA also has limited the Tier
3 requirement to fuels that make up at least ten percent of the annual heat input for a unit with a
maximum rated heat input capacity greater than 250 mmBtu/hr.
Commenter Name: Mike Aire
Commenter Affiliation: Newmont Mining Corporation (NMC)
Document Control Number: EPA-HQ-OAR-2008-0508-0378.1
Comment Excerpt Number: 3
Comment: EPA Allow Certified Reporting Systems (GRI, TCR) to Report Emissions EPA
should develop a reporting format that is fully compatible with other credible reporting systems
such as The Climate Registry so that data can be electronically transferred between databases to
save time and money.
161
-------
Response: See the Preamble, Section II. O., for the response on the relationship of this rule to
other programs, and for the response on collection, management, and dissemination of GHG
emissions data.
Commenter Name: Allen Kacenjar
Commenter Affiliation: Squire Sanders
Document Control Number: EPA-HQ-OAR-2008-0508-0492.1
Comment Excerpt Number: 2
Comment: EPA was correct to define the parameters of Subpart C so that sources operating
only a continuous opacity monitoring system ("COMS") are not obligated to conduct Tier 4
monitoring. As explained in the Preamble, §98.33(b)(5) is intended to "require the use of
certified CEMS to quantify CO2 mass emissions where existing CEMS equipment is installed"
which "include a gas monitor of any kind or a flow monitor (or both)." The Proposed Rule
expressly defines the term "Continuous Emissions Monitoring System" to mean "the total
equipment required to sample, analyze, measure, and provide, by means of readings recorded at
least once every 15 minutes, a permanent record of gas concentrations, pollutant emission rates,
or gas volumetric flow rates from stationary sources." §98.6. COMS do not monitor gas
concentrations or flow rates. Rather, they continuously measure opacity by transmitting a beam
of light across the stack to a receiver on the other side. The light is absorbed or deflected by
visible particles in the flue gas stream. An opacity reading is derived by measuring how these
flue gases attenuate the light beam between transmission and receipt. Thus, COMS are an
optical technique designed to simulate the results of a visual opacity reading performed by a
human using U.S. EPA Test Method 9. COMS detect only the ability of particles in flue gas
streams to refract light and lack the capacity to distinguish pollutant emission rates or gas
concentrations of any sort. Similarly, COMS do not measure the volume of gas flowing through
the stack because the monitors are not designed to determine quantity of a pollutant being
emitted. Thus, they comfortably fall beyond the express definition of CEMS in the Proposed
Rule. Distinguishing between CEMS and COMS for purposes of triggering Tier 4 reporting is
consistent with the distinct treatment these different monitoring technologies receive in existing
Clean Air Act rules. The New Source Performance Standards establish different calibration
techniques for CEMS and COMS and contain completely distinct performance specifications.
This is necessary because CEMS performance specifications must address issues with sample
interfaces, pollutant analyzers, and diluent analyzers that do not exist for COMS. The National
Emission Standards for Hazardous Air Pollutants (NESHAPs) for Source Categories also define
CEMS and COMS separately. CEMS are systems that can sample, condition, analyze, and
record emissions, whereas COMS are simpler systems that can only measure opacity. The
NESHAPs also distinguish between the two systems in discussing the timing of monitoring
cycles and calibration requirements, and may require installation of one, both, or neither of these
monitoring systems. Due to the operational and regulatory differences between CEMS and
COMS, EPA's underlying rationale for requiring Tier 4 reporting at facilities that operate CEMS
does not apply to facilities that only operate COMS. As noted above, EPA's rationale for
requiring facilities with CEMS that do not monitor CO2 to "upgrade" to CO2 CEMS is that the
"incremental cost" will not be unduly burdensome because they are "already required to install,
certify, maintain, and operate CEMS and to perform ongoing QA testing of the existing
monitors." 74 Fed. Reg. at 16483. Those assumptions do not hold true to facilities that only
162
-------
operate COMS. Instead of bearing only the "incremental cost" of upgrading existing CEMS
equipment, COMS-only facilities would functionally start from the same position as a facility
with no continuous monitoring apparatus at all. [Footnote: See Exhibit A in DCN EPA-HQ-
OAR-2008-0508-0492.1 for a cost Quotation and Scope of Work prepared by CEMTEK
Environmental for Orrville Municipal Utilities. As detailed in that quotation, the up-front cost of
installing a single CO2 CEMS at a facility that already possesses COMS is expected to total
approximately $250,000.] Thus, the end result of mandating Tier 4 monitoring at COMS-only
facilities would be imposition of the "undue burden" EPA acknowledges it is trying to avoid. To
eliminate any remaining ambiguity in the rule, AMP-Ohio requests express confirmation that the
Proposed Rule, as written, does not mandate Tier 4 reporting at sources that only operate COMS.
Response: EPA has added language to the final rule clarifying that only sources meeting all of
the requirements in §98.33(b)(4)(ii) or (iii) will be required to use Tier 4 methods. Sources
operating only COMS, therefore, will not be required to use Tier 4. EPA does not believe that
any further language is necessary to address this issue.
Commenter Name: J. Southerland
Commenter Affiliation: None
Document Control Number: EPA-HQ-OAR-2008-0508-0165
Comment Excerpt Number: 17
Comment: For simple combustion of carbon based fuels, stoichiometric calculations should
always be acceptable for emissions values. One atom of carbon always will produce one
molecule of carbon dioxide. The mass of carbon in any given fuel is usually known very
precisely.
Response: See the Preamble, Section II. L., for the response on the general monitoring
approach. EPA's Tier 3 approach is based on the fuel carbon content as suggested by the
commenter.
Commenter Name: Helen A. Howes
Commenter Affiliation: Exelon Corporation
Document Control Number: EPA-HQ-OAR-2008-0508-0373.1
Comment Excerpt Number: 22
Comment: Exelon supports the monitoring and emissions calculation methodologies proposed
for stationary combustion. We feel these requirements are largely consistent with the Acid Rain
Program requirements and successfully build on the monitoring and emissions quantification
approaches of this program.
Response: EPA appreciates your support and thanks you for your comment.
163
-------
Commenter Name: Jerry Call
Commenter Affiliation: American Foundry Society (AFS)
Document Control Number: EPA-HQ-OAR-2008-0508-0356.2
Comment Excerpt Number: 9
Comment: AFS agrees with EPA that facilities may quantify CH4 and N20 emissions from fuel
combustion using default emission factors or as an alternative to consider them de minimis and
ignored completely. By EPA's admission, the option of requiring periodic stack testing was too
costly for the small improvement in data quality and the emissions from stationary combustion
source are relatively low compared to C02 emissions.
Response: EPA appreciates the comment, and has retained in the final rule the provision to
report CH4 and N20 from stationary combustion sources based on fuel-specific emission factors.
EPA believes that this approach strikes an appropriate balance between minimizing the burden
on reporters and obtaining valuable GHG emission data. EPA has, however, revised the final
rule to exempt from reporting CH4 and N20 emissions from fuels for which the rule does not
provide emission factors, and has deleted the provision allowing the owner or operator of a
facility to develop site-specific emission factors for such fuels. EPA believes that this change
will reduce the reporting burden on facilities.
Commenter Name: Susan Amodeo Cathey
Commenter Affiliation: Air Liquide USA, LLC
Document Control Number: EPA-HQ-OAR-2008-0508-0464.1
Comment Excerpt Number: 5
Comment: The proposed rule imposes the Tier 4 calculation methodology on sources meeting
the conditions specified under §98.33(b)(5)(ii). As worded, it appears any one of the (A), (B),
(C), or (D) conditions would result in the Tier 4 method being required. Table C-l appears to
indicate that Tier 4 is required only for Solid Fossil Fuel fired units > 250 mmBTU/hr (meeting
other criteria, as well) and that Gaseous Fossil Fuel fired and Liquid Fossil Fuel fired combustion
units are required to use no more rigorous than Tier 3 methods. The current language of
§98.33(b)(5)(ii) would imply any of the conditions described in §98.33(b)(5)(ii)(A), (B), (C) or
(D) trigger the Tier 4 method requirement. EPA should clarify the requirement to employ the
Tier 4 calculation method. Resolve the apparent discrepancy between the intent to limit Tier 4 to
only Solid Fossil Fuel fired combustion units, per Table C-l of the Preamble, with the actual
imposition of Tier 4 described under §98.33(b)(5)(ii). Specifically, conditions (A), (B), (C), and
(D) should be separated by the word "and" - absent that, an implied "or" would force this
calculation method on many other combustion units for which it was not intended.
Response: EPA acknowledges the commenter's concerns regarding Tier 4 applicability. EPA
has revised §98.33(b)(4)(ii) of the final rule to clarify that all criteria must be met before Tier 4 is
required.
164
-------
Commenter Name: Kerry Kelly
Commenter Affiliation: Waste Management (WM)
Document Control Number: EPA-HQ-OAR-2008-0508-0376.1
Comment Excerpt Number: 5
Comment: As the WCI recognized, the substantial costs to implement Tier 4 methodology are
very difficult to justify since the Tier 2 methods provide CO2 emissions of sufficient accuracy.
All of Waste Management's sixteen Wheelabrator MWC facilities have state-of-the-art wet or
dry extractive Part 60 CEMs that use O2 for diluent correction. None of the facilities have stack
gas flow monitors, only two have Part 60 certified C02 CEMS, and half of the facilities have
dry-based CEMS without moisture monitoring. Consequently, for WM and most, if not all, other
large MWCs nationally, extensive CEM retrofits would be required to comply with Tier 4
including: installation of stack flow monitors; installation of moisture monitors for dry based
systems; installation of C02 analyzers and integration into existing CEMs; plant modifications
and integration including: installation of stack flow monitor ports, signal and power wiring,
wiring tray or conduit and new access platforms (depending on suitable flow monitor location);
new CEM data systems for automatic data substitution and reporting; and initial certification of
flow monitoring systems and C02 analyzers. Based upon cost estimates from our approved
CEMS equipment vendors, we estimate WM's costs of installation would range up to $4.5
million, with annual operating costs of a half a million dollars. Further, the purchase,
installation, startup and certification process for the new equipment would likely delay reporting
of 2010 emissions data collection and subsequent reporting.
Response: EPA's estimates of monitoring costs are averages and may not represent the actual
cost in individual circumstances.
Please see the response to comment EPA-HQ-OAR-2008-0508-0544.1 excerpt 4 for additional
information related to methodologies for MSW combustion.
EPA believes that it is appropriate to require the use of CEMS on the largest MSW combustion
sources and any smaller MSW combustion source which already has C02 concentration
monitors and stack gas volumetric flow rate monitors in place. EPA has, however, clarified that
all of the criteria in §98.33(b)(4)(ii) or (iii) must be present to require the use of Tier 4. The
commenter should note that, where all of the monitors necessary for Tier 4 have not been
installed and certified by January 1, 2010, emissions may be reported for 2010 using either Tier 2
or Tier 3. Tier 4 must then be used starting January 1, 2011.
Commenter Name: Susan Amodeo Cathey
Commenter Affiliation: Air Liquide USA, LLC
Document Control Number: EPA-HQ-OAR-2008-0508-0464.1
Comment Excerpt Number: 4
Comment: The proposed rule defines the applicability of the alternate calculation method
"tiers" based on combustion unit size and availability of data, with a general trend to require
more rigorous calculation methods (e.g. increasing from Tier 1 to Tiers 2, 3, and 4) for higher
operating capacity units and facilities that currently employ certain process or emission
165
-------
measurements. This push for more rigorous calculation methods is made without regard for the
underlying accuracy of the calculation method or the quality and completeness of existing
process or emission measurement, or the cost of the necessary measurement equipment or
practice. The result is a rule that often requires a costly, laborious measurement/calculation
method that does not improve the accuracy or completeness of the emission estimate. In many
instances, less rigorous calculation methods (e.g., "lower" Tiers) will yield comparable (or
better) accuracy emission estimates, with higher reliability and at lower cost. EPA should clarify
the applicability of the alternate combustion emission calculation methods. In particular: 1.
Allow use of the Tier 1 method for units of any size (currently restricted to units < 250
mmBTU/hr or less), particularly for standard fuels of commerce such as natural gas, LP gas and
fuel oils, where billing-quality consumption data is accurate and readily available and the default
HHV and CO2 emission factors are well known constants (as noted in the Preamble for the
proposed rule - natural gas carbon content is always within 1% of the default ratio). 2.
Recognize that a source's current practices of occasionally characterizing fuels for HHV or
carbon content does not necessarily constitute having data "available" consistent with the
compliance expectations of Tiers 2 and 3. Where Tiers 2 or 3 would be required, existing fuel
characterization may not be according to the specified analytical methods or at the required
frequency. Do not require Tier 2 or 3 where data fully meeting the defined compliance
expectation is not currently being obtained.
Response: See the Preamble, Section II. L., on General Monitoring Requirements for the overall
rationale for methodologies required under this rule, and the response to comment EPA-HQ-
OAR-2008-0508-0909.1 excerpt 4 and EPA-HQ-OAR-2008-0508-0580 excerpt 10 for the
rationale for methodologies required under Subpart C.
EPA disagrees with the commenter's suggestion of allowing Tier 1 reporting for all facilities and
the claim that more rigorous methods do not improve accuracy. Methodologies that reflect the
variability of fuels across units and facilities through sampling and measurement are more
accurate than methodologies that do not account for this variability (General Stationary
Combustion Technical Support Document, EPA-HQ-OAR-2008-0508-0004). The gains from
measurement vary by fuel type (i.e., heterogeneity of carbon content and heat rate is lower in
some fuels) and the final rule accounts for this difference by varying the requirements for units,
with due consideration of burden and cost.
EPA did not choose to adopt a simplified calculation method approach (e.g., using default
emission factors) for all units because the data would be less accurate than under the selected
option and would not make use of site-specific data that many facilities already have available
and refined calculation approaches that many facilities are already using. EPA has, however,
expanded the use of the Tier 2 calculation methodology based on fuel heating value to units of
any size in which the only fossil fuels combusted are pipeline quality natural gas, and/or distillate
oil, in view of the homogeneous nature of these fuels. EPA believes that the final rule makes it
clear that a unit will only be required to use Tier 2 (if it otherwise qualifies for Tier 1) if the
owner or operator routinely performs fuel sampling and analysis for the fuel high heat value or
routinely receives the results of HHV sampling from the fuel supplier at the minimum frequency
specified in §98.34.
166
-------
Commenter Name: Mike Aire
Commenter Affiliation: Newmont Mining Corporation (NMC)
Document Control Number: EPA-HQ-OAR-2008-0508-0378.1
Comment Excerpt Number: 4
Comment: Newmont requests more details on how a facility boundary is determined.
Response: In response to the comment, the Agency does not believe any additional language is
needed to clarify the definition of "facility." The use of the term in this part is addressed in §98.6
of the final rule with a detailed description of its meaning. The explanation provided states that
"Facility means any physical property, plant, building, structure, source, or stationary equipment
located on one or more contiguous or adjacent properties in actual physical contact or separated
solely by a public roadway or other public right-of-way and under common ownership or
common control, that emits or may emit any greenhouse gas. Operators of military installations
may classify such installations as more than a single facility based on distinct and independent
functional groupings within contiguous military properties."
Commenter Name: Kerry Kelly
Commenter Affiliation: Waste Management (WM)
Document Control Number: EPA-HQ-OAR-2008-0508-0376.1
Comment Excerpt Number: 2
Comment: EPA's most recent national GHG inventory (Inventory of U.S. Greenhouse Gas
Emissions and Sinks: 1990 - 2007, April 2009) reports WTE facilities emit very small amounts
of GHG relative to other electricity producing sources. Municipal waste combustors account for
only 0.34 percent of total CO2 equivalent emissions from all Energy Related Activities (20.8 Tg
CC>2e from a total of 6170.3 Tg C02e from the entire source category) and only 0.55 percent of
total CC^e emissions from the Combustion Source sector in EPA's proposed reporting rule.
Based on WTE's relatively small contribution to GHG emissions in their sector, WM suggests
that more flexible and cost effective GHG reporting requirements are appropriate and would
result in data of sufficient accuracy and reliability to meet EPA's needs.
Response: The commenter did not make a specific suggestion for revised reporting
requirements. EPA believes that it is appropriate to require the use of CEMS on the largest
MSW combustion sources and any smaller MSW combustion source which already has CO2
concentration monitors and stack gas volumetric flow rate monitors in place. EPA has, however,
clarified that all of the criteria in §98.33(b)(4)(ii) or (iii) must be present to require the use of
Tier 4.
167
-------
Commenter Name: Stephen E. Woock
Commenter Affiliation: Weyerhaeuser Company
Document Control Number: EPA-HQ-OAR-2008-0508-0451.1
Comment Excerpt Number: 2
Comment: We direct EPA's attention to the unnecessary burden (and counter-productive
emergence of a potentially substantial carbon footprint from a new national sampling and testing
program) of making frequent direct measurements of carbon content or heat content of fuels for
stationary combustion sources when the requisite accuracy can be achieved, as allowed under
most GHG reporting systems, by use of activity data, emissions factors and engineering
calculations, which EPA outlines in the Tier 1 requirements.
Response: See the Preamble, Section II. L., on General Monitoring Requirements for the overall
rationale for the methodologies required under this rule, and the response to comment EPA-HQ-
OAR-2008-0508-0909.1 excerpt 4 and EPA-HQ-OAR-2008-0508-0580 excerpt 10 for the
rationale for methodologies required under Subpart C.
EPA disagrees with the commenter's suggestion of allowing Tier 1 reporting for all facilities.
EPA did not choose to adopt a simplified calculation method approach (e.g., using default
emission factors) for all units because the data would be less accurate than under the selected
option and would not make use of site-specific data that many facilities already have available
and refined calculation approaches that many facilities are already using. Methodologies that
reflect the variability of fuels across units and facilities through sampling and measurement are
more accurate than methodologies that do not account for this variability. The gains from
measurement vary by fuel type (i.e., heterogeneity of carbon content and heat rate is lower in
some fuels) and the final rule accounts for this difference by varying the requirements for units,
with due consideration of burden and cost.
However, the commenter should note that the mandatory fuel sampling and analysis
requirements for Tiers 2 and 3 have also been considerably revised in order to reduce the burden
on reporters. §98.34 of the final rule requires that natural gas be sampled semiannually. For fuel
oil and coal, a representative sampling is required for each fuel lot, i.e., for each shipment or
delivery. For other liquid fuels and biogas, quarterly sampling is required. For other solid fuels,
excluding municipal solid waste, weekly composite sampling with monthly analysis is required.
For other gaseous fuels, the daily sampling requirement has been retained, but only for facilities
with existing equipment in place that is capable of providing the data. Otherwise, weekly
sampling is required. The final rule also clarifies that fuel sampling and analysis data provided
by the supplier may be used in the emission calculations.
Commenter Name: Randal G. Oswald
Commenter Affiliation: Integrys Energy Group, Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-0569.1
Comment Excerpt Number: 2
Comment: The measurement of distillate oil or natural gas fuel flow meters in Subpart C should
include fuel flow meters that measure mass flow. Similarly the calculations methods should
168
-------
include equations for the use of fuel flow meters that measure mass flow. It seems that Subpart
C, Tier 3 methodology presumes that the quantity of liquid or gaseous fuel combusted is directly
measured as a volume of liquid or gaseous fuel. Fuel flow meters may directly measure volume
or mass of fuel combusted. The Tier 3 methodology should be expanded to account for either
type of fuel flow meter.
Response: EPA has added language to Subpart C, allowing the use of fuel flow meters that
measure mass flow rates for liquid fuels, provided that the fuel density is used to convert the
readings to volumetric flow rates. For most fuels, the reporter must determine the density of the
fuel using the methods provided, though default densities for certain fuel oils have been
provided.
Commenter Name: Michael E. Van Brunt
Commenter Affiliation: Covanta Energy Corporation
Document Control Number: EPA-HQ-OAR-2008-0508-0548.1
Comment Excerpt Number: 2
Comment: The Proposed Rule would require EfW facilities to install new equipment and
initiate new operating and testing procedures to implement the Tier 4 methodology as currently
written. The increased cost would not increase the quality of data but it would increase the
operating cost borne by the owner, often municipalities. The EfW facility is a small source of
GHG emissions due to the combustion process but it is a GHG mitigation technology on a
lifecycle assessment basis.
Response: Please see the response to comment EPA-HQ-OAR-2008-0508-0544.1 excerpt 4 for
a discussion of the requirements for units combusting MSW.
EPA believes that it is appropriate to require the use of CEMS on the largest MSW combustion
sources and any smaller MSW combustion source which already has CO2 concentration
monitors and stack gas volumetric flow rate monitors in place. EPA has, however, clarified that
all of the criteria in §98.33(b)(4)(ii) or (iii) must be present to require the use of Tier 4.
Commenter Name: Randal G. Oswald
Commenter Affiliation: Integrys Energy Group, Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-0569.1
Comment Excerpt Number: 1
Comment: Subpart C, Tier 4 monitoring methods should include the option to employ 40 CFR
part 75 Appendix D and G excepted monitoring methods for distillate oil and natural gas fired
combustion units of any size. Under subpart D-Electricity Generation of the proposed rule, Acid
Rain Program (ARP) affected units shall continue to monitor and report CO2 mass emissions in
accordance with the monitoring requirements of 40 CFR Part 75. ARP affected units must install
CO2 or O2 and flow continuous emission monitors (CEMS). However, for certain distillate oil
and natural gas ARP affected units, excepted monitoring methods may be used in lieu of CEMS.
The excepted method of 40 CFR Part 75 Appendix D and Appendix G yield hourly or daily CO2
emissions acceptable for the Mandatory Greenhouse Gas Reporting Rule. Electrical Generating
Units not affected by the ARP monitor CO2 emissions under a four tiered system of Subpart C of
169
-------
the proposed rule. Distillate oil and natural gas units may elect to employ Tier 4 monitoring
methods. Tier 4 only allows CO2 or O2 and flow CEMS which are quality assured in accordance
with 40 CFR Part 75 requirements. Not included in the Tier 4 monitoring methods of Subpart C
are the excepted monitoring methods found in 40 CFR Part 75. It seems only logical that if the
Part 75 excepted monitoring methods are satisfactory for measuring, reporting, and quality
assuring CO2 emissions from ARP affected units, then the Part 75 excepted methods are
satisfactory for measuring, reporting, and quality assuring C02 from non-ARP affected units.
Response: The commenter should note that EPA has added alternative methods for units that
report data to EPA according to Part 75, which allow certain oil- and gas-fired units to use
methods from Appendices D and G to Part 75. See §98.33(a)(5) of the final rule.
Commenter Name: Mike Aire
Commenter Affiliation: Newmont Mining Corporation (NMC)
Document Control Number: EPA-HQ-OAR-2008-0508-0378.1
Comment Excerpt Number: 1
Comment: Sample Frequency of Carbon Content "For gaseous fuel combustion, EPA
considered calculation methodologies based on an assumption that all gaseous fuels are
homogeneous. However, the Agency decided against this approach because the characteristics
of certain gaseous fuels can be quite variable, and mixtures of gaseous fuels are often
heterogeneous in composition. Therefore, the proposed rule requires daily sampling for all
gaseous fuels except for natural gas." Specifically, Newmont requests EPA treat propane as a
homogeneous fuel. Newmont uses propane in our Carlin roaster during the winter months. Our
propane is stored in two large tanks. Each tank is a homogeneous mixture of propane that does
not change day to day. Each tank supplies gas to our roaster for one to two weeks. Once a tank
reaches a low level set-point, supply is switched to the other tank. Since the gas in a tank is
homogeneous, Newmont recommends sampling frequency be reduced to sampling each tank
upon filling rather than daily. The daily carbon content sampling requirement for gaseous fuels
seems overly onerous and it is recommended that sampling requirements for these fuels be
required monthly, consistent with requirements for other fuels. The Draft Rule requires monthly
carbon content sampling for natural gas, solid and liquid fuels. Newmont requests that EPA
lower the requirement for sampling non-gaseous fuels to new deliveries rather than monthly in
order to pinpoint the onset of fuel parameter variations.
Response: EPA has provided a default emission factor (kg C02/mmBtu) and HHV
(mmBtu/gallon) in Table C-l for propane.
Commenter Name: Lorraine Krupa Gershman
Commenter Affiliation: American Chemistry Council (ACC)
Document Control Number: EPA-HQ-OAR-2008-0508-0423.2
Comment Excerpt Number: 47
Comment: EPA has requested comment on integrating fuel supplier requirement for HHVs and
carbon content for Tier 1 and Tier 2 methodologies, which was not proposed. ACC recommends
170
-------
that EPA should require that the fuel supplier provide data for measured HHV and carbon
content for all fuels in commerce. Requiring the fuel supplier to provide this information instead
of the fuel users eliminates unnecessary duplication of analysis of the same fuel by multiple
users. For example, one fuel supplier might supply many units within an industrial area, and
requiring the fuel supplier to provide the data would reduce the number of required analyses
correspondingly. In addition, when making this change, EPA should then alter the requirements
in §98.34(c) and (d) such that operators of stationary combustion devices do not need to obtain
fuel analytical data when it is required to be provided by the fuel supplier.
Response: The final rule clarifies that fuel sampling and analysis data provided by the supplier
may be used in the emission calculations. However, EPA has not required fuel suppliers to
provide HHV and carbon content data to facilities, as it is the source's responsibility to determine
emissions, and it is the role of private sector transactions to specify the terms of information
conveyed with fuel purchases. Fuel suppliers have their own reporting requirements in other
subparts.
Commenter Name: Kerry Kelly
Commenter Affiliation: Waste Management (WM)
Document Control Number: EPA-HQ-OAR-2008-0508-0376.1
Comment Excerpt Number: 1
Comment: The MRR proposes to require all municipal waste combustors (MWC) with a
maximum rated input capacity of greater than 250 tons per day of MSW to use the Tier 4
calculation methodology. This requirement is problematic as it does not reflect current
regulatory requirements nor best management practices for MWCs; will be very costly and
onerous for these small GHG emitters; and will not result in commensurate enhancements in
reporting accuracy. Further, the GHG emission calculation methodology imposed on MWCs is
out of proportion to the sector's relative GHG emissions when compared to other electricity
generators. As we note below, other GHG reporting programs allow MWCs to use the Tier 2
calculation methodology. In fact, EPA proposes in the MRR to allow fossil fuel-fired, stationary
combustion sources with far greater GHG emissions than MWCs to use the Tier 2 calculation
methodology. We urge the Agency to reconsider requiring MWCs to use the Tier 4
methodology and recommend that MWCs use a modified Tier 2 methodology analogous to the
Title V program methods used for annual reporting of criteria pollutants and hazardous air
pollutants (HAP).
Response: Please see the response to comment EPA-HQ-OAR-2008-0508-0544.1 excerpt 4 for
an explanation of the requirements for units that combust MSW.
EPA believes that it is appropriate to require the use of CEMS on the largest MSW combustion
sources which already have CO2 concentration monitors and stack gas volumetric flow rate
monitors in place. EPA has, however, clarified that all of the criteria in §98.33 (b)(4)(ii) or (iii)
must be present to require the use of Tier 4. EPA believes that it is appropriate for MSW
combustion units to use ASTM D6866-06a and D7459-08 on a quarterly basis to determine the
relative proportions of biogenic and non-biogenic CO2 emissions from the MSW combusted.
Where Tier 2 is used, EPA has provided for MSW combustion units to determine total CO2
emissions from the amount of steam produced, boiler design, and a default CO2 emission factor.
171
-------
EPA believes that this is more appropriate than determining site-specific factors during annual
testing. Where Tier 4 is used, CO2 emissions are determined using a CO2 concentration monitor
and a stack gas volumetric flow rate monitor. Biogenic emissions for the MSW combustion unit
are then calculated by multiplying the total CO2 emissions for the year, determined using Tier 2
or 4, by the fraction of biogenic emissions, determined using the ASTM methods.
Commenter Name: Chris Hornback
Commenter Affiliation: National Association of Clean Water Agencies (NACWA)
Document Control Number: EPA-HQ-OAR-2008-0508-0566.1
Comment Excerpt Number: 12
Comment: NACWA recommends that EPA provide additional flexibility and guidance for
using actual emissions data to calculate emissions. Many of the factors included in the proposal
could be debated or changed, and NACWA believes that many POTWs may have additional
information on their combustion units that could provide for more accurate estimates. For
example, a number of POTWs will be conducting tests to determine N2O emissions associated
with the burning of biomass. POTWs should be allowed to use the results from these tests to
determine their emissions, rather than using the default heating values and emission factors
provided by EPA to calculate emissions.
Response: For simplicity and consistency, EPA will require use of specified default values for
CH4 and N2O, and the Agency has expanded the number of fuels with default CH4 and N2O
emission factors.
Commenter Name: Jerry Call
Commenter Affiliation: American Foundry Society (AFS)
Document Control Number: EPA-HQ-OAR-2008-0508-0356.2
Comment Excerpt Number: 7
Comment: In reference to proposed section 98.33(a)(1), EPA should allow use of site specific
fuel analysis information that would be more representative of fuels combusted than the default
values and may be available less frequently than monthly for both Tier 1 (use of the Table C-l
default values) and Tier 2 (use of monthly analyses) methodologies. Sections 98.33(a)(2) and (3)
of the proposed regulation, requires monthly analyses of fuels for Tier 2 and 3 (periodic
determination of the carbon content of the fuel use 40 CFR part 98 and direct measurement)
methodologies. Pipeline quality natural gas and liquid fuels meeting a purchase specification
typically do not vary significantly over time. Accordingly, a single analysis or supplier analysis
should be adequate. By allowing these more flexible methodologies, EPA can lower compliance
and reporting costs and, therefore, minimize the regulatory burdens associated with this proposed
rule.
Response: The mandatory fuel sampling and analysis requirements for Tiers 2 and 3 have been
considerably revised. EPA agrees with the commenters that for a homogeneous fuel such as
pipeline natural gas, monthly sampling is not necessary. For other fuels such as oil and coal,
which are delivered in shipments or lots, requiring monthly sampling may be impractical; new
172
-------
fuel lots or deliveries may not be received on a monthly basis. Therefore, §98.34 has been
revised to require that natural gas be sampled semiannually. For fuel oil and coal, a
representative sampling sample is required for each fuel lot, i.e., for each shipment or delivery.
For other liquid fuels and biogas, quarterly sampling is required. For other solid fuels, excluding
municipal solid waste, weekly composite sampling with monthly analysis is required. For other
gaseous fuels, the daily sampling requirement has been retained, but only for facilities with
existing equipment in place that is capable of providing the data. Otherwise, weekly sampling is
required. To simplify the emission calculations in Tiers 2 and 3, arithmetic averaging of HHV
and carbon content data is permitted if these data are obtained at least at the minimum frequency
specified in §98.34, but less frequently than monthly (see §98.33(a)(2)(ii)). If sampling is more
frequent, the reporter must calculate a weighted average according to Equation C-2b. However,
regardless of the sampling frequency, the owner or operator must use the results of all available
valid fuel analyses in the emissions calculations. EPA believes that these revised requirements
provide the flexibility the commenter requested.
Commenter Name: Robert P. Strieter
Commenter Affiliation: The Aluminum Association
Document Control Number: EPA-HQ-OAR-2008-0508-0350.1
Comment Excerpt Number: 2
Comment: Although the Aluminum Association agrees that the GHG reporting rule should
include direct emissions from significant combustion sources within a facility, it has some
concerns with the approach proposed in the rule. Specifically, the proposed tiered reporting
protocol included is overly complex and burdensome. In effect, many facilities with various
sized combustion units will have to comply with an array of reporting tiers at the process unit
level that are complex and expensive to conduct. The complexity of the additional carbon
content measurements and heating value measurements will add recordkeeping burdens and
costs that are incommensurate with the small potential increase in GHG emission accuracy that
could be obtained. This is especially true for gas and liquid fuels that have relatively constant
carbon contents. We propose revising to the proposed rule to require only for tier one reporting
of gaseous and liquid fuels, and to allow tier two and three reporting only when the reporting
facility desires to conduct the additional reporting tiers as an opt-in effort. The provision for
only tier one reporting should apply at the very least to small and medium size facilities. The use
of fuel specific emission factors for fuel combustion sources is sufficient to meet the goals and
objectives of the reporting protocol and should be incorporated in the proposed rule. Since EPA
has already developed and established such a reporting mechanism under the Climate Leaders
program that has been successfully used by a collection of industries for most of the past decade,
it is reasonable to adopt this proven approach here as well. The Climate Leaders Stationary
Source Guidance is available at the following website: http://www.epa.gov/stateply/documents/
resources/stationarycombustionguidance.pdf. Accordingly, EPA should incorporate the Climate
Leaders stationary combustion source reporting guidance in the mandatory GHG reporting
program for three important reasons: (1) it provides a suitable technical means for reporting that
is accurate and cost effective; (2) it provides continuity with the industries that have been
reporting and will continue to report under the Climate Leaders program, and (3) it is consistent
with international reporting requirements.
173
-------
Response: See the Preamble, Section II. L., for the response on the general monitoring
approach.
See the response to comment EPA-HQ-OAR-2008-0508-0464.1 excerpt 4 for information on
EPA's approach to methodological tiers.
EPA did not choose to adopt a simplified calculation method approach (e.g., using default
emission factors) for all units because the data would be less accurate than under the selected
option and would not make use of site-specific data that many facilities already have available
and refined calculation approaches that many facilities are already using. However, EPA has
significantly expanded the use of Tier 1 and Tier 2 Calculation Methodologies. Most units
combusting only the biogenic fuels listed in Table C-l may use Tier 1. The 250 mmBtu/hr
restriction on the use of Tier 2 has been lifted for units in which the only fossil fuels combusted
are pipeline quality natural gas and/or distillate oil, in view of the homogeneous nature of these
fuels. However, the 250 mmBtu/hr unit size cutoff remains for units that combust other fossil
fuels.
Commenter Name: Natasha Meskal
Commenter Affiliation: Ecotek
Document Control Number: EPA-HQ-OAR-2008-0508-0346
Comment Excerpt Number: 1
Comment: We would suggest the following standardized units for fuels: Gaseous: mmscf,
Liquid: 1000 gallons, Solid: tons. There are few reasons we are suggesting specific units: Most
of the local Districts collect the fuel usage data in the proposed units - consequently I believe
that a big number of facilities that will be subject to reporting already have tracking systems set
up to track their usage in the mentioned units. If industry (or some of the local governments)
consider the consolidated reporting of criteria, toxics and GHG emissions - it will allow for
easier data transfer and minimize chances for conversion/data entry errors. And the main reason
for suggesting these particular standardized units is the fact that EPA FIRE (most commonly
used compilation of default emission factors on national level) tends to offer default emission
factors either in proposed units or in lbs/heating value. Recently a lot of work/improvements
were done on FIRE. It already contains some GHG default emission factors that I hope, will
soon be greatly expanded.
Response: EPA believes that the units of short tons for solid fuel, standard cubic feet for
gaseous fuel, and gallons for liquid fuel are appropriate. Different companies and industries use
different units, and EPA is unable to standardize across all of them. The units EPA requires are
sufficiently common in usage that EPA does not believe that it will be burdensome for facilities
which track fuel usage in other units to convert to these units for the purpose of calculating GHG
emissions.
174
-------
Commenter Name: Carl H. Batliner
Commenter Affiliation: AK Steel Corporation
Document Control Number: EPA-HQ-OAR-2008-0508-0337.1
Comment Excerpt Number: 8
Comment: Steel Industry facilities may have several combustion sources having a maximum
heat input capacity greater than 250 MMBtu/hr. These sources include coke battery underfiring,
slab reheat furnaces, as well as boilers. The sources may be fueled by coke oven gas, blast
furnace gas, and or natural gas. Subpart C requires these sources to utilize Tier 4 methodology
to calculate GHG emissions based on the heat input rating. However, these sources are not
typically equipped with the instrumentation to comply with Tier 4 methodology, and
requirements to install such equipment are contrary to statements elsewhere in the rule that new
monitoring equipment is not required. Utilizing Tier 1 methodology has always been sufficient
for calculating criteria pollutant emissions for emission inventory reporting for combustion
sources. AK Steel believes that it should be sufficient for GHG emission reporting too and
respectfully requests that EPA consider stipulating Tier 1 methodology regardless of the
combustion unit's heat input capacity. The additional cost and burden to implement and operate
Tier 4 methodology does not justify the minimal, if any, benefit gained.
Response: EPA has clarified the criteria for use of the Tier 4 methodology in §98.33(b)(4)(ii) of
the final rule such that all the conditions specificied must be met for Tier 4 to be required.
EPA disagrees with the commenter's suggestion of allowing Tier 1 reporting for all facilities.
See the response to comment EPA-HQ-OAR-2008-0508-0464.1 excerpt 4 for more explanation
of EPAs approach to methodological tiers.
EPA, however, has significantly expanded the use of the Tier 2 Calculation Methodology for
units that combust only natural gas and/or distillate oil, in view of the homogeneous nature of
these fuels. However, the Tier 3 methodology is still required for large 250 mmBtu/hr units that
combust residual oil, solid fossil fuel, and other gaseous fuels (including coke oven gas and blast
furnace gas).
EPA also has limited the Tier 3 requirement to fuels that make up at least ten percent of the
annual heat input for a unit or group of units.
Commenter Name: Carl H. Batliner
Commenter Affiliation: AK Steel Corporation
Document Control Number: EPA-HQ-OAR-2008-0508-0337.1
Comment Excerpt Number: 7
Comment: In the event that EPA decides not to delete the reporting requirement for coke oven
gas and blast furnace gas combustion for the Steel Industry, EPA needs to consider that
combustion of coke oven gas and blast furnace gas in various sources is a common function.
Subpart C requires the reporting of CH4 and N2O emissions from all combustion sources using
default values for various fuels shown in Table C-3. However, no values are presented for coke
oven gas and blast furnace gas. In addition, we are not aware of any reliable emission factors for
175
-------
CH4 and N20 for coke oven gas and blast furnace gas combustion but believe concentrations of
these emissions to be insignificant, if present at all, in the exhaust gases. Accordingly, AK Steel
requests that EPA delete the requirement to include CH4 and N20 emission estimates for coke
oven gas and blast furnace gas combustion sources.
Response: EPA acknowledges the concerns of the commenter. Table C-2 has been revised to
include CH4 and N20 emission factors for more fuels, including blast furnace gas and coke oven
gas, as well as generic emission factors covering all fuel types listed in Tables C-l. EPA has
also deleted §98.33(c)(4), which allowed facilities burning other fuels to develop site-specific
emission factors based on the results of source testing, and revised the rule to require reporting of
CH4 and N20 emissions only from fuels listed in Table C-2.
Commenter Name: MarkNordheim
Commenter Affiliation: Western States Petroleum Association
Document Control Number: EPA-HQ-OAR-2008-0508-0228k
Comment Excerpt Number: 3
Comment: The second area I want to talk a little bit about is the use of continuous emission
monitors. We've read and reread the sections in the rule and Preamble that relate to Tier 4. And
certainly several of us see an inconsistency in the Preamble language and the actual language
text. It was kind of interesting, I've worked with the California rule so long I start reading the
rules. My peers start reading the Preamble. And we didn't have the same answer because the
language in the rule specifically says in Tier 4 anybody over, with a heater and boiler over
250,000,000 BTU/hour design capacity has a continuous emission monitor. For us, because we
have in a typical refinery, we will have 50-plus heaters and boilers, some of which have dual
stacks. For Chevron, as an example, that would mean 15 continuous emission monitors that
would have to be installed, which wouldn't essentially be of any value to us in the construct of
the ARB rule or the WCI. We'd have to report those emissions, subtract those from emissions
that come from our central fuel systems. And so we'd end up with spending a lot of money on
continuous analyzers or continuous stack analyzers. We are continuously measuring flow and
would be required to measure our carbon content daily. So we think we can get very accurate
numbers. So I don't know what is right or wrong, the Preamble or the rule. But clearly we
would go forward on the Preamble characterization of the requirement.
Response: EPA acknowledges the commenter's concerns regarding Tier 4 applicability. EPA
has revised §98.33(b)(4)(ii) of the final rule to clarify that all six criteria specified in
subparagraphs (A) through (F) must be met before Tier 4 is required.
176
-------
Commenter Name: Scott Evans
Commenter Affiliation: CleanAir Engineering (Clean Air)
Document Control Number: EPA-HQ-OAR-2008-0508-0696.1
Comment Excerpt Number: 2
Form Letter? Yes
Comment: We encourage EPA to consider the use of Predictive Emission Monitoring Systems
(PEMS) for those sources where such systems are approved for use for other purposes or where
they make sense. We feel that a properly designed and calibrated PEMS can provide data that is
as reliable as a CEMS. We recognize that not all sources are good candidates for PEMS but we
do feel that for those that are, PEMS should be allowed. Since EPA has recently promulgated
Performance Specification 16, there exists a mechanism for ensuring any installed PEMS
continues to meet the highest data quality specifications. We feel PEMS should be included in
Tier 4 methodology.
Response: The Agency acknowledges the concerns of the commenters, but has only required
the Tier 4 methodology for large solid fuel-fired units and MWC units that already are required
to have a gas monitor or a stack gas volumetric flow rate monitor, or both. The Tier 4
methodology is being prescribed to large these units because it is difficul to measure fuel
consumption rates. Inclusion of PEMS in Tier 4, as an alternative to CEMS, is inappropriate,
because PEMS are not suitable for use on units that combust solid fossil fuel. Rather, PEMS are
primarily used to estimate NOx emissions from gas turbines, and gas-fired boilers. Under the
Acid Rain Program, EPA has approved the use of PEMS only for these two applications. The
Agency is not opposed to innovative, alternative approaches for estimating C02 mass emissions.
However, the commenter did not provide any supplementary information explaining how a
PEMS could be used to predict CO2 mass emissions, or why Tier 4 would be the appropriate
place for this methodology. In view of this, EPA has not incorporated the commenter's
suggested approach into the final rule, but is willing to consider it in a future rulemaking, if the
necessary technical details of the method are provided for Agency review.
Commenter Name: Scott Evans
Commenter Affiliation: Clean Air Engineering
Document Control Number: EPA-HQ-OAR-2008-0508-0228e
Comment Excerpt Number: 3
Comment: The last thing that I would like to comment on is some other technologies in terms
of measurement. The proposal is silent on predictive emission monitoring systems. As you
know, EPA has just come out with a performance specification for PEMS that subjects these
software-based monitoring solutions to the same kinds of QA/QC that continuous emission
monitors are, which may provide an alternative for some sources. I don't want to say that PEMS
are not applicable, I don't believe, to every kind of source. For those that it would be appropriate
for, that might provide an alternative to hardware CEMS that may provide data of high quality.
And, of course, the other thing I mentioned previously is to allow the use of thermo dynamic
modeling to replace or as an alternative, let's say, to direct measurement of coal fuel feed for
those choosing to use the calculation approach.
177
-------
Response: The commenter suggests that PEMS may be a suitable alternative to CEMS that can
provide data of high quality. However, PEMS are not suitable for use on units that combust
solid fossil fuel. Rather, PEMS are primarily used to estimate NOx emissions from gas turbines,
and gas-fired boilers. The Agency is not opposed to innovative, alternative approaches for
estimating C02 mass emissions, but the commenter did not provide any supplementary
information explaining how a PEMS could be used to predict CO2 mass emissions. In view of
this, EPA has not incorporated the commenter's suggested approach into the final rule, but is
willing to consider it in a future rulemaking, if the necessary technical details of the method and
a cost analysis are provided for Agency review.
Commenter Name: Scott Evans
Commenter Affiliation: Clean Air Engineering
Document Control Number: EPA-HQ-OAR-2008-0508-0228e
Comment Excerpt Number: 1
Comment: I would like to support EPA's proposed tier structure with regard to monitoring,
which puts measurement first, in the highest tier. I'm the one that delivered that paper on air and
waste that the previous speaker referred to. In fact, there are large discrepancies between
measured and calculated C02 emissions despite the protestations of some that the data simply is
there that shows there is a discrepancy. And a lot of that comes from uncertainty in the fuel feed
rate, which is necessary for doing the calculations. The research that we have done indicated that
there could be up to a 20 percent uncertainty in how much coal is going into a large utility boiler.
And actually EPA had solicited comment on how to quantify this uncertainty. Unfortunately, the
direct answer is somewhat onerous in that, like any instrument, a belt feeder or some other way
of feeding the coal into the boiler needs to be calibrated on a regular basis. This becomes
progressively problematic because it is in continuous use and is on line. The only opportunity
really to do that is during infrequent outages. An alternative to that, to specifically address your
comment about uncertainty in fuel feed rate, is to move away from actual direct measurement of
fuel feed as many plants are doing right now. They are moving toward a thermo dynamic model
to calculate heat input from which you can then determine fuel feed. That has proven to be more
accurate than just looking at measuring the coal going into a boiler; and that possibility is not
specifically addressed in the proposal and potentially should be.
Response: EPA has required Tier 4 CEMS and stack flow rate monitors for certain solid fuel
fired units (units with a gas CEMS or flow rate monitor) because of the difficulty and complexity
of monitoring solid fuel consumption noted by the commenter. In Tier 2, EPA has expanded the
use of steam production and combustion unit efficiency to calculate CO2 emissions to other solid
fuels in addition to municipal solid waste (MSW). These parameters may also be used to
quantify the amount of biomass combusted in a unit. The commenter should note that in Tier 3,
solid fuel use is determined based on company records, which could involve calculations such as
those suggested by the commenter.
178
-------
Commenter Name: Lorraine Krupa Gershman
Commenter Affiliation: American Chemistry Council (ACC)
Document Control Number: EPA-HQ-OAR-2008-0508-0423.2
Comment Excerpt Number: 103
Comment: We encourage EPA to be more flexible as it relates to the applicability to the
alternate combustion emission calculation methods. In particular: (1) Allow use of the Tier 1
method for units of any size (currently restricted to units < 250 mm BTU/hr or less), particularly
for standard fuels of commerce such as natural gas, LP gas and fuel oils, where billing-quality
consumption data is accurate and readily available and the default HHV and C02 emission
factors are well known constants (as noted in the Preamble for the proposed rule - natural gas
carbon content is always within 1% of the default ratio). (2) Recognize that a source's current
practices of occasionally characterizing fuels for HHV or carbon content does not necessarily
constitute having data Available' consistent with the compliance expectations of Tiers 2 and 3.
Where Tiers 2 or 3 would be required, existing fuel characterization may not be according to the
specified analytical methods or at the required frequency. Do not require Tier 2 or 3 where data
fully meeting the defined compliance expectation is not currently being obtained. (3) Do not
require the use of the Tier 4 method where alternative fuel consumption data is available. Allow
optional use of the Tier 4 method where, at the source's discretion. This may be a suitable
calculation method where a source uses multiple fuels and/or non-commercial fuels or where
existing CEMS systems include CO2 measurement or can be modified at lower cost than
alternative fuel consumption and/or characterization devices/practices. In any case, let the
regulated source determine which method is most cost effective for their particular situation.
Response: See the Preamble, Section II. L., for the response on the general monitoring
approach.
See the response to comment EPA-HQ-OAR-2008-0508-0464.1 excerpt 4 for an explanation of
the approach to methodological tiers.
EPA disagrees with the commenter's suggestion of allowing Tier 1 reporting for all facilities.
EPA did not choose to adopt a simplified calculation method approach (e.g., using default
emission factors) because the data would be less accurate than under the selected option and
would not make use of site-specific data that many facilities already have available and refined
calculation approaches that many facilities are already using. EPA has, however, expanded the
use of the Tier 2 calculation methodology based on fuel heating value to units of any size in
which the only fossil fuels combusted are pipeline quality natural gas, and/or distillate oil, in
view of the homogeneous nature of these fuels. EPA believes that the final rule makes it clear
that a unit will only be required to use Tier 2 (if it otherwise qualifies for Tier 1) if the owner or
operator routinely performs fuel sampling and analysis for the fuel high heat value or routinely
receives the results of HHV sampling from the fuel supplier at the minimum frequency specified
in §98.34.
The Tier 4 CEMS requirement is limited to larger solid fossil fuel units with an existing pollutant
CEMS or volumetric flow rate monitor. EPA is requiring the use of CEMS due to the
complexity of monitoring solid fuel consumption and the heterogeneous nature of the solid fuels.
Many of these fossil fuel-fired units with a pollutant CEMS have an existing diluent monitor (O2
or CO2) that can be used to determine CO2 emissions.
179
-------
Commenter Name: Lorraine Krupa Gershman
Commenter Affiliation: American Chemistry Council (ACC)
Document Control Number: EPA-HQ-OAR-2008-0508-0423.2
Comment Excerpt Number: 56
Comment: EPA has requested comment on the use of more technology-specific CH4 and N20
emission factors that could be applied in unit-level calculations for §98.33(c). ACC recommends
that EPA eliminate CH4 and N20 calculations entirely due to their negligible impact on the total
greenhouse gas inventory and on a facility's emissions. In §98.33(c), according to the formulae
provided, less than 0.00001 percent of the greenhouse gas emissions would be CH4 or N20.
Therefore, EPA should not require calculation and reporting of these emissions because their
contribution to the total is insignificant.
Response: Please see the response to comment EPA-HQ-OAR-2008-0508-0561.1 excerpt 2 for
further explanation of EPA's approach to reporting of CH4 and N20 from stationary combustion
sources. EPA acknowledges the concerns of the commenter. However, EPA has decided to
retain in the final rule the requirement to report CH4 and N20 from stationary combustion
sources. EPA believes that the use of fuel-specific emission factors for these pollutants strikes
an appropriate balance between minimizing the burden on reporters and obtaining valuable GHG
emission data. EPA has, however, revised the final rule to exclude CH4 and N20 emissions
from fuels for which the rule does not provide emission factors, and has deleted the provision
allowing the owner or operator of a facility to develop site-specific emission factors for such
fuels. EPA believes that this change will reduce the reporting burden on facilities.
Commenter Name: Lorraine Krupa Gershman
Commenter Affiliation: American Chemistry Council (ACC)
Document Control Number: EPA-HQ-OAR-2008-0508-0423.2
Comment Excerpt Number: 54
Comment: Section 98.33(b)(5)(ii)(E) does not specify that the CEMS installed must be a
CEMS for monitoring C02. ACC believes that EPA meant a C02 analyzer, and should specify
accordingly to eliminate any uncertainty. If EPA meant any CEMS monitoring device regardless
of the CEMS ability to monitor C02 without additional equipment modification and possibly
equipment purchase, then we recommend that EPA change the requirement to apply to existing
C02 CEMS only. Requiring the added capability to monitor for other constituents is
unnecessarily costly and not necessary for ensuring an appropriate level of accuracy for purposes
of compiling an inventory.
Response: See the response to comment EPA-HQ-OAR-2008-0508-0455.1 excerpt 7 and the
response to comment EPA-HQ-OAR-2008-0508-0580 excerpt 10 for EPA's rationale and
approach to the use of CEMS.
EPA disagrees with suggestions that Tier 4 should only be required if the installed CEMS
include a C02 monitor. The incremental cost of adding a diluent gas (C02 or 02) monitor or a
180
-------
flow monitor, or both, to meet Tier 4 monitoring requirements would likely not be unduly
burdensome for a large unit that combusts solid fossil fuels or MSW, operates frequently, and is
already required to install, certify, maintain, and operate CEMS and to perform ongoing QA
testing of the existing monitors.
Commenter Name: Allen Kacenjar
Commenter Affiliation: Squire Sanders
Document Control Number: EPA-HQ-OAR-2008-0508-0492.1
Comment Excerpt Number: 1
Comment: Sources should only be obligated to conduct Tier 4 monitoring when actual C02
CEMS are already in place. The Proposed Rule's requirement to install CO2 CEMS at sources
with other CEMS is founded on the premise that the "incremental cost" of upgrading "would
likely not be unduly burdensome for a large unit that combusts solid fossil fuels or MSW,
operates frequently, and is already required to install, certify, maintain, and operate CEMS and to
perform ongoing QA testing of the existing monitors." 74 Fed. Reg. at 16483. In all scenarios
except where C02 CEMS are already in place, actual costs will be more burdensome than the
Proposed Rule assumes. One primary reason is that EPA's capital cost estimates are based on
"annualized costs over a 15-year timeframe." EPA-HQOAR-2008-0508-0002 at p. 4 - 22.
While CO2 CEMS may operate for 15 years, the real world cash-flow impact of such capital
improvements cannot be similarly deferred. Rather, contractors require payment in full no later
than the date of installation. Given the challenging economic climate and existing budget
constraints, payment of lump-sum capital costs (even assuming the actual amount of those costs
matches EPA's estimates) will often create a significant burden. That burden will fall most
heavily on SBREFA small entities that must install CO2 CEMS. [Footnote: The Regulatory
Flexibility Act, 5 U.S.C. §§601 - 612, as strengthened in 1996 by the Small Business Regulatory
Enforcement Fairness Act ("SBREFA"), was enacted to require proper agency consideration of
measures to protect small entities from harm due to agency regulation. The Small Business
Administration's related regulations provide that an electric utility is "small if, including its
affiliates, it is primarily engaged in the generation, transmission, and/or distribution of electric
energy for sale and its total electric output for the preceding fiscal year did not exceed 4 million
megawatt hours." 13 C.F.R. §121.201 at fn. 1. AMP-Ohio's generating members (and many
similar small municipal utilities nationwide) qualify as small entities but were apparently not
considered in EPA's "screening assessment." See 74 Fed. Reg. at 16600. Assessing whether
additional costs impose an "undue" burden also requires assessment of the relative benefits
expected from such expenditures. The Tier 4 approach appears to provide, at most, very
marginal benefit over Tier 3 reporting. As acknowledged in the Preamble, "for combustion
sources, the emission rate of CO2 is directly proportional to the carbon content of the fuel, and
virtually all of the carbon is oxidized to CO2." 74 Fed. Reg. at 16480. Since Tier 3 requires
careful monitoring of fuel carbon content and "virtually all" of the measured carbon becomes
CO2, this methodology is more than accurate enough to achieve Congress' expressed goal: the
collection of sufficient information to guide future legislative and regulatory efforts. 74 Fed.
Reg. at 16456. Indeed, the only expected difference between the Tier 3 and Tier 4 protocols is
that Tier 3 reporting may modestly overestimate CO2 emissions where incomplete combustion
results in low-level CO emissions. While that potential for the minor overestimation of CO2
emissions may create adequate incentive for some sources to voluntarily install CO2 CEMS
(particularly if a cap-and-trade system is created), it does not justify the mandatory imposition of
181
-------
up-front capital costs. It would be significant overkill to require sources to track down such
minute carbon overestimates when the rule claims to cover only 85% of national GHG emissions
and exempts all sources under 25,000 metric tons per year. Accordingly, we request that EPA
limit mandatory Tier 4 reporting to only units that already have functioning CO2 CEMS.
Response: See the response to comment EPA-HQ-OAR-2008-0508-0455.1 excerpt 7 and the
response to comment EPA-HQ-OAR-2008-0508-0580 excerpt 10 for EPA's rationale and
approach to the use of CEMS.
The applicability of Tier 4 has been clarified such that only units that meet all six criteria in
§98.33 (b)(4)(ii)(A) through (F) must use CEMS, including the criterion that the "unit has
installed CEMS that are required either by an applicable Federal or State regulation or the unit's
operating permit." In some cases this requirement may require a unit to install a diluent gas
(C02 or 02) and a stack gas volumetric flow rate monitor. The incremental cost of adding a
diluent gas monitor or a flow monitor, or both, to meet Tier 4 monitoring requirements would
likely not be unduly burdensome for a large unit that combusts solid fossil fuels or MSW,
operates frequently, and is already required to install, certify, maintain, and operate CEMS and to
perform ongoing QA testing of the existing monitors.
Commenter Name: Kathy G. Beckett
Commenter Affiliation: West Virginia Chamber of Commerce
Document Control Number: EPA-HQ-OAR-2008-0508-0956.1
Comment Excerpt Number: 20
Comment: EPA proposes that all ARP units, and "other units monitoring heat input year round
under §75.10(c)" and reporting heat input under §75.64, use Part 75 heat input data (in mmBtu)
and a fuel-specific emission factor from Table C-3 to report CH4 and N2O. Proposed §98.33(c).
For all other units, EPA proposes use of (1) measured HHV, if measured or provided at least
monthly, and (2) if not measured monthly, the default HHV specified in Table C-l. Proposed
98.33(c). The Chamber has concerns regarding use of missing data procedures and bias
adjustment factors for CH4 and N2O. As a result, we request that the same alternative be
provided for missing volumetric flow data and Appendix D fuel flow data. It would not
necessarily agree to use of bias-adjusted volumetric flow data to calculate heat input, and mass
emission of CH4 and N2O, in a future program regulating GHG.
Response: See the Preamble, Section III. C., for EPA's response on missing data.
EPA acknowledges the commenter's concerns, but believes that it is appropriate to use the heat
input data reported under Part 75 for the purposes of calculating CH4 and N2O emissions from
Part 75 units. As the commenter points out, this data is already quality-assured and reported to
EPA. EPA believes that use of the Part 75 missing data procedures for stack gas flow rate and
fuel flow rate will not significantly bias the CH4 and N2O emissions estimates. The percent
monitor data availability (PMA) for Part 75 flow monitors is, on average, very high ( > 95
percent). The small amount of substitute data used by Part 75 units has little effect on the
emissions data. The only time that a significant bias may be introduced in the reported stack gas
flow rates is when the PMA drops below 80 percent and the maximum potential flow rate must
be reported. This is a very rare occurrence. Fuel flow meters are also very reliable and seldom
experience missing data incidents. The missing data routines for fuel flow rate are much less
182
-------
conservative than the CEMS routines. Substitute fuel flow rates are very similar to actual fuel
flow rates. In view of these considerations, EPA is not revising Part 75 reporting requirements,
and for simplicity and cost reasons, EPA is keeping the GHG monitoring requirements consistent
with current monitoring requirements.
Commenter Name: Craig S. Campbell
Commenter Affiliation: Lafarge North America
Document Control Number: EPA-HQ-OAR-2008-0508-0674.1
Comment Excerpt Number: 14
Comment: In the definition section (40 CFR §98.6) of the proposed rule EPA defines
"Municipal solid waste" ("MSW") to mean "solid phase household, commercial/retail, and/or
institutional waste, such as, but not limited to, yard waste and refuse." This is a very broad
definition that may be read to include a number of common mixed waste streams which are used
as alternative fuels by the cement industry. Commercially generated scrap paper/plastics would
be one example. This broad definition, coupled with some of the proposed GHG
measurement/calculation methodologies included elsewhere in the proposed rule for MSW
(apparently written with MSW incinerators in mind), presents a number of concerns for how
cement kiln operators are to handle these calculations. In some cases the proposed
measurement/calculation methodologies would be inappropriate and/or entirely unworkable for a
cement kiln. For example, EPA is proposing a separate "MSW" calculation method for an
emission unit's biogenic emissions. The facility would be required to use ASTM methods listed
in the rule to sample and analyze the C02 in the flue gas once each quarter, in order to determine
the relative percentages of fossil fuel-based carbon (e.g., petroleum-based plastics) and biomass
carbon (e.g., newsprint) in the emissions when MSW is combusted in the unit. More
specifically: Sources that combust MSW under the proposed rule are required to follow 40 CFR
§98.33(e)(3) which states "For a unit that combusts MSW, the owner or operator shall use, for
each quarter, ASTM Methods D 6866-06a and D 7459-08, as described in 40 CFR §98.34(f), to
determine the relative proportions of biogenic and non-biogenic CO2 emissions when MSW is
combusted." Further to this, under 40 CFR §98.34(f) gas samples shall be taken "during normal
unit operating conditions while MSW is the only fuel being combusted, for at least 24
consecutive hours or for as long as necessary to obtain a sample large enough to meet the
specifications of ASTM D6866-06a." This aspect of the proposed rule is entirely unworkable for
cement kilns using any mixed-waste alternative fuels meeting the proposed rule definition of
MSW. Cement kilns typically use mixed-waste alternative fuels at some fuel-replacement
percentage (usually much less than 100%) along with traditional fossil fuels. In most cases a
cement kiln would not be capable - and often cases not legally permitted - to operate using these
"MSW" fuels as the "only fuel being combusted." Lafarge believes it is imperative for EPA to
allow a workable (e.g., different) approach for the biogenic emissions determination from
cement kilns. It is recommended that cement kilns be allowed to use the Tier 1 method for
calculating biogenic emissions, in addition to having the option of using the above mentioned
ASTM Methods D 6866-06a and D 7459-08. The Tier 1 method essentially requires fuel mass
consumption data along with default biogenic-fuel emission factors for calculating the biogenic
emissions. In the alternative, EPA could make an appropriate change to the definition of
"MSW" as used in the proposed rule. Assuming EPA's actual intent is to exclude use of the Tier
1 method when MSW is being combusted by dedicated MSW facilities (e.g., municipal waste
incinerators processing more-traditional municipal refuse steams), it may be possible to revise
183
-------
the MSW definition such that mixed wastes used as fuels at cement kilns are not captured within
the greenhouse gas reporting rule's MSW definition.
Response: EPA has revised §98.33 to allow units which combust MSW and do not produce
steam to use Tier 1 to calculate the total C02 emissions from MSW combustion. Default
emission factors for MSW are provided in Table C-l. Regarding the biogenic CO2 emissions,
EPA disagrees with the commenter that ASTM Methods D 6866-06a and D 7459-08 are
unworkable for a cement kiln. The commenter has correctly noted that the proposed rule would
have required MSW to be the only fuel combusted when the methods are used. However, the
final rule has corrected this and simply states that the ASTM methods are to be used "when
MSW is combusted in the unit." These final rule provisions should address the commenter's
concerns.
Commenter Name: Marcelle Shoop
Commenter Affiliation: Rio Tinto Services, Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-0636.1
Comment Excerpt Number: 24
Comment: EPA rejected an option of requiring periodic stack testing to derive site-specific
emission factors for CH4 and N2O because it was too costly for the small improvement in data
quality that it might achieve. (74 Fed. Reg. at 16485) Rio Tinto supports this decision. We
agree that stack testing for CH4 and N2O emissions would not provide enough additional
accuracy or benefit to justify the additional cost and effort since these emissions from
combustion are so low.
Response: EPA appreciates the supportive feedback, and has maintained these specifications in
the final rule. EPA has revised the rule that only CH4 and N2O emissions from those fuels listed
in Table C-2 of Subpart C are required to be reported.
Commenter Name: Juanita M. Bursley
Commenter Affiliation: GrafTech International Holdings Inc. Company (GrafTech)
Document Control Number: EPA-HQ-OAR-2008-0508-0686.1
Comment Excerpt Number: 24
Comment: If a facility opts to combine all its combustion units that are supplied by a common
gaseous or liquid fossil fuel supply piping configuration, which is equipped with a calibrated fuel
flow meter, for the purpose of simplifying its emissions calculations, GrafTech understands the
facility can do this regardless of the total number of units or regardless of the total maximum
rated heat input capacity of the individual units or of the entire group. GrafTech agrees this is an
acceptable option. However, since EPA is not restricting the total maximum rated heat input
capacity of the combined units, GrafTech believes that the facility should not be required to use
the Tier 3 method to calculate CO2 emissions for any combustion unit > 250 mmBtu/hr. and that
this requirement should also not apply to these aggregated combustion units, where any one or
more of the units, or the total group of units exceeds this maximum rated heat input capacity.
This would potentially negate much of the main reason for aggregating multiple units, which is
184
-------
to simplify the GHG emission calculations, if the facility would now have to use the more
complex calculation method for the entire group, requiring either daily or monthly measurements
and calculations. A fact to which EPA readily admits in the Preamble, commercially-available
gaseous and liquid fuels are typically homogenous so there should be an insignificant variability
in the carbon content. That fact coupled with the expected accuracy of the typical supplier
billing meter on common fuel supply piping, indicates there would be no significant benefit to
requiring the more onerous Tier 3 calculation method to estimate GHG emissions for an
aggregated group of units even if the total (or any of the individual unit) maximum heat input
capacity exceeds 250 mmBTU/hr. On page 16484 of the Preamble under the discussion of Tier
1, EPA states it "considered" allowing the use of default emission factors, default HHVs and
company records to quantity annual fuel consumption for all stationary combustion units,
regardless of size or the type of fuel combusted, but "decided to limit the use of this type of
calculation methodology to smaller combustion units". However, EPA provides absolutely no
justification for this decision, which unnecessarily complicates the emissions estimation
procedures. Given the additional burden on reporting facilities, and the arguments provided
above, GrafTech requests that EPA allow this simplified and generally accepted Tier 1
estimation procedure in the final rule for all stationary combustion units regardless of size or the
type of fuel combusted, at a minimum to quantify annual consumption for commercially-
available gaseous and liquid fuels that have established default emission factors and HHVs.
Response: See the Preamble, Section II. L., on General Monitoring Requirements for the overall
rationale for methodologies required under this rule, and the response to comment EPA-HQ-
OAR-2008-0508-0909.1 excerpt 4 and EPA-HQ-OAR-2008-0508-0580 excerpt 10 for the
rationale for methodologies required under Subpart C.
EPA disagrees with the commenter's suggestion of allowing Tier 1 reporting for all fuels and
units of any size. EPA did not choose to adopt a simplified calculation method approach (e.g.,
using default emission factors) because the data would be less accurate than under the selected
option and would not make use of site-specific data that many facilities already have available
and refined calculation approaches that many facilities are already using.
However, the 250 mmBtu/hr restriction on the use of Tier 2 has been lifted for units in which the
only fossil fuels combusted are natural gas and/or distillate oil, in view of the homogeneous
nature of these fuels. This is consistent with the common pipe reporting provisions, which allow
oil- or gas-fired units sharing a common supply pipe to report jointly using the tier required
based on the maximum rated heat input capacity of the largest unit served by the common pipe
configuration.
The commenter should also note that the cumulative 250 mmBtu/hr heat input capacity limit on
the aggregation of units into a group has been dropped. Rather, the 250 mmBtu/hr restriction
applies only to the individual units in the group. Therefore, for reporting purposes, individual
units with maximum rated heat input capacities of 250 mmBtu/hr or less may be aggregated
without limit into a single group, provided that the Tier 4 methodology is not required for any of
the units, and all units in the group use the same tier for any common fuel(s) that they combust.
185
-------
Commenter Name: See Table 3
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0433.2
Comment Excerpt Number: 24
Comment: For the purposes of this rule for most C02 and other GHG sources, including
catalytic cracking units, fluid coking units, and other refinery combustion and process units,
engineering calculations are rejected as being less accurate than are CEMS data. While this may
appear true on its face, frequently such calculations can provide comparable or more accurate
data than CEMS data, if adequate process information, data on carbon content of materials, and
mass of materials processed or combusted are available. Such calculations can often exceed a ±
5% accuracy, while the CEMS monitors specified in the proposed rule are allowed to have data
errors as large as ± 20% of the true value for pollutant monitors (40 CFR 60, Appendix B,
Performance Specification 2) and ± 1% absolute 02 or C02 concentration (40 CFR 60,
Appendix B, Performance Specification 3) during annual compliance certification testing.
Furthermore, when the flow monitoring required to report mass emission rates for pollutants is
included, the allowable accuracy of the monitoring system is ± 20% of the mean value of the
relative accuracy test audit results (40 CFR 60, Appendix B, Performance Specification 6).
These accuracy values far exceed those of many engineering calculations. Usually, even the
EPA's default high heat values and C02 emission factors are likely to be more accurate than ±
20% of the true value. Therefore, little if any value may be expected by requiring the installation
of CEMs. NPRA requests that EPA reconsider allowing the use of engineering calculations for
calculation of C02 emission rates for most refinery sources, including the catalytic cracking
units and fluid coking units in refineries.
Response: See the Preamble, Section II. L., for the response on the general monitoring
approach.
See the response to comments on Subpart Y regarding refinery process unit monitoring.
Refinery process heaters and boilers are not required to install CEMS under the general
stationary combustion requirements in Subpart C.
Commenter Name: Marcelle Shoop
Commenter Affiliation: Rio Tinto Services, Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-0636.1
Comment Excerpt Number: 23
Comment: Two of the proposed reporting methodologies for stationary source combustion
devices, Tiers 2 and 3 as provided for in 40 CFR 98.33, employ calculations based on the mass
of solid fuel (coal) consumed and the sampled mass fraction of the carbon composition of the
coal. The carbon content of the coal is based on sampling and analyses of solid fuel (coal) from
weekly composite sampling analyzed monthly. 40 CFR 98.34(c) - (d), 74 Fed.Reg. 16636. As
discussed above, Rio Tinto urges EPA to allow the stationary combustion source to rely on: 1.
Supplier information (commercial records such as coal deliveries or invoices) for volume
measurements; 2. Default carbon content or HHV default factors; 3. Carbon content or HHV data
provided to the source by the coal-fuel supplier. We request EPA to make the rules more dear
186
-------
and explicit that supplier information can be used by industrial combustion sources. The
methodologies in proposed 40 CFR 98.33 and the monitoring and QA/QC provisions of 40 CFR
98.34 indicate that the reporter may rely on company records for fuel consumption, but the rules
are not entirely dear whether the reporter may rely on commercial records (coal deliveries,
invoices) or must undertake additional measurement activities to determine and record
consumption. Most important is the need for the combustion source to be able to rely on supplier
information for the carbon content or HHV, or alternatively to be able to utilize a carbon default
or HHV default factor. Most industrial combustion sources do not have appropriate equipment,
facilities or expertise to conduct weekly or monthly sampling of the coal in accordance with the
applicable standards. The proposed rule would require coal combustion sources to use ASTM
methods to collect representative samples of the fuel bunkered or consumed. See Proposed 40
CFR 98.34(c). Obtaining a representative sample from a coal pile can be difficult and expensive
for a coal user. Conversely, many coal suppliers have necessary sampling equipment and
expertise to collect representative samples in accordance with applicable ASTM standards.
Where they do not, the default factors should be acceptable. Currently, our facility with the coal
combustion source receives quarterly carbon content information from the supplier and we
utilize this information for making our estimates of C02 emissions from the industrial
combustion source. Requiring both the combustion source and the supplier (per Subpart KK) to
conduct sampling and analyses would be duplicative, inefficient and expensive. Moreover,
given the large number of combustion facilities relative to suppliers, there is a potential concern
whether there would be sufficient laboratory capacity to analyze samples for carbon content or
HHV for all of these combustion facilities in addition to the coal suppliers. Being both a user
and a Supplier of coal, Rio Tinto recognizes the need and importance of carefully coordinating
the fuel supplier requirements with the requirements applicable to combustion sources to make it
dear that combustion sources may use data provided by fuel suppliers.
Response: See the Preamble, Section II. L., for the response on the general monitoring
approach.
EPA did not choose to adopt a simplified calculation method approach (e.g., using default
emission factors) for all units because the data would be less accurate than under the selected
option and would not make use of site-specific data that many facilities already have available
and refined calculation approaches that many facilities are already using. However, the
commenter should note that in Tiers 2 and 3 the volume of solid fuel combusted is determined
using company records, which could include fuel billing records. EPA has revised the sampling
requirements for coal so that a representative sample is required for each fuel lot, i.e., for each
shipment or delivery. The final rule clarifies that fuel sampling and analysis data provided by
the supplier may be used in the emission calculations. EPA notes that Subpart KK Suppliers of
Coal is not being included in this rule at this time.
Commenter Name: Juanita M. Bursley
Commenter Affiliation: GrafTech International Holdings Inc. Company (GrafTech)
Document Control Number: EPA-HQ-OAR-2008-0508-0686.1
Comment Excerpt Number: 22
Comment: GrafTech's understanding from §98.33(b)(4) is that the Tier 3 calculation method
"may be used" (i.e., at the facility's discretion) for a unit of any size and for any type of fuel,
187
-------
except when Tier 4 is required by the rule. However, this is confused by the apparent indication
in Table C-l and discussions in the Preamble that Tier 3 is "required" for gaseous and liquid
fossil fuel use when the combustion unit size exceeds 250 mmBtu/hr. GrafTech wanted to bring
this apparent discrepancy to EPA's attention, and express our opinion that use of the Tier 1 and
Tier 2 methods should be allowed by EPA for estimating GHGs from combustion of gaseous and
liquid fossil fuels available from commercial sources, regardless of the size of the combustion
unit(s). We are not familiar with gaseous and liquid fuels that may be obtained from private
wells, so are not offering an opinion as to whether emissions from those fuel sources warrant use
of the more complex Tier 3 calculation method.
Response: In response to comments, EPA has substantially revised §98.33(b), describing which
tier a reporter is to use. EPA has decided to allow the use of Tier 2 methods for units of any size
in which the only fossil fuels combusted are pipeline quality natural gas and/or distillate fuel oil.
Specific provisions in the final rule clarify when Tier 3 methods are required.
Commenter Name: Marcelle Shoop
Commenter Affiliation: Rio Tinto Services, Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-0636.1
Comment Excerpt Number: 22
Comment: The differences between the proposed emissions calculation methodologies for
stationary combustion source rules for natural gas and those for natural gas local distribution
companies (LDCs) are not rational and should be aligned. We specifically request that the Tier 2
or Tier 3 calculation methodologies in 40 CFR §98.33 be modified to comport with the
calculation methodologies for natural gas suppliers in 40 CFR §98.403, allowing the combustion
source, at its option, to calculate emissions either using either default factors or supplier data if
available. For stationary sources that combust natural gas, the Tier 2 methodology under Subpart
C requires high heat values (HHV) to be determined on a monthly basis using "the applicable
fuel sampling and analysis methods incorporated by reference in §98.7." §98.34(c), 74 Fed. Reg.
at 16636. The Tier 3 methodology for such facilities would require carbon content and
molecular weight to be measured on a monthly basis, using "an applicable method listed in
§98.7." §98.34(d)(3). It appears that applicable measurement methods for natural gas would be
those listed in the provisions for natural gas suppliers, specifically 40 CFR §98.404(d), 18 e.g.,
American Gas Association or ASTM. In contrast, the proposed rule does not require natural gas
suppliers to measure high heat values or carbon content at all. Rather, Subpart NN authorizes
natural gas local distribution companies (LDCs) the option of reporting CC^e emissions using
one of two calculation methodologies, neither of which mandates monthly sampling. See
§98.403, 74, Fed. Reg. at 16720. The calculation methodologies rely on the default high heating
value or CO2 emission factors provided in either Table NN-'l or NN-2, as applicable. An LDC
also has the option of relying on reporter-specific higher heating values or CO2 emission factors
developed using methods outlined in §98.404(d), which we reference above." In the Preamble,
EPA explains that: We considered but do not propose an option in which LDCs and natural gas
processing plants would be required to sample and analyze natural gas and NGLs periodically to
determine the carbon content. Given the close correlation between carbon content and BTU
value of natural gas and NGLs, and the availability of BTU information on these products, EPA
believes that periodic sampling and analysis would impose a cost on facilities but would not
result in improved accuracy of reported emissions values. 74 Fed. Reg. at 16577. Many
188
-------
stationary combustion sources subject to the Tier 2 or 3 Methodology under Subpart C do not
have appropriate equipment, facilities or expertise to conduct monthly sampling of natural gas
supplied to the facility. The reason EPA articulated in the Preamble (noted above) for not
requiring LDCs to undertake periodic sampling-that the additional costs would not result in
improved accuracy of reported emissions values — appears to be equally applicable for the Tier 2
or 3 methodology for combustion sources (or their suppliers) and monthly sampling should not
be required. In some cases, supplier information may be available. We read the proposed rule
(§§98.33 and .34) to allow a reporting entity to rely on company records in making the
calculations, including information provided by fuel suppliers, on which to base the high heat
value or fuel carbon content measurement. However, we request that EPA specifically clarify
that stationary combustion sources may rely on high heat value or carbon content data provided
by natural gas suppliers or LDCs20 in utilizing Tier 2 or 3 methodologies. [Footnote: 20 For
example, two companies that deliver natural gas to Rio Tinto entities, Kern River Gas
Transmission Company and Questar Gas Company, provide online access to their natural gas
quality databases: http://services.kemrivergas.com/portallDesktop.aspx and
http://www.guestargas.com/ServicesBuslTemnicallnfo.php. In summary, stationary combustion
sources should be able to calculate their C02 emissions from natural gas combustion using the
applicable Tier 2 or 3 Methodologies based on either of the following options: (1) the default
values provided in Tables NN-1 and NN-2 for natural gas suppliers; or (2) high heat value or
carbon content information as provided by the natural gas supplier or LDC (for example when
the LDC chooses to undertake reporter-specific analyses per 40 CFR §98.403-.404); or (3) high
heat value or carbon content information as measured by the combustion facility. The comments
made in this section related to natural gas apply equally to propane. Some of our facilities use
propane as a backup fuel in case natural gas supplies are interrupted for any reason. Propane
used for these backup purposes is not used on a regular basis but is stored for potentially long
periods. Under these circumstances, it would be impracticable to measure the HHV, carbon
content, and/or molecular weight of this fuel, further supporting our recommendation to allow
the use of default values or vender supplied data (if available) to calculate emissions from these
fuels.
Response: The commenter should note that the final rule allows units of any size in which the
only fossil fuels combusted are natural gas and/or distillate oil to use Tier 2. EPA agrees with
the commenter that for a homogeneous fuel such as pipeline natural gas, monthly sampling is not
necessary. Therefore, §98.34 has been revised to require that natural gas be sampled
semiannually. Furthermore, the final rule clarifies that fuel sampling and analysis data provided
by the supplier may be used in the emission calculations.
EPA expects that most units combusting propane will have maximum rated heat input capacities
less than 250 mmBtu/hr, and will thus be allowed to use Tier 1 or Tier 2. Tier 1 does not require
any fuel sampling or analysis. Tier 2 will only be required if the owner or operator of the unit
already performs sampling and analysis for HHV, or receives the result of such analysis from the
fuel supplier, at the minimum frequency. If a unit larger than 250 mmBtu/hr combusts propane,
Tier 3 will be required, and fuel sampling and analysis for carbon content will be required.
189
-------
Commenter Name: Robert Rouse
Commenter Affiliation: The Dow Chemical Company
Document Control Number: EPA-HQ-OAR-2008-0508-0533.1
Comment Excerpt Number: 22
Comment: Dow Suggests that EPA Modify the Tier 1 Restriction. In §98.33(b)(1), it is
restrictive to limit the use of Tier I to units < 250 mmBTU/hr in size. There is no appropriate
reason for this restriction, and EPA should not keep this restriction in the final rule. The
variations introduced in the calculations will be very small compared to the size of the entire
GHG inventory. Dow suggests that EPA eliminate the < 250 mmBTU/hr restriction for the first
3 years of the reporting obligation and then revisit the need for such a restriction after this period
of time. Dow Suggests that EPA Modify the Tier 2 Restriction. In §98.33(b)(3), it is restrictive
to limit the use of Tier II to units < 250 mmBTU/hr in size. There is no appropriate reason for
this restriction, and EPA should not keep this restriction in the final rule. The variations
introduced in the calculations will be very small compared to the size of the entire GHG
inventory. Dow suggests that EPA eliminate the < 250 mmBTU/hr restriction for the first 3
years of the reporting obligation and then revisit the need for such a restriction after this period
of time. Dow Suggests that EPA Clarify that the Tier 4 Method is only Required for Sources
that Combust Solid Fossil Fuel with a Maximum Heat Input Capacity Greater Than 250
mmBTU/hr (and for units with a capacity to combust greater than 250 tons per day of MSW) that
are Already Equipped with a CEMS System. The requirements contained in proposed
§98.33(b)(5) are very confusing as written regarding the applicability of the Tier 4 requirements.
The requirements are confusing as to whether they are only required for combustion sources
firing solid fuel or MSW, or if they apply to other large (i.e., > 250 MMBtu/hr) combustion units
with liquid or gaseous fuels. In addition, the other criteria for MSW and solid fuels listed in Tier
4 are also confusing. Dow believes that EPA has clearly stated the applicability of the Tier 4
requirements on Page 16483 of the Preamble: "The Tier 4 method, and the use of CEMS (with
any required monitored upgrades) is required for solid fossil fuel-fired units with a maximum
heat input capacity greater than 250 mmBtu/hr (and for units with a capacity greater than 250
tons per day of MSW)." Dow comments that EPA should add this language to
§98.33(b)(5)(ii)(A) to clarify the intent of the Tier 4 requirements. Dow comments that EPA
should incorporate Table C-l from page 16481 of the Federal Register containing the Preamble
into the actual final rule. This table clearly shows the applicability of Tiers 1 - 4 to various types
of combustion units. Dow comments that §98.33(b)(5)(ii) should include the word "and" at the
end of each item (A) through (F) to clarify that each one is required and that EPA did not mean
"or" between these items.
Response: See the Preamble, Section II. L., on General Monitoring Requirements for the overall
rationale for methodologies required under this rule, and the response to comment EPA-HQ-
OAR-2008-0508-0909.1 excerpt 4 and EPA-HQ-OAR-2008-0508-0580 excerpt 10 for the
rationale for methodologies required under Subpart C.
EPA disagrees with the commenter's suggestion of allowing Tier 1 reporting for all fuels and
units of any size. EPA did not choose to adopt a simplified calculation method approach (e.g.,
using default emission factors) for all units because the data would be less accurate than under
the selected option and would not make use of site-specific data that many facilities already have
available and refined calculation approaches that many facilities are already using.
190
-------
However, EPA has significantly expanded the use of Tier 1 and Tier 2 Calculation
Methodologies. Most units combusting the biogenic fuels listed in Table C-l may use Tier 1.
The 250 mmBtu/hr restriction on the use of Tier 2 has been lifted for units in which the only
fossil fuels combusted are natural gas and/or distillate oil, in view of the homogeneous nature of
these fuels. However, the 250 mmBtu/hr unit size cutoff remains for units that combust other
fossil fuels.
EPA also acknowledges the commenter's concerns regarding Tier 4 applicability. EPA has
revised §98.33(b)(4)(ii) of the final rule to clarify that all six criteria specified in subparagraphs
(A) through (F) must be met before Tier 4 is required. The Tier 4 requirement is limited to larger
solid fossil fuel units with an existing pollutant CEMS or volumetric flow rate monitor. EPA is
requiring the use of CEMS due to the complexity of monitoring solid fuel consumption and the
heterogeneous nature of the solid fuels. Many of these fossil fuel-fired units with a pollutant
CEMS have an existing diluent monitor (O2 or CO2) that can be used to determine CO2
emissions.
Commenter Name: Juanita M. Bursley
Commenter Affiliation: GrafTech International Holdings Inc. Company (GrafTech)
Document Control Number: EPA-HQ-OAR-2008-0508-0686.1
Comment Excerpt Number: 21
Comment: As written, the citation on page 16634 under §98.33(b)(5)(ii)(c) appears to require
any combustion unit that has operated for more than 1,000 hours in any calendar year since 2005
to use the Tier 4 Calculation Method, and therefore would require the installation and operation
of CEMS even if this monitoring equipment is not currently installed. (Since there is no "and"
provided in the list of criteria, GrafTech has therefore interpreted the requirement to apply to any
one listed criterion "or" another.) Firstly, each facility may be unable to establish the annual
hours of operation of each stationary fuel combustion unit since 2005, as it was not a past legal
requirement to maintain such documentation of operations. There is no convincing reason or
known legal precedent to go back to historical operations records several years before a reporting
rule becomes effective. Even if this operational documentation is available at a facility, this
language is totally unfounded and unnecessary for the same arguments as above, i.e., sufficiently
accurate and consistent fuel usage data can be collected and GHG emissions estimated using
standard recognized protocols without this additional burden on the regulated community. The
number of hours of operation would have negligible impact on the accuracy or consistency of
using any of the other recognized GHG emission estimation methods, using readily available fuel
usage data and default emission factors available for all the common fuels. Secondly, according
to Table C-l in the Preamble, this criterion only applies to combustion units burning > 250
mmBtu/hour solid fossil fuels or > 250 tons/day municipal solid waste (MSW). Liquid and
gaseous fossil fuels, in particular, natural gas, are amongst the cleanest burning and homogenous
fuels available, so that this 1,000 hour per year operation time criteria should not apply to them.
On page 11 of EPA's Technical Supporting Document (TSD) for the proposed rule, dated Jan 30,
2009, Section 3.2.1 Tier 4 Methodology also indicates that CEMS are being required for large
solid fuel units and MSW units, where there is uncertainty in heating value and carbon content.
Default emission factors are available and sufficiently accurate for gaseous and liquid fossil
fuels, so Tier 1 or Tier 2 (if monthly high heating value information is available) should be
acceptable. The §98.33(b)(5)(ii)(c) language in the Final Rule should be written to be clearer
191
-------
and consistent with Table C-l. This language, unless clarified, could conceivably make a large
number of covered facilities unnecessarily install and operate CEMS.
Response: EPA acknowledges the commenter's concerns regarding Tier 4 applicability. EPA
has revised §98.33(b)(4)(ii) of the final rule to clarify that all six criteria specified in
subparagraphs (A) through (F) must be met before Tier 4 is required. The commenter should
note that in the final rule, units of any size in which the only fossil fuels combusted are distillate
oil and/or pipeline quality natural gas may use Tier 2.
Commenter Name: Marcelle Shoop
Commenter Affiliation: Rio Tinto Services, Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-0636.1
Comment Excerpt Number: 21
Comment: The Tier 3 calculation methodology (98.33(a)(3) requires the reporting entity to rely
on direct fuel volume measurements from fuel flow meters, which can include billing meters to
determine natural gas or other liquid fuel volumes. The Tier 2 calculation methodology for
liquid or gaseous fuels references only reliance on company records, but does not specifically list
fuel flow or billing meter measurements as company records. Both with respect to Tier 2 and
Tier 3, we assume that billing statements (with metering information) from the fuel or natural gas
suppliers may be relied upon to determine fuel volume measurements. However, we request that
EPA clarify that combustion sources can rely on such supplier information.
Response: The final rule clarifies that fuel billing meters may be used to quantify fuel
consumption, both as a part of company records under Tier 1 and Tier 2, and to directly measure
liquid or gaseous fuel flow under Tier 3.
Commenter Name: Lauren E. Freeman
Commenter Affiliation: Hunton & Williams LLP
Document Control Number: EPA-HQ-OAR-2008-0508-0493.1
Comment Excerpt Number: 31
Comment: Although the vast majority of UARG members' combustion units are ARP units that
will calculate CO2 emissions under Subpart D, UARG members also own and operate a variety
of non-ARP affected combustion units that could be required to report under this proposed rule.
Those may include pre-1990 simple cycle combustion turbines, units serving a generator < 25
MW (either pre-1990 units or new units combusting low sulfur fuel), and industrial or auxiliary
boilers. In some cases, these units already are monitoring and reporting CO2 (or O2)
concentration (as diluent) with CEMS and heat input under Part 75 to comply with the NBP or
CAIR, or monitoring CO2 (or O2) concentration (as diluent) with CEMS under an applicable
NSPS. One of UARG's immediate concerns with the rule is ensuring that units that do not
already have required monitoring equipment installed have sufficient time to order, install, and
perform any necessary testing on that equipment prior to the start of the program. EPA has
attempted to address that sort of concern in proposed §98.33(b)(6), which provides that if the
monitors needed for Tier 4 reporting have not been installed and certified by January 1, 2010, the
192
-------
unit may use Tier 3 in 2010. While UARG believes that the relief provided by this provision is
necessary, it is incomplete. Reporting under Tier 3 also requires monitoring equipment for
gaseous fuels — fuel flow meters and, for some fuels, gas chromatographs — that may have to be
installed and calibrated. In finalizing the rule, EPA must ensure that sufficient time and
resources are available for installation and calibration of this equipment.
Response: EPA has revised the rule so that units that must upgrade their existing CEMS to meet
Tier 4 requirements and do not have all necessary equipment in place by January 1, 2010 may
use either Tier 2 or Tier 3 in 2010. For these units, Tier 4 must be used starting January 1, 2011.
See the Preamble, Section III. G., "Summary of Comments and Responses on Initial Reporting
Year and Best Available Monitoring Methods," for additional explanation of flexibility provided
to facilities for reporting year 2010.
Commenter Name: Juanita M. Bursley
Commenter Affiliation: GrafTech International Holdings Inc. Company (GrafTech)
Document Control Number: EPA-HQ-OAR-2008-0508-0686.1
Comment Excerpt Number: 20
Comment: The Tier 4 Calculation Method under §98.33(4) is highly burdensome and the
required continuous emissions monitoring system (CEMS) is both expensive to install and
maintain. Therefore, this method should only be required of reporting facilities that are already
required to operate such emissions monitoring equipment under existing rules promulgated under
the CAA. The primary purposes of the Mandatory Greenhouse Gas Reporting Rule are to
establish a reasonably accurate GHG emissions baseline for the U.S. for use in future
rulemaking, and to establish standard procedures to ensure consistent GHG emissions data from
year to year for tracking purposes. Given the significant recordkeeping and maintenance burdens
associated with operating and maintaining CEMS, the higher level of accuracy afforded by these
monitoring systems is neither necessary nor justified by the intended purposes of this rule. If a
facility is not required to have CEMS under a Title V Permit for listed priority and hazardous air
pollutants, or other CAA programs, because other emissions monitoring and/or estimation
methods were deemed adequate, it makes little sense for such a facility to now have to install
CEMS to report GHG emissions, when there are adequate methods available to reasonably and
consistently estimate these emissions without adding excessive costs and the need for additional
resources to install, operate and maintain these monitoring devices. GrafTech believes that EPA
should not require CEMS at any reporting facilities, regardless of quantities or types of fuels
combusted each year, that are not currently required to have them under other existing air
permitting or other regulatory programs, as there is insufficient justification for EPA to make the
monitoring or recordkeeping requirements for GHGs more onerous than existing programs for
regulated priority pollutants or hazardous air pollutants. This is especially true for purchased
gaseous and liquid fossil fuels, which are largely homogenous and for which credible alternative
emissions estimation protocols based on metered fuel usage already exist. Similarly, a
requirement to install CEM on units for which limited or no other regulatory requirements exist
due to "grandfather" status under state air permitting programs appears to be unjustified.
193
-------
Response: See the response to comment EPA-HQ-OAR-2008-0508-0455.1 excerpt 7 and the
response to comment EPA-HQ-OAR-2008-0508-0580 excerpt 10 for EPA's rationale and
approach to the use of CEMS.
The Tier 4 requirement is limited to larger solid fossil fuel or MSW units with an existing
pollutant CEMS or volumetric flow rate monitor, or a source with an existing CO2 CEMS and
flow rate monitor. EPA is requiring the use of CEMS due to the complexity of monitoring solid
fuel consumption and the heterogeneous nature of the solid fuels. Many of these fossil fuel-fired
units with a pollutant CEMS have an existing diluent monitor (02 or C02) that can be used to
determine CO2 emissions.
Commenter Name: Lauren E. Freeman
Commenter Affiliation: Hunton & Williams LLP
Document Control Number: EPA-HQ-OAR-2008-0508-0493.1
Comment Excerpt Number: 32
Comment: For large solid fuel-fired non-ARP units that are already monitoring C02 or 02
under some other program, like the NSPS, UARG disputes EPA's assumption that installing a
volumetric flow monitor will not be burdensome. 74 Fed. Reg. at 16,483. Experience under the
ARP has shown that volumetric flow monitors can be very sensitive to flow disturbances that
occur when monitors are installed in short stacks or ducts or downstream of any potential
disturbance. Circular flow and "wall effects" can significantly affect measurements and may
need to be accounted for with special testing procedures or, for wall effects, application of
correction factors. For these reasons, flow monitors must meet minimum location criteria. Some
units may not have an existing location that is suitable for installation of a flow monitor.
Moreover, RATA testing of flow monitors, even at the normal level, is significantly more
difficult and expensive that RATA testing for C02 or O2, and the cost of adding platforms and
access for servicing new volumetric flow monitors can be significant. While UARG does not
object to allowing use of a flow monitor if it is already installed, UARG does not believe that
installation and certification of a volumetric flow monitor should be required under this rule for
any unit. If the information available under Tier 3 is adequate for solid fuel-fired units that do
not have CO2 or O2 CEMS (and UARG believes that it is), it also is adequate for other units.
EPA has not provided an adequate justification for, or estimate of the burdens of, imposing such
a requirement.
Response: EPA's estimates of monitoring costs are averages and may not represent the actual
cost in individual circumstances. EPA does not agree that Tier 3 monitoring is adequate for all
large units that combust solid fossil fuels, particularly if most, or all, of the CEMS infrastructure
is already in place. EPA is requiring the use of CEMS due to the complexity of monitoring solid
fuel consumption and the heterogeneous nature of the solid fuels. The incremental cost of
adding a flow monitor to meet Tier 4 monitoring requirements is not unduly burdensome for a
unit that is already required to install, certify, maintain, and operate CEMS, and to perform
ongoing QA testing of the existing monitors. EPA's estimated this cost as approximately
$25,000 per year (2006 $).
194
-------
Commenter Name: Kathy G. Beckett
Commenter Affiliation: West Virginia Chamber of Commerce
Document Control Number: EPA-HQ-OAR-2008-0508-0956.1
Comment Excerpt Number: 19
Comment: To comply with §821 of Public Law 101-549, EPA included a number of
methodologies in Part 75 to monitor and report CO2 mass emissions. Although sources are
allowed to use C02/02 CEMS installed as diluent for other purposes, Part 75 also allows use of
alternative procedures in Appendix G in lieu of CEMS. Much like Tiers 2 and 3, Appendix G
allows C02 emissions to be estimated, either by using: (1) fuel feed rates and the results of
periodic fuel sampling and analysis (to determine the percent carbon in the fuel), Appendix G,
§2.1; or (2) hourly heat input rate measurements from a certified Part 75, Appendix D fuel flow
meter and a fuel-specific, carbon-based "F-factor," Appendix G, §2.3. Appendix G is the most
frequently-used Part 75 method for estimating C02 mass emissions from the oil and gas-fired
units that would be required to use Tier 3 under this rule in not ARP affected. Although EPA's
proposed rule appropriately allows ARP affected oil and gas-fired units to report annual C02
mass emissions calculated using the Appendix G F-factor method to comply with this rule, that
option is not provided for other combustion sources and it should be. The F-factors used under
Appendix G are well established and apply only to homogeneous liquid and gaseous fuels with
little expected variability in their carbon content. EPA recognized this lack of variability in its
own proposed Tier 3 methodology, which requires sampling for carbon content only monthly.
The Appendix G F-factor method is also based on the same F-factors used by Tier 4 sources with
CEMS to convert 02 CEMS values to CO2. In short, there is no reason not to allow non ARP
combustion sources to use this methodology as well. The accuracy is certainly of sufficient
quality to serve the information gathering purposes of this rule.
Response: The commenter should note that EPA has added alternative methods for units that
report data to EPA according to Part 75, which allow certain oil- and gas-fired units to use
methods from Appendices D and G to Part 75. See §98.33(a)(5) of the final rule.
Commenter Name: Marcelle Shoop
Commenter Affiliation: Rio Tinto Services, Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-0636.1
Comment Excerpt Number: 19
Comment: We urge EPA to make the fuel supplier requirements consistent with the
requirements for combustion sources that burn those fuels, while still providing flexibility for the
reporter to the greatest extent possible. Allow stationary combustion sources (Tiers 2 or 3) at
their option to utilize: 1. Default carbon content or high heating values (sometimes referred to as
"HHV") default factors; 2. Carbon content or HHV data provided to the source by the coal-fuel
supplier. At a minimum allow the use of default factors for de minimis sources or where carbon
content or HHV data are not available from the supplier. Through reliance on business records,
EPA presumably intended for stationary combustion sources to be able to make use of supplier
information for high heat values (under the Tier 2 calculation methodology) or carbon content
and/or molecular weight (under the Tier 3 methodology) as an alternative to conducting on site
sampling and analysis. EPA should make the language of the rule clear and explicit that the
195
-------
combustion source can rely on supplier information at its option. We note that this approach is
consistent with the draft final WCI Essential Requirements of Mandatory Reporting, which
allows facilities to use higher heating values (Calculation Methodology 2) or fuel carbon content
or molar fraction (for gaseous fuels) (Calculation Methodology 3) provided by the fuel supplier.
See Final Draft Essential Requirements of Mandatory Reporting, WCI.23(b) and (c).
Response: The final rule clarifies that fuel sampling and analysis data provided by the supplier
may be used in the emission calculations.
See the response to comment EPA-HQ-OAR-2008-0508-0464.1 excerpt 4 for additional
information on the applicability of tiers. EPA did not choose to adopt a simplified calculation
method approach for all larger units (e.g., using default factors) because the data would be less
accurate than under the selected option and would not make use of site-specific data that many
facilities already have available and refined calculation approaches that many facilities are
already using.
The commenter should note that units smaller than 250 mmBtu/hr combusting fuels listed in
Table C-l may use Tier 1, provided that the owner or operator does not routinely determine or
receive from the fuel supplier the fuel's measured HHV at a frequency greater than or equal to
the minimum frequency specified in §98.34. Under Tier 1, a reporter calculates emissions based
on fuel consumption from company records and default emission factors and HHVs.
Commenter Name: Kathy G. Beckett
Commenter Affiliation: West Virginia Chamber of Commerce
Document Control Number: EPA-HQ-OAR-2008-0508-0956.1
Comment Excerpt Number: 18
Comment: For large solid-fuel fired non-ARP units that are already monitoring CO2 or O2
under some other program, like the NSPS, EPA's assumption that installing a volumetric flow
monitor will not be burdensome is not quite accurate. 74 Fed. Reg. at 16483. Experience under
the ARP has shown that volumetric flow monitors can be very sensitive to flow disturbances that
occur when monitors are installed in short stacks, ducts, or downstream of any potential
disturbance. Circular flow and "wall effects" can significantly affect measurements and may
need to be accounted for with special testing procedures or, for wall effects, application of
correction values. For these reasons, flow monitors must meet minimum location criteria. Some
units may not have an existing location that is suitable for installation of a flow monitor.
Moreover, RATA testing of flow monitors, even at the normal level, is also significantly more
difficult and expensive that RATA testing for CO2/O2. While the Chamber does not object to
allowing use of a flow monitor if it is already installed, it does not believe that installation and
certification of a volumetric flow monitor should be required under this rule for any unit. If the
information available under Tier 3 is adequate for solid fuel-fired units that do not have CO2/O2
CEMS, it also is adequate for other units. EPA has not provided an adequate justification, or
estimation of the burdens, for imposing such a requirement.
Response: EPA's estimates of monitoring costs are averages and may not represent the actual
cost in individual circumstances. EPA does not agree that Tier 3 monitoring is adequate for all
large units that combust solid fossil fuels fuels, particularly if most, or all, of the CEMS
196
-------
infrastructure is already in place, because of the benefits CEMS provide over calculation
approaches in terms of difficulties measuring fuel quality and quantity. EPA is requiring the use
of CEMS due to the complexity of monitoring solid fuel consumption and the heterogeneous
nature of the solid fuels. The incremental cost of adding a flow monitor to meet Tier 4
monitoring requirements is not unduly burdensome for a unit that is already required to install,
certify, maintain, and operate CEMS, and to perform ongoing QA testing of the existing
monitors. EPA's estimated this cost as approximately $25,000 per year (2006 $).
Commenter Name: J. P. Blackford
Commenter Affiliation: American Public Power Association (APPA)
Document Control Number: EPA-HQ-OAR-2008-0508-0661.1
Comment Excerpt Number: 18
Comment: APPA supports alternatives to in-stack monitoring in Part 75, e.g. Appendix G to
Part 75 that allows gas-fired units to use heat input (derived from fuel flow monitoring data) to
calculate CO2 emissions.
Response: The commenter should note that EPA has added alternative methods for units that
report data to EPA according to Part 75, which allow certain oil- and gas-fired units to use
methods from Appendices D and G to Part 75. See §98.33(a)(5) of the final rule.
Commenter Name: Lawrence W. Kavanagh
Commenter Affiliation: American Iron and Steel Institute (AISI)
Document Control Number: EPA-HQ-OAR-2008-0508-0695.1
Comment Excerpt Number: 18
Comment: For facilities meeting all of the requirements specified in §98.33(b)(5), Tier 4
requirements are applicable. However, see our comments in reference to coke oven combustion
stacks and blast furnace stoves regarding necessary clarifications to §98.33(b)(5). In addition,
for those facilities that do qualify for Tier 4, we believe those requirements should only be
required for those units that have CO2 CEMS in place. EPA's requires facilities with CEMS that
do not monitor CO2 to "upgrade" to CO2 CEMS based on the premise that "incremental costs"
will not be duly burdensome. However, the incremental cost of adding CO2 monitoring when
installing a new CEMS is not the same as incremental cost of adding CO2 monitoring to an
existing CEMS, and EPA has understated the cost burden. Moreover, the added benefit of a CO2
CEMS over the methods specified for Tier 3 is marginal at best, particularly given problems with
operational reliability (as noted in our discussion for iron and steel sector monitoring options)
and does not justify the added costs.
Response: EPA acknowledges the commenter's concerns regarding Tier 4 applicability. EPA
has revised §98.33(b)(4)(ii) of the final rule to clarify that all six criteria specified in
subparagraphs (A) through (F) must be met before Tier 4 is required. However, EPA disagrees
with suggestions that Tier 4 should only be required if the installed CEMS include a CO2
monitor. The Tier 4 requirement is limited to larger solid fossil fuel units with an existing
pollutant CEMS or volumetric flow rate monitor, or a source with an existing CO2 CEMS and
197
-------
flow rate monitor. EPA is requiring the use of CEMS due to the complexity of monitoring solid
fuel consumption and the heterogeneous nature of the solid fuels. Many of these fossil fuel-fired
units with a pollutant CEMS have an existing diluent monitor (02 or C02) that can be used to
determine CO2 emissions. EPA's estimates of monitoring costs are averages for a representative
facility and may not represent the actual cost in individual circumstances.
Commenter Name: Michael Carlson
Commenter Affiliation: MEC Environmental Consulting
Document Control Number: EPA-HQ-OAR-2008-0508-0615
Comment Excerpt Number: 18
Comment: The proposed requirement for daily sampling of all gaseous fuels, except for natural
gas, under the General Stationary Fuel Combustion Category (16484) presents a serious
disincentive for facilities to use alternative, "green" gaseous fuels, and is inconsistent with efforts
by the current administration to promote alternative energy uses.
Response: For gaseous fuels other than natural gas or biogas, due to variability, the daily
sampling requirement has been retained, but only for facilities with existing equipment in place
that is capable of providing the data. Otherwise, weekly sampling is required. For biogas,
quarterly sampling is required.
Commenter Name: Michael Garvin
Commenter Affiliation: Pharmaceutical Research and Manufacturers of America (PhRMA)
Document Control Number: EPA-HQ-OAR-2008-0508-0959.1
Comment Excerpt Number: 17
Comment: PhRMA believes that EPA should require use of methods that are not accepted as
common practice in existing regulatory schemes and, where possible, should apply globally
accepted methods such those described in EU Directive 2003/97/EC and EU Directive
2007/589/EC. The current language in the proposed rule is not consistent with this standard. As
proposed, this rule may have potentially significant impacts on the pharmaceutical industry.
These impacts would include the need to install additional monitoring systems on our solid waste
incinerators (e.g., pathological waste incinerators, medical/infectious waste incinerators and solid
waste incinerators). A number of pharmaceutical facilities operate pathological waste
incinerators which are not regulated by detailed federal air quality standards such as the NSPS
and NESHAP rules. Given their status under these rules, these units are typically not equipped
with elaborate CEM systems. Under the proposed rule, facilities that trigger the 25,000 MT CO2
eq annual threshold may be required to either upgrade these waste incinerators to install carbon
dioxide CEM systems or discontinue their use and outsource the disposal of these materials.
Additionally, sites which may be close to the applicability threshold, may need to install and
operate elaborate and expensive monitoring systems simply to allow for accurate applicability
determinations. PhRMA believes that EPA should not require use of methods that are not
accepted as common practice in existing regulatory schemes and, where possible, apply methods
accepted globally such as those described in EU Directive 2003/87/EC and EU Directive
2007/589/EC. The existing language regarding CEM systems goes well beyond this.
198
-------
Response: EPA acknowledges the concerns of the commenter under the assumption that the
commenter believes that "EPA should not require the use of methods that are not accepted as
common practice ..."
EPA does not intend to require CEMS for this type of unit, and has clarified that all of the
criteria specified in §98.33(b)(4)(ii) or (iii) must be present to trigger Tier 4. EPA has also
revised the rule to specify that Tier 3 will only be required for units combusting fuels not listed
in Table C-l if the alternative fuel combusted in the unit makes up more than ten percent of the
average annual heat input to the unit, and the unit has a maximum rated heat input capacity
greater than 250 mmBtu/hr. Provided that CO2 CEMS are not required or elected, units smaller
than 250 mmBtu/hr are only required to report emissions from those fuels listed in Table C-l.
Therefore, in this case it appears that only the GHG emissions from combustion of
supplementary fossil fuels (if any) in these types of sources must be reported.
EPA respects the effort that may be required to determine applicability and has modified the
final rule in order to provide clarity. EPA expects that a source should be able to determine
applicability without installing new equipment.
Commenter Name: Michael Carlson
Commenter Affiliation: MEC Environmental Consulting
Document Control Number: EPA-HQ-OAR-2008-0508-0615
Comment Excerpt Number: 17
Comment: The use of Tier 2 or a higher tier for Tier 1 facilities if monthly higher heating
values (HHVs) are provided by the fuel supplier should not be mandatory, as proposed by the
agency (16484) but optional. From a practical standpoint, how is the agency to know if the fuel
supplier provides HHVs monthly?
Response: See the Preamble, Section VI., for the response on rule implementation and
enforcement.
EPA believes that it is appropriate to require the use of Tier 2 if the fuel supplier provides HHVs
at a frequency greater than or equal to the minimum frequency specified in §98.34. This
provision is necessary to ensure that facilities make use of the site-specific data that they already
have available. Additionally, fuel providers to stationary sources, particularly coal suppliers,
typically provide information to purchasers on the heat content of coal as part of private sector
contracts. See the technical support document for Subpart KK Suppliers of Coal.
Commenter Name: Karen St. John
Commenter Affiliation: BP America Inc. (BP)
Document Control Number: EPA-HQ-OAR-2008-0508-0631.1
Comment Excerpt Number: 16
Comment: EPA's proposed CEMS requirements for stationary fuel combustion sources in
Subpart C are overly restrictive and need to be made more flexible. In particular, as the
199
-------
proposed rule now reads and which is contrary to the Preamble, the blanket requirement to add a
CO2 monitor to existing CEMS system would impose unnecessary economic burden. The rule
should provide greater flexibility to allow the use of other GHG emission determination
methodologies. BP also draws EPA's attention to the need to add clarifying syntax to omissions
("and" and "or") to the Tier 4 calculation methodology language for large stationary combustion
units that are fired with solid fuels and that have existing CEMS equipment.
Response: EPA acknowledges the commenter's concerns regarding Tier 4 applicability. EPA
has revised §98.33(b)(4)(ii) of the final rule to clarify that all six criteria specified in
subparagraphs (A) through (F) must be met before Tier 4 is required. However, EPA disagrees
with suggestions that Tier 4 should only be required if the installed CEMS include a C02
monitor. The Tier 4 requirement is limited to larger solid fossil fuel units with an existing
pollutant CEMS or volumetric flow rate monitor, or a source with an existing C02 CEMS and
flow rate monitor. EPA is requiring the use of CEMS due to the complexity of monitoring solid
fuel consumption and the heterogeneous nature of the solid fuels. Many of these fossil fuel-fired
units with a pollutant CEMS have an existing diluent monitor (O2 or CO2) that can be used to
determine C02 emissions, and in other cases the existing CEMS can be upgraded to measure
CO2 emissions.
Commenter Name: Lawrence W. Kavanagh
Commenter Affiliation: American Iron and Steel Institute (AISI)
Document Control Number: EPA-HQ-OAR-2008-0508-0695.1
Comment Excerpt Number: 16
Comment: For units with heat inputs less than 250 MMBTUH, Tier 1 methodology would
apply. However, given the very large number of combustion units in a typical integrated facility,
even this simpler method is unnecessarily burdensome. For example, many plants have only a
single metering location for natural gas consumption by the entire plant, and the required
addition of individual metering of all units using natural gas would be unnecessarily costly.
Section 98.36(c)(3) allows for combined reporting of combustion units that are manifolded and
supplied by common fuel piping. We see little difference in expanding this to the entire plant.
Besides, the CO2 emissions from these sources will have already been accounted for in reports
required of upstream fuel suppliers.
Response: EPA acknowledges the concerns of the commenter. For units that use Tiers 1, 2, and
3 to calculate CO2 mass emissions, the cumulative 250 mmBtu/hr heat input capacity limit on
the aggregation of units into a group has been dropped. Rather, the 250 mmBtu/hr restriction
applies only to the individual units in the group. Therefore, for reporting purposes, individual
units with maximum rated heat input capacities of 250 mmBtu/hr or less may be aggregated
without limit into a single group, provided that the Tier 4 methodology is not required for any of
the units, and all units in the group use the same tier for any common fuel(s) that they combust.
In this case it appears that emissions from all of the small units could be reported jointly using
Tier 1 or Tier 2 methodologies. There is also an option to group units fed by a common pipe
configuration to take advantage of situations where the same fuel is metered centrally and fed to
multiple units.
Also, see the Preamble, Section II. L., for EPA's comments on the general monitoring approach.
200
-------
Commenter Name: Michael DiMauro
Commenter Affiliation: Massachusetts Municipal Wholesale Electric Company (MMWEC)
Document Control Number: EPA-HQ-OAR-2008-0508-0580
Comment Excerpt Number: 11
Comment: EPA should consider reducing, or even eliminating, fuel sampling/analysis
requirements for standard types of oil and gas fuels (pipeline gas, No. 2 oil, No. 6 oil, kerosene,
etc.), and should instead allow use of default C02 emission factors (C02 lb/MMBtu or C02
lb/unit of fuel consumed) at all Tier levels for units firing standard fuels. For standard gas and
oil fuels, the carbon content and the heat content are generally quite consistent (vary by only a
few % between samples), so that snap shot site-specific data collection is not expected to
improve data accuracies. To the contrary, snap shot data collection of fuel characteristic data
could complicate proper identification of GHG emission trends: Variability in site specific GHG
emissions caused by random fluctuations (i.e. noise) in fuel characteristic data values resulting
from the use of snapshot sampling, errors in the sampling process, and occasional anomalous
sample values could act to mask underlying trends in fuel usage and/or differences in fuel usage
across facilities. 1. Use of standard default emission factors would avoid this source of data
distortion and variability. 2. Policy initiatives for fuel combustion sources are likely to focus
improving fuel usage and efficiency patterns, and any factors that could mask such trends would
be counterproductive to the development of effective control measures, ii. There is a substantial
cost entailed in on-site monthly sampling and analysis of fuels, as well as a significant
recordkeeping burden. 1. Collection and transport of natural gas samples can be problematic. 2.
Costs of sample analysis are not insignificant. 3. On-site scheduling and tracking of sampling
activities represent a significant logistical and manpower burden. It is for these reasons that
many Part 75 Appendix D sources use fuel supplier data in lieu of performing on site sampling,
iii. As far as I am aware, neither the heat content nor the carbon content of gas and oil fuels can
be readily controlled, and therefore they are not likely to be targets for regulation. However, if
the tracking of fuel characteristic data is considered of potential benefit, it is suggested that such
data be obtained directly from fuel suppliers. Fuel supplier data should be more reliable,
complete and consistent than facility data, facilitating the identification of any temporal trends or
regional differences in fuel carbon content or GCV values, iv. It should also be noted that Part
75 [C02] default Fuel factors are used by all Dilution Extraction CEMS to measure [NOx, CO,
etc.] lb/MMBtu emission rates for compliance determination. It is unclear why such Emission
factors should be considered adequate for emission compliance assessments but not for simple
emission reporting. It should be noted that while these arguments apply equally to fuel high heat
content and to fuel carbon content, indicating that no sampling should be required for either
parameter, in practice, a requirement to obtain fuel high heat content data would not represent an
onerous burden to the site, if the fuel supplier could serve as the source of such data for all Tier
levels.
Response: EPA did not choose to adopt a simplified calculation method approach (e.g., using
default emission factors) for all units because the data would be less accurate than under the
selected option and would not make use of site-specific data that many facilities already have
available and refined calculation approaches that many facilities are already using. However, the
use of Tier 2 Calculation Methodologies for CO2 emissions has been expanded to include units
with a maximum rated heat input capacity greater than 250 mmBtu/hr in which the only fossil
201
-------
fuels combusted are pipeline natural gas and/or distillate oil. Furthermore, the sampling
frequencies for Tier 2 and Tier 3 have been revised to reduce the burden on reporters. For
example, the final rule requires that natural gas be sampled semiannually. For fuel oil and coal, a
representative sampling sample is required for each fuel lot, i.e., for each shipment or delivery.
The final rule also clarifies that fuel sampling and analysis data provided by the supplier may be
used in the emission calculations.
Commenter Name: See Table 3
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0433.2
Comment Excerpt Number: 20
Comment: NPRA disagrees with the blanket requirement to add a C02 (or 02 in some cases)
monitor to an existing CEMs system that qualifies under the conditions stated in the Preamble.
This will impose a substantial and unnecessary economic burden on some facilities. For
example, the proposed rule could be construed to require the addition of a C02 monitor to a
CEMs system that currently only measures stack gas flow, even though no gaseous pollutant
monitor is present. In order to accomplish this, not only would the facility be required to
purchase and install the C02 monitor, it also likely would have to purchase and install a data
acquisition and control system (DACS) for the CO2 monitor; an analyzer calibration system that
would be controlled by the DACS to transport the zero and span gases to the stack probe to meet
the quality assurance requirement to perform daily zero and span checks; a stack port into which
the stack gas sampling probe or monitor, if an in situ monitoring approach is selected and is
installed; and possibly a climate controlled monitor shelter to house the additional equipment. In
this case, the installation of a CO2 CEMS would impose substantial capital and operating costs to
the facility far beyond those estimated by the EPA in the supporting documentation or those
needed to provide the required data using alternative methodologies.
Response: EPA has revised §98.33 (b)(4)(ii) of the final rule to clarify that all six criteria
specified in subparagraphs (A) through (F) must be met before Tier 4 is required. The Tier 4
requirement is limited to larger solid fossil fuel units with an existing pollutant CEMS or
volumetric flow rate monitor, or a source with an existing CO2 CEMS and flow rate monitor.
EPA is requiring the use of CEMS due to the complexity of monitoring solid fuel consumption
and the heterogeneous nature of the solid fuels. Many of these fossil fuel-fired units with a
pollutant CEMS have an existing diluent monitor (O2 or CO2) that can be used to determine CO2
emissions. The incremental cost of adding a to monitor meet Tier 4 monitoring requirements is
not unduly burdensome for a large unit that combusts solid fossil fuels, and is already required to
install, certify, maintain, and operate a CEMS or flow rate monitor, and to perform ongoing QA
testing of the existing monitors. EPA's estimates of monitoring costs are averages for a
representative facility and may not represent the actual cost in individual circumstances. Further
detail on the engineering cost analysis for Subpart C can be found in RIA (EPA-HQ-OAR-2008-
0318-002), Section 4.3. We are also not aware of instances where only a certified flow rate
monitoring system is in place to meet a federal or state requirement.
202
-------
Commenter Name: Karen St. John
Commenter Affiliation: BP America Inc. (BP)
Document Control Number: EPA-HQ-OAR-2008-0508-0631.1
Comment Excerpt Number: 58
Comment: BP supports EPA's use of fuel-based CH4 and N20 emission factors, consistent with
aggregation of combustion sources using common fuel gas supplies. Requiring "unit specific"
CH4 and N20 factors would eliminate the option for aggregation of small sources and the "one-
meter" concept where a uniform fuel gas is used throughout a facility and would drive the
installation, maintenance, data capture and recording, and QA/QC requirements for metering or
monitoring at a unit specific level. Given the small (about 1%) of CC^e's that CH4 and N20
make up from combustion sources this is not cost/value effective. This could be particularly
problematic on offshore platform installations.
Response: EPA appreciates the supportive feedback, and has maintained these specifications in
the final rule.
Commenter Name: See Table 6
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0679.1
Comment Excerpt Number: 117
Comment: §98.38, Table C-3. CH4 and N2O factors are not defined, but should be added, for
the following fuel types currently listed in §98.38, Table C-l: Ethane; Biogas; Isobutane; n-
Butane; Natural Gasoline; Other Oil (> 401 def. F); Pentanes Plus; Petrochemical Feedstocks;
Special Naphtha; and Unfinished Oils.
Response: In response to the comment, EPA has extensively revised the default emission
factors needed to calculate CH4 and N2O emissions, adding generic fuel-based emission factors
covering all fuels listed in Table C-l. For example, many of the fuels mentioned by the
commenter are covered by the CH4 and N2O emission factors for "Petroleum" in Table C-2.
EPA has clarified in the final rule that only CH4 and N2O emissions from combustion of those
fuels listed in Table C-2 of Subpart C are required to be reported.
Commenter Name: See Table 6
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0679.1
Comment Excerpt Number: 116
Comment: §98.38, Table C-3 should include default CH4 and N2O emission factors for flexi
gas, consistent with the emissions factors adopted in California. Flexi gas is a low Btu gas
produced during FLEXICOKINGTM, where thermal cracking converts heavy hydrocarbons into
light hydrocarbons. The applicable California emission factors for flexi gas (referred to as a
derived gas, low BTU gases) are 0.3 g CH4 per MMBtu and 0.1 g N2O per MMBtu.
203
-------
Response: In response to the comment, EPA has extensively revised the default emission
factors needed to calculate CH4 and N20 emissions, consolidating the emission factors and
linking them to the fuel types listed in Table C-l. EPA has revised the final rule so that only
CH4 and N20 emissions from combustion of those fuels listed in Table C-2 of Subpart C are
required to be reported.
Commenter Name: See Table 6
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0679.1
Comment Excerpt Number: 115
Comment: §98.38, Table C-l: The emission factor for "Coke" is not specified to be a particular
type of coke (e.g. petroleum coke versus catalyst coke).
Response: The coke emission factors in Table C-l, under Coal and Coke, refer to coke derived
from coal. There is also an emission factor in Table C-l specific to petroleum coke under
Petroleum Products, and the rule definitions in §98.6 include catalyst coke as a petroleum coke.
Commenter Name: See Table 6
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0679.1
Comment Excerpt Number: 103
Comment: Based on Preamble language, API is concerned that the EPA believes any CEMS
can be easily converted to a C02 CEMS in Tier 4. API disagrees that this is a simple
conversion. For this reason, clarification should be added to §98.33(b)(5)(ii). In addition,
clarification should be added to §98.33(b)(5)(ii)(D) and (E) to indicate whether the "installed
CEMS" are any type of CEMS (i.e. criteria pollutant CEMS or CO2 CEMS) or a specific type of
CEMS (e.g. CO2 CEMS). For gaseous fuels metering of fuel volume coupled with analysis of
carbon content is likely to be more accurate than direct measurement of CO2 emissions with a
CEM. API will provide additional information on this topic.
Response: EPA has revised §98.33 (b)(4)(ii) of the final rule to clarify that all six criteria
specified in subparagraphs (A) through (F) must be met before Tier 4 is required. EPA disagrees
with suggestions that Tier 4 should only be required if the installed CEMS include a CO2
monitor. The Tier 4 CEMS requirement is limited to larger solid fossil fuel or MSW units with
an any type of existing pollutant CEMS or volumetric flow rate monitor, or a source with an
existing CO2 CEMS and flow rate monitor.
204
-------
Commenter Name: See Table 6
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0679.1
Comment Excerpt Number: 100
Comment: §98.33: Offshore facilities submit triannually an emission inventory to MMS under
the GOADS system for criteria pollutants. Offshore facilities should be allowed to use the same
calculations under the GOADS7 systems for GHG reporting since MMS has been granted
jurisdiction for offshore air emissions.
Response: See the Preamble, Section II. O., for the response on the relationship of this rule to
other programs. EPA requires all facilities to report annually directly to EPA to ensure timely
reporting of data in a consistent format, subject to consistent verification procedures.
Commenter Name: See Table 6
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0679.1
Comment Excerpt Number: 98
Comment: In Subpart MM (Suppliers of Petroleum Products), EPA requests "comment on
whether reporters should be allowed to combine default C02 emission factors to develop
alternative factors for fuel reformulations according to the volume percent of each fuel
component" (p. 16572). This issue also affects Subpart C. As there are currently no default
emission factors for fuel mixtures, Tiers 1 and 2 cannot be used to estimate combustion
emissions from fuel mixtures. However, since CO2 emissions are based on the carbon content of
the fuels, multiplying the volume of each pre-mixed fuel by its respective fuel-based emission
factor would result in an accurate estimate of CO2 for the fuel mixture. Clarification should be
added to Subpart C as to how emissions from fuel mixtures should be estimated, without the use
of carbon content measurements or CEMS. III.3, API requests that the reporting rule allow up to
5% of the emissions to be declared as "de minimis", allowing simplified emission estimation
methods for demonstrating compliance with this emission level. This should include small
combustion sources.
Response: See the Preamble, Section II., K., for the response on de minimis reporting for small
emission points.
While EPA does not agree that there should be a de minimis emissions exclusion, the Agency
has expanded the list of exempted source categories to include portable equipment, emergency
generators, and flares. In addition, units that combust hazardous waste will not be required to
report GHG emissions given specific provisions stated in §98.30(c). EPA has also removed the
cumulative 250 mmBtu/hr restriction on unit aggregation, and believes that the expanded
availability of this option will reduce the reporting burden on facilities.
Where different types of fuel are blended prior to combustion, and Tier 2 or 3 is used, EPA has
added an option to either use a weighted HHV or carbon content value in the emission
calculations based on the relative proportions of each fuel in the blend, or take a representative
sample of the blended fuel and analyze it for HHV or carbon content. Section 98.33(b)(6)
205
-------
provides clarification regarding the use of the tiers for units combusting more than one fuel. The
commenter should note that units reporting under Tier 3 are only expected to report emissions
from fuels that contribute more than ten percent of the unit's annual heat input.
Commenter Name: See Table 6
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0679.1
Comment Excerpt Number: 97
Comment: 11. EPA states : [...] given the unit-level approach for calculating CO2 emissions,
EPA is requesting comments on the use of more technology-specific CH4 and N20 emission
factors that could be applied in unit-level calculations." (p. 16485) API Comments: API
supports EPA's use of fuel-based CH4 and N20 emission factors, consistent with aggregation of
combustion sources using common fuel gas supplies. Requiring "unit specific" CH4 and N20
factors would eliminate the option for aggregation of small sources and the "one-meter" concept
where a uniform fuel gas is used throughout a facility and would drive the installation,
maintenance, data capture and recording, and QA/QC requirements for metering or monitoring at
a unit specific level. Given the small (about 1%) of CC^e's that CH4 and N2O make up from
combustion sources this is not cost/value effective. This could be particularly problematic on
offshore platform installations.
Response: EPA appreciates the supportive feedback, and has maintained these specifications in
the final rule.
Commenter Name: See Table 10
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0635
Comment Excerpt Number: 76
Comment: EPA's proposed rule includes flaring in the fugitive emission category. Flares are
combustion sources and are included in EPA's combustion equipment inventories for criteria air
pollutants, and in current industry GHG combustion equipment inventories. Flares are a large
source of GHG emissions. We recommend that all flare sources be required to report GHG
emissions, and these emissions be included in the combustion equipment category as a
standalone source. While some operators have taken steps to minimize flaring emissions, this is
still a very large viable GHG emission reduction target, with known cost-effective emission
reduction opportunities.
Response: EPA acknowledges the concerns of the commenter, but has concluded that in many
cases flare sources are not significant, considering the small quantity of emissions captured and
the expense associated with their quantification. EPA has revised the list of exemptions from the
general stationary combustion source category to exclude flares (see §98.30(b)(3)) from Subpart
C, so long as flare emissions are not required to be reported by another subpart. Note that
Subpart W Oil and Gas Operations is not being finalized at this time.
206
-------
Commenter Name: Karen St. John
Commenter Affiliation: BP America Inc. (BP)
Document Control Number: EPA-HQ-OAR-2008-0508-0631.1
Comment Excerpt Number: 71
Comment: Biogenic carbon is carbon derived from biogenic (plant or animal) sources
(excluding fossil carbon) that have been fixed from atmospheric carbon dioxide through
photosynthesis. Biogenic carbon is part of the natural carbon cycle where there is a continuous
exchange of carbon between the biosphere and the atmosphere. BP recommends that the
calculation methodology for quantifying CO2 emissions from the combustion of biogenic
material in Subpart C Section 98.33(e) should be removed to make its treatment more consistent
with the Kyoto Protocol. By international reporting convention, CO2 emissions from the
combustion of biogenic material are zero by definition. The international reporting convention
was designed to enable the reporting of robust and complete national GHG emission inventories
without double counting and forms the basis of the international flexible mechanisms within the
Kyoto Protocol. BP accepts the logic of the international convention for the reporting of CO2
from the combustion of biomass and considered carbon neutral and recommends that C02
emissions from the combustion of biogenic carbon not be included in the final rule. Biofuels
production facilities should only be required to report emissions from on-site stationary
combustion of fossil fuels. BP anticipates that a number of technologies and processes would
utilize biomass to power advanced and cellulosic biofuels production facilities. For example, in
Brazil, where over 50% of the nation's fuel is comprised of biofuels, biomass is the source of
power for most biofuels production facilities. In much the same manner, it is likely that
cellulosic biofuels facilities built in the U.S. to meet federal mandates would utilize biomass to
produce the power necessary to run the production facility.
Response: See the response to comment EPA-HQ-OAR-2008-0508-0690.1 excerpt 1
corresponding to Section II. of the Preamble, and the response to comment EPA-HQ-OAR-2008-
0508-0631.1 excerpt 71 corresponding to Subpart C for additional explanation of the reporting of
biogenic CO2 emissions.
Including reporting of biogenic CO2 at facilities that are already reporting for stationary
combustion provides EPA with information on the use of biofuels as they relate to reductions of
fossil CO2 emissions over time. This reporting requirement also provides additional data for
verification. EPA believes that it is clear in §98.2, however, that CO2 emissions from biogenic
fuels do not count toward the 25,000 metric ton threshold for reporting for stationary combustion
units, although CH4 and N2O emissions from biogenic fuels must be considered when
calculating the threshold and determining applicability.
EPA has specified in §98.33 that in most cases Tier 1 may be used to calculate emissions from
the combustion of biogenic fuels listed in Table C-l in a unit of any size.
Also see the Preamble, Section II. C., for EPA's response to comments on GHGs to report.
207
-------
Commenter Name: Karen St. John
Commenter Affiliation: BP America Inc. (BP)
Document Control Number: EPA-HQ-OAR-2008-0508-0631.1
Comment Excerpt Number: 64
Comment: It is apparent from EPA's construct and use of the 4 Tier Monitoring system and the
discussion in the Preamble that EPA presumes that CEMS are the most accurate methodology to
estimate C02 emissions. BP has evaluated this premise and illustrated that metering of gaseous
fuels combined with carbon content analysis of the fuel (gas) has more inherent accuracy than
use of a CEMS for determining C02 emissions. The typical types of gas meters used in the
industry will all return better relative accuracy than use of a CEMS. [See DCN: EPA-HQ-OAR-
2008-0508-0631.1 for Tables showing Fuel Meter Method Uncertainty and CEMS Uncertainty]
Response: See the response to comment EPA-HQ-OAR-2008-0508-0455.1 excerpt 7 and the
response to comment EPA-HQ-OAR-2008-0508-0580 excerpt 10 for EPA's rationale and
approach to the use of CEMS.
EPA has revised §98.33(b)(4)(ii) of the final rule to clarify that all six criteria specified in
subparagraphs (A) through (F) must be met before Tier 4 is required. The Tier 4 CEMS
requirement is limited to larger solid fossil fuel and MSW units with an existing pollutant CEMS
or volumetric flow rate monitor, or a source with an existing CO2 CEMS and flow rate monitor.
Commenter Name: Marcelle Shoop
Commenter Affiliation: Rio Tinto Services, Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-0636.1
Comment Excerpt Number: 25
Comment: The proposed rule only requires facilities with installed CEMS to use CEMS. One
of the criteria for determining whether a facility with installed CEMS must use the Tier 4
Calculation Methodology is that the "installed CEMS include a gas monitor of any kind." (74
Fed. Reg. at 16634, proposed §98.33(b)(5)(ii)(E) Rio Tinto supports EPA's decision to require
CEMS only at facilities that already have installed CEMS. A Rio Tinto facility has an installed
continuous opacity monitoring system. Since this device does not measure gas, we seek
clarification from EPA that an opacity monitor is NOT a "gas monitor of any kind."
Response: EPA has added language to the final rule clarifying that only sources meeting all of
the requirements in §98.33(b)(4)(ii) or (iii) will be required to use Tier 4 methods. Sources
operating only COMS will not be required to use Tier 4. EPA does not believe that any further
language is necessary to address this issue.
208
-------
Commenter Name: Karen St. John
Commenter Affiliation: BP America Inc. (BP)
Document Control Number: EPA-HQ-OAR-2008-0508-0631.1
Comment Excerpt Number: 59
Comment: In Subpart MM (Suppliers of Petroleum Products), EPA requests "comment on
whether reporters should be allowed to combine default CO2 emission factors to develop
alternative factors for fuel reformulations according to the volume percent of each fuel
component" (p. 16572). This issue also affects Subpart C. As there are currently no default
emission factors for fuel mixtures, Tiers 1 and 2 cannot be used to estimate combustion
emissions from fuel mixtures. However, since CO2 emissions are based on the carbon content of
the fuels, multiplying the volume of each pre-mixed fuel by its respective fuel-based emission
factor would result in an accurate estimate of CO2 for the fuel mixture. BP requests that EPA
clarify how emissions from fuel mixtures should be estimated, without the use of carbon content
measurements or CEMS.
Response: Where different types of fuel are blended prior to combustion, and Tier 2 or 3 is
used, EPA has added an option to either use a weighted HHV or carbon content value in the
emission calculations based on the relative proportions of each fuel in the blend, or take a
representative sample of the blended fuel and analyze it for HHV or carbon content.
§98.33(b)(6) provides clarification regarding the use of the tiers for units combusting more than
one fuel. The commenter should note that units reporting under Tier 3 are only expected to
report emissions from fuels that contribute more than ten percent of the unit's annual heat input.
Commenter Name: Lawrence W. Kavanagh
Commenter Affiliation: American Iron and Steel Institute (AISI)
Document Control Number: EPA-HQ-OAR-2008-0508-0695.1
Comment Excerpt Number: 14
Comment: Subpart C requires reporting of combustion unit CH4 and N2O emissions using
default values for various fuels shown in Table C-3. No values are presented for blast furnace
gas. We are not aware of any reliable emission factors for these gases for blast furnace gas
combustion but believe concentrations of these gases to be insignificant, if present at all, in the
combustion products of blast furnace gas and suggest deleting this requirement for blast furnace
gas combustion sources.
Response: EPA acknowledges the concerns of the commenter. Section 98.33(c) of the final
rule excludes from calculations any CH4 and N2O emissions from fuels that are not listed in
Table C-2 of Subpart C. Table C-2 has been revised to include CH4 and N2O emission factors
for more fuels, including blast furnace gas and coke oven gas, as well as generic emission factors
covering all fuel types listed in Table C-l. EPA has also deleted the provision which allowed
facilities burning other fuels to develop site-specific emission factors based on the results of
source testing.
209
-------
Commenter Name: Gregory A. Wilkins
Commenter Affiliation: Marathon Oil Corporation
Document Control Number: EPA-HQ-OAR-2008-0508-0712.1
Comment Excerpt Number: 56
Comment: Marathon proposes that natural gas pilots should be allowed the use of engineering
estimates for their contribution to heater BTU values. Natural gas pilots represent less than 5%
of the heater designed BTU value and do not have flow meters. For most refinery heaters the
pilot gas system is separate from the main combustion systems. Marathon has concerns that
EPA would require a flow meter on this stream if emissions are required to be reported on a unit
by unit basis. Because these are such small streams and because there are numerous streams
located in the facilities, this would represent a large cost and burden to install and maintain any
equipment needed.
Response: EPA has removed the cumulative 250 mmBtu/hr restriction on unit aggregation and
has clarified the use of common pipe metering. While emissions from natural gas pilots such as
these should be reported, it is not necessary to add individual fuel flow meters on each pilot.
Instead, a single fuel flow meter on the pipe supplying natural gas to multiple pilots or other
units at the facility may be used. EPA believes that the expanded availability of these options
will reduce the reporting burden on facilities.
Commenter Name: Gregory A. Wilkins
Commenter Affiliation: Marathon Oil Corporation
Document Control Number: EPA-HQ-OAR-2008-0508-0712.1
Comment Excerpt Number: 54
Comment: Marathon opposes the requirement of monthly monitoring of natural gas used within
the facility. Pipeline quality natural gas is homogenous and its qualities do not change. The use
of supplier data should be allowed for natural gas as with other fuels, with a frequency of
providing that data no more often than monthly as offered elsewhere in the rule (for example the
monthly supplier heating values allowed in 98.33(b)(l)(ii)). This data would meet the
requirements for the reporting rule as there is almost no possibility of these parameters changing
if there are no streams being added to the incoming natural gas stream from the point where the
supplier is monitoring to the point where it comes on site. This is an unnecessary requirement to
mandate as efforts will only be duplicated with no added benefit. In addition, natural gas sample
equipment required to be added on the line to collect samples will be costly. Marathon would
propose to remove the requirement from the Tier 3 methodology requiring monthly sampling of
natural gas and instead allow the submission of supplier provided carbon content data.
Response: The commenter should note that EPA has expanded the use of the Tier 2 Calculation
Methodology to units of any size in which the only fossil fuels combusted are pipeline quality
natural gas and/or distillate oil. Furthermore, the mandatory fuel sampling and analysis
requirements for Tiers 2 and 3 have been considerably revised. EPA agrees with the commenter
that for a homogeneous fuel such as pipeline natural gas, monthly sampling is not necessary.
Therefore, §98.34 has been revised to require that natural gas be sampled semiannually.
210
-------
The final rule clarifies that fuel sampling and analysis data provided by the supplier may be used
in the emission calculations, and that fuel billing meters may be used to quantify fuel
consumption. To simplify the emission calculations in Tiers 2 and 3, arithmetic averaging of
HHV and carbon content data is permitted if these data are obtained at least at the minimum
frequency specified in §98.34, but less frequently than monthly (see §98.33(a)(2)(ii)). If
sampling is more frequent, the reporter must calculate a weighted average according to Equation
C-2b. However, regardless of the sampling frequency, the owner or operator must use the results
of all available valid fuel analyses in the emissions calculations.
Commenter Name: Sam Chamberlain
Commenter Affiliation: Murphy Oil Corporation
Document Control Number: EPA-HQ-OAR-2008-0508-0625
Comment Excerpt Number: 39
Comment: EPA requests "comment on whether reporters should be allowed to combine default
CO2 emission factors to develop alternative factors for fuel reformulations according to the
volume percent of each fuel component" (Preamble, p. 648). As there are currently no default
emission factors for fuel mixtures, Tiers 1 and 2 cannot be used to estimate combustion
emissions from fuel mixtures. Murphy operates two refineries and twelve terminals across the
USA performing various blending mixtures. This issue also affects Subpart C. Since CO2
emissions are based on the carbon content of the fuels, multiplying the volume of each pre-mixed
fuel by its respective fuel-based emission factor would result in an accurate estimate of CO2 for
the fuel mixture. Clarification should be added to Subpart C as to how emissions from fuel
mixtures should be estimated, without the use of carbon content measurements or CEMS.
Response: Where different types of fuel are blended prior to combustion, and Tier 2 or 3 is
used, EPA has added an option to either use a weighted HHV or carbon content value in the
emission calculations based on the relative proportions of each fuel in the blend, or take a
representative sample of the blended fuel and analyze it for HHV or carbon content.
§98.33(b)(6) provides clarification regarding the use of the tiers for units combusting more than
one fuel. The commenter should note that units reporting under Tier 3 are only expected to
report emissions from fuels that contribute more than ten percent of the unit's annual heat input.
Commenter Name: Rich Raiders
Commenter Affiliation: Arkema Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-0511.1
Comment Excerpt Number: 38
Comment: Arkema does not understand why individual reporters should be required to
determine the high heating value ("HHV") of commodity quality fuels being burned in Part 98
reporting units. Pipeline and commodity fuel distributors manage HHV values for their fuel
streams within their processes. EPA correctly notes that most commodity fuel manufacturers do
not currently disclose HHV data to their customers, but could readily distribute this information
to their customers. EPA should revise proposed Subpart C to allow reporters to utilize vendor-
provided HHV in lieu of developing periodic HHV data from commodity fuels.
211
-------
Response: The final rule clarifies that fuel sampling and analysis data provided by the supplier
may be used in the emission calculations.
Commenter Name: Rich Raiders
Commenter Affiliation: Arkema Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-0511.1
Comment Excerpt Number: 37
Comment: Owners and operators of commodity fuels may use the Tier 1 or 2 compliance
systems to report C02e emissions from fuel combustion sources using commodity fuels. EPA
should allow operators of thermal APCD to use total supplemental fuel delivered to the APCD to
calculate C02e emissions from such devices. Many reporters can, and are required to, calculate
with reasonable accuracy, using existing CAA required approaches, the total APCD input stream
over the course of a year. Where these total APCD input loading calculations already exist, EPA
should allow the reporters to utilize this existing information to calculate CC^e values for each
device as a compliance option for proposed Subpart C Tier 3 reporting requirements. The Tier 3
daily BTU analysis, molecular weight determination, and carbon content determination are
redundant with existing requirements to determine total load into APCD.
Response: EPA acknowledges the concerns of the commenter and has revised §98.33 to deal
with certain unconventional combustion processes and types of fuel. In the Preamble, EPA has
explained that "devices such as thermal oxidizers and pollution control devices . . . would report
only the GHG emissions from the firing of supplemental fossil fuels." EPA believes that these
provisions satisfy the intent of Part 98, to collect accurate and consistent GHG emissions data
that can be used to inform future decisions.
Commenter Name: See Table 5
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0480.1
Comment Excerpt Number: 36
Comment: Tiers 1 and 2 indicate that fuel combusted must be based on company records and
the operator must provide an explanation and data used to determine fuel consumption. Natural
gas sector operators are required to report combustion emissions for pollutants (e.g., NOx,
VOCs, etc.) under Clean Air Act and state programs. For consistency, those technical
approaches for fuel use determination should be allowed under Subpart C. As an example, fuel
consumption is determined based on operating hours, source rated capacity, and brake specific
fuel consumption (i.e., Btu/hp-hr fuel use, which is a measure of unit operating efficiency).
INGAA's understanding is that the operator has discretion to use such approaches to determine
fuel consumption for Tier 1 and Tier 2 and that current practice acceptable for other emissions
reporting obligations are acceptable for GHG reporting under Subpart C.
212
-------
Response: EPA acknowledges the commenter's concerns, and has defined the term "company
records" in §98.6 of the final rule. EPA believes that the revised definition provides appropriate
guidance as to what records a facility may use to determine fuel consumption.
Commenter Name: See Table 5
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0480.1
Comment Excerpt Number: 35
Comment: To avoid confusion during implementation and provide reporting consistency,
INGAA recommends that EPA specify the horsepower (hp) equivalent to 250 MMBtu/hr.
Combustion capacity at many facilities is permitted based on horsepower rating rather than firing
rate, and presenting the horsepower equivalent will ensure that the aggregation threshold is
consistently implemented for subject facilities. INGAA recommends that the rule indicate that
aggregation for combustion reporting can be based on 250 MMBtu/hr or 30,000 hp. Similarly,
the 30,000 hp equivalency to 250 MMBtu/hr should be used for defining whether a Tier 1 or Tier
2 approach can be used for an individual source (i.e., larger sources must use Tier 3 or Tier 4).
Response: See the Preamble, Section II. E., and the response to comment EPA-HQ-OAR-2008-
0508-0350.1 excerpt 3 for additional explanation of the selection and form of thresholds.
EPA acknowledges the concerns of the commenter but as demonstrated by the commenter it is
straightforward for reporters to establish equivalencies for horsepower and heat input to be used
internally as guides. To avoid confusion associated with multiple thresholds in different units,
EPA will not define a horsepower equivalent to the 250 mmBtu/hr maximum rated heat input
capacity in the final rule. EPA plans to issue additional guidance to help potential reporters
determine applicability and the use of tiers.
Commenter Name: See Table 6
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0679.1
Comment Excerpt Number: 35
Comment: API would like to emphasize a major discrepancy between the Preamble discussion
and the rule language under Subpart C: The Preamble states that continuous emission
monitoring systems (CEMS) are only required for combustion devices fired by solid fuels, as
listed in Table C-l on page 16481; The rule language regarding selection of the "Tier" level for
monitoring and measurement methods does not reflect the discussion and intent in the Preamble;
Section 98.33(b)(5), as currently written, would require CEMS for any combustion unit that ran
for more than 1,000 hours in any year since 2005; There seems to be some syntax omissions,
including some "and" and "or" omissions in the current rule language. These omissions seem to
contravene the Preamble intent as summarized in Table C-l. API is providing in Exhibit 3
below an excerpt of the rule language with specific edits for amending the rule language to
reflect the intent and rationale presented in the Preamble, and as summarized in Table C-l (74
FR 68, page 16481). Exhibit 3 - Recommended rule language amendment (74 FR 16634, April
213
-------
10, 2009) (b) Use of the four tiers. (5) The Tier 4 Calculation Methodology: (i) May be used for
a unit of any size, combusting any type of fuel, (ii) Shall be used for a unit if: (A) The unit has a
maximum rated heat input capacity greater than 250 mmBtu/hr, or if the unit combusts municipal
solid waste and has a maximum rated input capacity greater than 250 tons per day of MSW, and
(B) The unit combusts solid fossil fuel or MSW, either as a primary or secondary fuel, and (C)
The unit has operated for more than 1,000 hours in any calendar year since 2005, or (D) The unit
meets the criteria in (B) and (C) directly above, and (E) The unit has installed CEMS that are
required either by an applicable Federal or State regulation or the unit's operating permit, and (F)
The installed CEMS include a gas monitor of any kind, a stack gas volumetric flow rate monitor,
or both and the monitors have been certified in accordance with the requirements of part 75 of
this chapter, part 60 of this chapter, or an applicable State continuous monitoring program, and
(G) The installed gas and/or stack gas volumetric flow rate monitors are required, by an
applicable Federal or State regulation or the unit's operating permit, to undergo periodic quality
assurance testing in accordance with appendix B to part 75 of this chapter, appendix F to part 60
of this chapter, or an applicable State continuous monitoring program, (iii) Shall be used for a
unit with a maximum rated heat input capacity of 250 mmBtu/hr or less and for a unit that
combusts municipal solid waste with a maximum rated input capacity of 250 tons of MSW per
day or less, if the unit: (A) Has both a stack gas volumetric flow rate monitor and a CO2
concentration monitor, and (B) The unit meets the other conditions specified in paragraphs
(b)(5)(ii)(B) and (C) of this section, and (C) The CO2 and stack gas volumetric flow rate
monitors meet the conditions specified in paragraphs (b)(5)(ii)(D) through (b)(5)(ii)(F) of this
section.
Response: EPA acknowledges the commenter's concerns regarding Tier 4 applicability. EPA
has revised §98.33(b)(4) of the final rule to clarify that either all six criteria specified in
§98.33(b)(4)(ii) subparagraphs (A) through (F) or all three criteria specified in §98.33(b)(4)(iii)
subparagraphs (A) through (C) must be met before Tier 4 is required.
Commenter Name: Lauren E. Freeman
Commenter Affiliation: Hunton & Williams LLP
Document Control Number: EPA-HQ-OAR-2008-0508-0493.1
Comment Excerpt Number: 34
Comment: EPA proposes to require that all ARP affected units, and "other units monitoring
heat input year round under §75.10(c)" and reporting heat input under §75.64, use Part 75 heat
input data (in mmBtu) and a fuel-specific emission factor from Table C-3 to report CH4 and
N2O. Proposed §98.33(c). For all other units, EPA proposes to require use of (1) measured
HHV, if measured or provided at least monthly, and (2) if not measured monthly, the default
HHV specified in Table C-l. Proposed section 98.33(c). UARG again appreciates the
opportunity to use quality-assured data reported under Part 75. However, UARG has the same
concerns regarding use of missing data procedures and bias adjustment factors for CH4 and N2O
as described above for CO2. As a result, UARG requests that the same alternative be provided
for missing volumetric flow data and Appendix D fuel flow data as requested above for Subpart
D. UARG also notes that it would not necessarily agree to use of bias-adjusted volumetric flow
data to calculate heat input, and mass emission of CH4 and N2O, in a possible future program
regulating GHG.
214
-------
Response: See the Preamble, Section III. C., the Subpart D comment response document
volume, and response to comment EPA-HQ-OAR-2008-0508-0956.1 excerpt 20 for the rationale
for using substitute data reported under Part 75.
EPA acknowledges the commenter's concerns, but believes that it is appropriate to use the heat
input data reported under Part 75 for the purposes of calculating CH4 and N2O emissions from
Part 75 units. As the commenters point out, this data is already quality-assured and reported to
EPA, and it is consistent with EPA's overall approach to require minimum additional reporting
for facilities already reporting C02 to EPA. EPA does not believe that it is appropriate to
provide any alternative missing data procedures for Part 75 units. Requiring additional missing
data procedures would require additional verification of data currently being reported by these
units.
Commenter Name: Lauren E. Freeman
Commenter Affiliation: Hunton & Williams LLP
Document Control Number: EPA-HQ-OAR-2008-0508-0493.1
Comment Excerpt Number: 33
Comment: Although EPA's proposed rule appropriately allows ARP affected oil- and gas-fired
units to comply with this rule by reporting annual CO2 mass emissions calculated using the
Appendix G "F-factor method," that option is not provided for other combustion sources. UARG
believes that it should be. The F-factors used under Appendix G are well established and apply
only to homogeneous liquid and gaseous fuels with little expected variability in their carbon
content. EPA recognized this lack of variability in its own proposed Tier 3 methodology, which
requires sampling for carbon content only monthly. The Appendix G "F-factor method" is also
based on the same F-factors used by Tier 4 sources with CEMS to convert O2 CEMS values to
CO2. In short, UARG sees no reason not to allow non-ARP stationary combustion sources
owned or operated by electric generating companies to use this methodology as well. The
accuracy is certainly of sufficient quality to serve the information gathering purposes of this rule.
Response: The commenter should note that EPA has added alternative methods for units that
report data to EPA according to Part 75, which allow certain oil- and gas-fired units to use
methods from Appendices D and G to Part 75. See §98.33(a)(5) of the final rule.
Commenter Name: See Table 5
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0480.1
Comment Excerpt Number: 33
Comment: As Section §98.33(a) identifies a tiered approach for determining combustion CO2
emissions. INGAA supports this approach, which provides flexibility based on the information
that is available while providing accurate combustion CO2 estimates. For natural gas-fired
sources, fuel quality will typically be stable over extended time periods, thus an annual average
value for gas quality parameters and annual fuel use should be allowed for calculating
combustion CO2 emissions for Tiers 2 and 3. This will minimize unnecessary reporting burden.
215
-------
Data quality can be assured via records that document consistent fuel quality. In addition, to
avoid any potential for future confusion, INGAA requests clarification regarding application of
the Tier 4 approach, which relies on continuous emissions monitoring systems (CEMS). CEMS
are required for some large electric generating units and other select sources, and optional for
other sources. §98.33(b)(5)(ii) identifies criteria that mandate CEMS, and it is apparent based on
the Preamble discussion that all of the criteria in (ii) must apply. However, when not clearly
specified, regulatory criteria can be interpreted as or rather than and criteria. To avoid any
potential for confusion, §98.33(b)(5)(ii) should be revised to indicate that Tier 4, "shall be used
for a unit if all of the following apply:"
Response: In the final rule, the use of the Tier 2 Calculation Methodologies for C02 emissions
has been expanded to include units greater than 250 mmBtu/hr in which the only fossil fuels
combusted are pipeline natural gas and/or distillate oil. The revised Tier 2 methods allow
emissions to be calculated based on total annual fuel consumption and average measured HHV,
calculated according to specifications in the rule. In addition, the mandatory fuel sampling and
analysis requirements for Tiers 2 and 3 have been considerably revised. Section 98.34 in the
final rule requires that natural gas be sampled semiannually.
EPA acknowledges the commenter's concerns regarding Tier 4 applicability. EPA has revised
§98.33(b)(4)(ii) of the final rule to clarify that all six criteria specified in subparagraphs (A)
through (F) must be met before Tier 4 is required.
Commenter Name: Karen St. John
Commenter Affiliation: BP America Inc. (BP)
Document Control Number: EPA-HQ-OAR-2008-0508-0631.1
Comment Excerpt Number: 60
Comment: Offshore facilities tri-annually submit an emission inventory to the U.S. Department
of Interior Minerals Management Service (MMS) under the GOADS system for criteria
pollutants. Offshore facilities should be allowed to use the same monitoring, data, and approach
as used for the GOADS inventory.
Response: See the Preamble, Section II. O., for the response on the relationship of this rule to
other programs. EPA requires all facilities to report annually directly to EPA to ensure timely
reporting of data in a consistent format, subject to consistent verification procedures.
Commenter Name: Michael DiMauro
Commenter Affiliation: Massachusetts Municipal Wholesale Electric Company (MMWEC)
Document Control Number: EPA-HQ-OAR-2008-0508-0580
Comment Excerpt Number: 14
Comment: Units subject to Tier III monitoring should be provided the option of conforming
with 40 FCR 75 Appendix D fuel metering/fuel sampling procedures and data reduction
procedures to determine CO 2.
216
-------
Response: EPA has expanded the use of the Tier 2 Calculation Methodology to include units
greater than 250 mmBtu/hr that combust only pipeline natural gas and/or distillate oil. This
would affect non-ARP units referenced by the commenter. The monthly fuel sampling and
analysis requirements for Tiers 2 and 3 have been considerably revised. §98.34 of the final rule
requires that natural gas be sampled semiannually. For other fuels such as oil and coal, which
are delivered in shipments or lots, requiring monthly sampling may be impractical. For fuel oil
and coal, a representative sampling is required for each fuel lot, i.e., for each shipment or
delivery. For other liquid fuels and biogas, quarterly sampling is required.
In addition, alternative methodologies have been added to the rule, allowing sources that monitor
and report heat input according to Part 75, but are not required to report C02 mass emissions, to
use established Part 75 CO2 emissions calculation methods to meet the Part 98 reporting
requirements. See §98.33(a)(5).
Commenter Name: Lawrence W. Kavanagh
Commenter Affiliation: American Iron and Steel Institute (AISI)
Document Control Number: EPA-HQ-OAR-2008-0508-0695.1
Comment Excerpt Number: 15
Comment: Coke oven gas not used for oven underfiring and blast furnace gas not used in stoves
are distributed as useful fuels for other combustion processes throughout the plant. These units
may include boilers, reheat furnaces, annealing furnaces, process heaters, space heaters, and
other miscellaneous direct- and indirect-fired combustion units, often in combination with
natural gas or other purchased fuels. Coke oven gas and blast furnace gas used in this way
reduces the amount of energy that would have to be purchased to operate these facilities and
thereby reduces the CO2 emissions that would be associated with those purchased fuels. In
addition to combustion sources fired with coke oven gas or blast furnace gas, steel plants,
whether integrated facilities or EAF facilities, contain numerous other combustion sources fired
with natural gas or fuel oil. For larger plants, these sources can amount to hundreds of individual
units. Subpart C of the proposed rule requires the reporting of CO2 emissions for all such units,
regardless of size or firing rates. In some cases this would require Tier 2 or Tier 3 methodology.
For example, blast furnace gas-fired boilers and reheat furnaces at both integrated and EAF
facilities typically exceed 250 MMBTUH. In other cases, Tier 1 methodology would be
permitted. For combustion units larger than 250 MMBTUH, Tier 3 methodology is unnecessary.
These combustion sources are not typically equipped with the instrumentation to comply with
the prescribed methodology, and requirements to install such equipment are contrary to
statements elsewhere in the rule that new monitoring equipment is not required. Accordingly, if
reporting of all combustion source CO2 emissions is retained in the final rule, we respectfully
request that Tier 1 methodology apply. Total annual CO2 emissions can be determined with
sufficient certainty and accuracy by averaging routine fuel analyses or applying documented
default values and estimated consumption rates.
Response: When two or more liquid-fired or gaseous-fired stationary combustion units at a
facility combust the same type of fuel and the fuel is fed to the individual units through a
common supply line or pipe, facilities may report the combined emissions from the units served
by the common supply line, in lieu of separately reporting the GHG emissions from the
individual units, provided that the total amount of fuel combusted by the units is accurately
217
-------
measured at the common pipe or supply line using a fuel flow meter that is calibrated in
accordance with §98.34(a). If the common pipe option is selected, the applicable tier shall be
used based on the maximum rated heat input capacity of the largest unit served by the common
pipe configuration.
EPA has significantly expanded the use of the Tier 2 Calculation Methodology for units that
combust only natural gas and/or distillate oil, in view of the homogeneous nature of these fuels.
However, the Tier 3 methodology is still required for large 250 mmBtu/hr units that combust
residual oil, solid fossil fuel, and other gaseous fuels (including coke oven gas and blast furnace
gas).
For gaseous fuels other than natural gas and biogas, due to variability, the daily sampling
requirement has been retained, but only for facilities with existing equipment in place that is
capable of providing the data. Otherwise, weekly sampling is required. EPA also has limited the
Tier 3 requirement to fuels that make up at least ten percent of the annual heat input for a unit or
group of units.
The commenter should note that EPA has provided default values for coke oven gas and blast
furnace gas in Table C-l, allowing units smaller than 250 mmBtu/hr combusting these fuels to
use Tier 1 or Tier 2. EPA has also removed the cumulative 250 mmBtu/hr restriction on unit
aggregation, and has clarified the common pipe reporting option.
Commenter Name: Filipa Rio
Commenter Affiliation: Alliance of Automobile Manufacturers (Alliance)
Document Control Number: EPA-HQ-OAR-2008-0508-0630.1
Comment Excerpt Number: 24
Comment: The Alliance supports the premise of a four-tier system of CO2 emission calculation
methodologies for stationary combustion. The tier concept provides for an appropriate level of
monitoring and complexity based upon the significance of the source. In particular, Tier 1,
which provides the use of a fuel-specific default C02 emission factor, a default heat content, and
annual fuel consumption from company records, is particularly beneficial as opposed to a
continuous monitoring approach (i.e., GEMS) that is costly and burdensome to smaller emitters.
Response: EPA appreciates your support, and thanks you for your comment.
Commenter Name: Keith Adams
Commenter Affiliation: Air Products and Chemicals, Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-1142.1
Comment Excerpt Number: 23
Comment: The Preamble for the proposed rule states that CO2 emissions far exceed the CC>2-e
contributions of combustion byproduct emissions of CH4 and N20, specifically "less than 1
percent of combined U.S. GHG emissions from stationary combustion, on a CC>2-e basis."
Despite this insignificant contribution, combustion sources are being required to estimate these
218
-------
emissions. In some instances, particularly where the lower tier methods for calculating C02
emissions are employed, the calculation of combustion byproduct CH4 and N2O is
straightforward. But in instances where more rigorous methods for calculating C02 emissions
are required (e.g. Tier 4), the calculation of combustion byproduct CH4 and N2O requires a
completely separate calculation process (and inherent process measurement data), comparable to
Tiers 1 - 3 for CO2 emissions. This is a burdensome requirement for an insignificant
contribution to a source's overall GHG footprint. Air Products does not support calculating the
combustion byproduct CH4 and N2O. However, if the agency feels these emissions are
significant, it should allow greater use of Tiers 1, 2, and 3 for estimating C02 emissions (per
comments on §98.33(b), above).
Response: See the Preamble, Section II. C., and the response to comment EPA-HQ-OAR-2008-
0508-0561.1 excerpt 2 for information on the rationale for reporting for CH4 and N2O. EPA
believes that the use of fuel-specific emission factors for these pollutants strikes an appropriate
balance between minimizing the burden on reporters and obtaining valuable GHG emission data.
EPA has, however, revised the final rule to exclude CH4 and N2O emissions from fuels for
which the rule does not provide emission factors, and has deleted the provision allowing the
owner or operator of a facility to develop site-specific emission factors for such fuels. EPA
believes that this change will reduce the reporting burden on facilities.
The Agency has clarified the requirements to report under Tier 4, and has made several changes
to reporting dates, extensions, and exceptions, that may indirectly address these concerns. While
EPA does not find the methodologies for calculating CH4 and N20 emissions burdensome, EPA
has clarified them in the final rule. When more than one type of fuel is combusted in a unit,
direct measurements or engineering estimates of the annual heat input from each fuel are needed
to calculate the CH4 and N2O emissions. Consequently, when CEMS (which are not fuel-
specific) are used to monitor the CO2 emissions and heat input for a multi-fuel unit, the total heat
input measured by the CEMS must be apportioned to each fuel type. The owner or operator
should use the best available information (e.g., fuel feed rates, GCV values, etc.) to do the
necessary heat input apportionment.
Commenter Name: Keith A. Nagel
Commenter Affiliation: ArcelorMittal USA and Severstal North America
Document Control Number: EPA-HQ-OAR-2008-0508-0496.1
Comment Excerpt Number: 23
Comment: In lieu of the expensive testing for Tier 3, we are evaluating the potential to measure
CO2 emissions from the combustion of coke oven gas in an on-site gas chromatograph or other
continuous monitoring device which could determine CO2 emissions from a thermally oxidized
sample. That approach would allow for direct measurement of the amount of CO2 actually
generated by combustion of the process gas. The resulting CO2 generation factor could then be
multiplied by the amount of coke oven gas combusted to generate total CO2 emissions
information. This direct combustion approach would be more accurate than the Proposed Rule's
Tier 3 methodology because it would directly measure the actual amount of CO2 generated when
coke oven gas is combusted. In contrast, the Tier 3 approach would rely on a sampling estimate
of the amount of carbon and the presumption that 100% of that carbon will become CO2. The
sample combustion approach under evaluation would also be more accurate because it would
219
-------
allow for sampling of the coke oven gas stream on a more frequent basis. That more frequent
data would allow for adjustments based on the modest fluctuations that continuously occur in
coke oven gas composition. This approach could be modeled on currently required TRS
continuous monitors. Similar alternatives are potentially viable for blast furnace gas
measurement. For example, steel plants may wish to use sampling data generated by the top gas
analyzers and mass spectrometers located at each blast furnace. These analyzers measure CO2
and CO very accurately in order to ensure efficient furnace operation. A simple formula that
conservatively presumes the combustion of blast furnace gas will convert all CO to CO2 could
be used to reliably convert that data to projected C02 emissions with greater accuracy than
available under Tier 3. To enable such improved methods, we request that the final rule
authorize operators to develop and use any alternate emissions methodology that provides equal
or greater accuracy than EPA's proposed approach.
Response: EPA's approach makes use of existing data and methodologies to the extent feasible,
and is consistent with the types of methods contained in other GHG reporting programs (e.g., the
California mandatory reporting rule, WCI, RGGI, TCR, and Climate Leaders). Because this
approach specifies methods for each source category, it will result in data that are comparable
across facilities. For consistency, EPA did not provide for alternative approaches as described
by the commenter. However, the commenter should note that in the final rule EPA has permitted
the use of chromatographic analysis to determine the carbon content and molecular weight of a
fuel. EPA believes that the availability of this additional option will reduce the burden on
reporters.
Commenter Name: Linda Farrington
Commenter Affiliation: Eli Lilly and Company (Lilly)
Document Control Number: EPA-HQ-OAR-2008-0508-0680.1
Comment Excerpt Number: 22
Comment: Lilly believes the use of fuel flow meters can generate a more accurate estimate of
the CO2 emissions than continuous emission monitoring, and they should be allowed for CO2
estimation even if CEMS are present. If we look at the combustion device as a unit operation,
the CO2 emissions can be estimated from measurement of the output or input streams. The
accuracy of the measurement devices on those inlet or outlet streams should drive that decision;
outlet CEMS are not inherently superior to inlet fuel monitoring. In addition, to avoid missing
data due to instrument or data collection downtime, the fuel flow meter is expected to provide a
more accurate measurement of the total flow over a range of operating conditions. The outlet
stack measurement depends on temperature, CO2 concentration, and volumetric flow. Each of
those has its own measurement uncertainty. The RATA performance specification requires that
the CEMS measurement be within +/- 20% of the EPA's reference test method. [Footnote: 40
CFR 60, Appendix B, Performance Specification 6 — Specifications and Test Procedures for
Continuous Emission Rate Monitoring Systems in Stationary Sources] By comparison, the fuel
flow meters recently installed on a typical Lilly boiler have an accuracy estimated at +/- 2%.
Affected facilities should have the flexibility to use instrumentation that provides more accuracy,
reduced downtime, and reduced operating costs.
220
-------
Response: See the response to comment EPA-HQ-OAR-2008-0508-0455.1 excerpt 7 and the
response to comment EPA-HQ-OAR-2008-0508-0580 excerpt 10 for EPA's rationale and
approach to the use of CEMS.
EPA has revised §98.33(b)(4)(ii) of the final rule to clarify that all six criteria specified in
subparagraphs (A) through (F) must be met before Tier 4 is required. The Tier 4 CEMS
requirement is limited to larger solid fossil fuel units with an existing pollutant CEMS or
volumetric flow rate monitor, or a source with an existing CO2 CEMS and flow rate monitor.
EPA is requiring the use of CEMS due to the complexity of monitoring solid fuel consumption
and the heterogeneous nature of the solid fuels. Units with fuel flow meters burning gaseous or
liquid fuels are not required to use Tier 4.
Commenter Name: Keith Adams
Commenter Affiliation: Air Products and Chemicals, Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-1142.1
Comment Excerpt Number: 22
Comment: The proposed rule imposes the Tier 4 calculation methodology on sources meeting
the conditions specified under §98.33(b)(5)(ii). As worded, it appears any one of the (A), (B),
(C), or (D) conditions would result in the Tier 4 method being required. This does not match the
intent expressed in the Preamble to the proposed rule, and summarized in Preamble table C-l. In
particular, Table C-l appears to indicate that Tier 4 is required only for Solid Fossil Fuel fired
units > 250 mmBTU/hr (meeting other criteria, as well) and that Gaseous Fossil Fuel fired and
Liquid Fossil Fuel fired combustion units are required to use no more rigorous than Tier 3
methods. The current language of §98.33(b)(5)(ii) would imply any of the conditions described
in §98.33(b)(5)(ii)(A), (B), (C) or (D) trigger the Tier 4 method requirement. We believe the
agency's intent is that all of the conditions described in §98.33(b)(5)(ii)(A), (B), (C) and (D) are
necessary in order to trigger the Tier 4 method requirement. §98.33(b)(5)(ii)(E) imposes the Tier
4 method if the source has any existing CEMS system. Depending on the type of gas monitoring
system a source may have (extractive vs. in-situ; wet vs. dry, etc.) the addition of a CO2 CEMS
can be a very costly modification. Modifications could include, assuming it is even technically
feasible, the addition of stack sampling ports, addition of extractive sampling systems, sample
conditioning systems, calibration gas systems and modification to data acquisition and reporting
systems and software. Based on our experience, these modifications can impose $40,000 to
$250,000 of capital costs, as well as ongoing maintenance and operating costs for such units.
These costs may be imposed on the false premise that direct emission measurement via CEMS is
an inherently more accurate than alternative calculation methods (e.g. Tiers 1, 2, or 3). Clarify
the requirement to employ the Tier 4 calculation method. Resolve the apparent discrepancy
between the intent to limit Tier 4 to only Solid Fossil Fuel fired combustion units, per Table C-l
of the Preamble, with the actual imposition of Tier 4 described under §98.33(b)(5)(ii). Clarify
that in order for Tier 4 to be required under §98.33(b)(5)(ii), all the conditions under
§98.33(b)(5)(ii)(A), (B), (C), and (D) must be met. Specifically, conditions (A), (B), (C), and
(D) should be separated by the word "and" - absent that, an implied "or" would force this
calculation method on many other combustion units for which it was not intended. Do not
require the use of the Tier 4 method where alternative fuel consumption data is available. Tier 1,
2, and 3 offer viable alternatives for many combustion sources that will yield comparable (and in
many cases more) accurate emission estimates. Allow optional use of the Tier 4 method where,
221
-------
at the source's discretion. This may be a suitable calculation method where a source uses
multiple fuels and/or non-commercial fuels or where existing CEMS systems include CO2
measurement or can be modified at lower cost than alternative fuel consumption and/or
characterization devices/practices. In any case, let the regulated source determine which method
is most cost effective for their particular situation.
Response: EPA acknowledges the commenter's concerns regarding Tier 4 applicability. EPA
has revised §98.33(b)(4)(ii) of the final rule to clarify that all six criteria specified in
subparagraphs (A) through (F) must be met before Tier 4 is required. However, EPA disagrees
with suggestions that Tier 4 should only be required if the installed CEMS include a CO2
monitor. EPA is requiring the use of CEMS due to the complexity of monitoring solid fuel
consumption and the heterogeneous nature of the solid fuels. Many of these fossil fuel-fired
units with a pollutant CEMS have an existing diluent monitor (02 or C02) that can be used to
determine CO2 emissions. The incremental cost of adding a monitor to meet Tier 4 monitoring
requirements is not unduly burdensome for a unit that is already required to install, certify,
maintain, and operate a CEMS or flow rate monitor, and to perform ongoing Q A testing of the
existing monitors. EPA's estimates of monitoring costs are averages for a representative facility
and may not represent the actual cost in individual circumstances.
Commenter Name: Keith Adams
Commenter Affiliation: Air Products and Chemicals, Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-1142.1
Comment Excerpt Number: 21
Comment: The proposed rule defines the applicability of the alternate calculation method
"tiers" based on combustion unit size and availability of data, with a general trend to require
more rigorous calculation methods (e.g. increasing from Tier 1 to Tiers 2, 3, and 4) for higher
operating capacity units and facilities that currently employ certain process or emission
measurements. This push for more rigorous calculation methods is made without regard for a)
the underlying accuracy of the calculation method, b) the quality and completeness of existing
process or emission measurement, or the cost of the necessary measurement equipment or
practice. The result is a rule that often requires a costly, laborious measurement/calculation
method that does not improve the accuracy or completeness of the emission estimate. In many
instances, less rigorous calculation methods (e.g. "lower" Tiers) will yield comparable (or better)
accuracy emission estimates, with higher reliability and at lower cost. There is an implied
assumption that directly measured emissions will yield a better emission estimate. This
presumption is not true, as evidenced by an acceptable level of (in)accuracy tolerance under
CEMS certification/calibration procedures (> 5-7%) versus levels of fuel consumption metering
employed for invoice billing (typically < 2%). Air Products Comment: EPA should be more
flexible as it relates to the applicability to the alternate combustion emission calculation methods.
In particular: 1. Allow use of the Tier 1 method for units of any size (currently restricted to units
< 250 mmBTU/hr or less), particularly for standard fuels of commerce such as natural gas, LP
gas and fuel oils, where billing-quality consumption data is accurate and readily available and
the default HHV and CO2 emission factors are well known constants (as noted in the Preamble
for the proposed rule - natural gas carbon content is always within 1% of the default ratio). 2.
Recognize that a source's current practices of occasionally characterizing fuels for HHV or
carbon content does not necessarily constitute having data "available" consistent with the
222
-------
compliance expectations of Tiers 2 and 3. Where Tiers 2 or 3 would be required, existing fuel
characterization may not be according to the specified analytical methods or at the required
frequency. Do not require Tier 2 or 3 where data fully meeting the defined compliance
expectation is not currently being obtained. 3. Do not require the use of the Tier 4 method where
alternative fuel consumption data is available; allow optional use of the Tier 4 method at the
source's discretion. This may be a suitable calculation method where a source uses multiple
fuels and/or non-commercial fuels or where existing CEMS systems include C02 measurement
or can be modified at lower cost than alternative fuel consumption and/or characterization
devices/practices. In any case, let the regulated source determine which method is most cost
effective for their particular situation. This option is available in California's GHG mandatory
reporting program.
Response: See the Preamble, Section II. L., on General Monitoring Requirements for the overall
rationale for methodologies required under this rule, and the response to comment EPA-HQ-
OAR-2008-0508-0909.1 excerpt 4 and EPA-HQ-OAR-2008-0508-0580 excerpt 10 for the
rationale for methodologies required under Subpart C, and EPA-HQ-OAR-2008-0508-0695.1
excerpt 18 for additional information on rationale for CEMS.
EPA has, however, expanded the use of the Four Tier system to be more significantly more
flexible. EPA has significantly expanded the use of the Tier 2 Calculation Methodology for units
in which the only fossil fuels combusted are natural gas and/or distillate oil, in view of the
homogeneous nature of these fuels. However, the Tier 3 methodology is still required for large
250 mmBtu/hr units that combust other fossil fuels.
EPA believes that it is clear in the final rule that a unit which otherwise qualifies to use Tier 1
will not be required to use Tier 2 unless the owner or operator routinely performs fuel sampling
and analysis for the fuel high heat value, or routinely receives the results of HHV sampling and
analysis from the fuel supplier at the minimum frequency specified in §98.34.
Additionally, units required have the flexibility in some circumstances to use company records
and supplier information for obtaining HHV and fuel quantity.
EPA acknowledges the commenter's concerns regarding Tier 4 applicability. EPA has revised
§98.33(b)(4)(ii) of the final rule to clarify that all six criteria specified in subparagraphs (A)
through (F) must be met before Tier 4 is required. However, EPA disagrees with suggestions
that Tier 4 should only be required if the installed CEMS include a CO2 monitor, or not be
required if alternative fuel records are available. EPA is requiring the use of CEMS due to the
complexity of monitoring solid fuel consumption and the heterogeneous nature of the solid fuels.
Many of these fossil fuel-fired units with a pollutant CEMS have an existing diluent monitor (O2
or CO2) that can be used to determine CO2 emissions. The incremental cost of adding a to
monitor meet Tier 4 monitoring requirements is not unduly burdensome for a large unit that
combusts solid fossil fuels, and is already required to install, certify, maintain, and operate a
CEMS or flow rate monitor, and to perform ongoing QA testing of the existing monitors.
223
-------
Commenter Name: Leslie Bellas
Commenter Affiliation: National Lime Association (NLA)
Document Control Number: EPA-HQ-OAR-2008-0508-0520.1
Comment Excerpt Number: 20
Comment: Sources Should Be Permitted to Apply Different Tiers to Each Fuel Type
Combusted in a Unit (40 C.F.R. §98.33(b)). 40 C.F.R. §98.33(b) indicates that units combusting
multiple fuel types (e.g., burning coal and natural gas in the same kiln) could be required to use
two different emission calculation methodologies (tiers) in order to calculate stationary fuel
combustion. NLA requests confirmation of a statement made by EPA staff during a May 14
conference call that it is permissible to use multiple tiers for each fuel type combusted by a
single unit.
Response: In response to comments, EPA has added language to the final rule to clarify the use
of tiers. Section 98.33(b)(6) of the final rule explains that different tiers may be used for
different fuels in the same unit, unless the use of Tier 4 is required or elected.
Commenter Name: Filipa Rio
Commenter Affiliation: Alliance of Automobile Manufacturers (Alliance)
Document Control Number: EPA-HQ-OAR-2008-0508-0630.1
Comment Excerpt Number: 19
Comment: The proposed four-tiered approach to estimating GHG emissions from fuel
combustion units appears to provide appropriate emission calculation methodologies that serve a
broad range of fuel combustion sources. The methodologies also appear consistent with many
existing reporting programs. Additionally, the allowance of alternative reporting approaches for
aggregating small combustion units, units sharing a common stack, or units served by a common
supply line also serves to reduce the reporting burden while maintaining an equally high quality
of data. The Alliance supports inclusion of these concepts in a final rule.
Response: EPA appreciates this comment, and believes that the final rule includes further
clarification and flexibility regarding aggregation and common pipe provisions that will reduce
the burden on sources. The cumulative 250 mmBtu/hr heat input capacity limit on the
aggregation of units into a group has been dropped. Rather, the 250 mmBtu/hr restriction applies
only to the individual units in the group. Therefore, for reporting purposes, individual units with
maximum rated heat input capacities of 250 mmBtu/hr or less may be aggregated without limit
into a single group, provided that the Tier 4 methodology is not required for any of the units, and
all units in the group use the same tier for any common fuel(s) that they combust. Units with
maximum rated heat inputs greater than 250 mmBtu/hr must report as individual units, unless
they burn the same type of fuel (oil or gas) provided by a common pipe or supply line; case, the
owner or operator may opt to use the common pipe reporting provisions in §98.36(c)(3). Units
using Tier 4 must report as individual units unless they share a monitored common stack or duct;
in that case, the common stack or duct reporting provisions of §98.36(c)(2) may be used.
224
-------
Commenter Name: Leslie Bellas
Commenter Affiliation: National Lime Association (NLA)
Document Control Number: EPA-HQ-OAR-2008-0508-0520.1
Comment Excerpt Number: 18
Comment: The four-tier approach for calculating C02 combustion emissions is based on unit
size and fuel type. The Proposed Rule should clarify how the maximum rated heat input
capacity of a unit is determined and how tiers may apply to a single unit. Based on our review of
40 C.F.R. §98.3 3(b), use of the tiers is dependent, in part, on the maximum rated heat input
capacity of a unit. 40 C.F.R. §98.6 provides that the "maximum rated heat input capacity" is
determined as of the date of initial installation of the unit, as specified by the manufacturer.
NLA requests confirmation that the maximum rated heat input capacity is equal to the original
design and/or nameplate capacity of the unit so that the regulated community knows how the
maximum rated heat input capacity is determined. If the maximum rated heat input capacity of
the unit is the same as "design" or "nameplate" capacity of the unit, then NLA has no comment
on the requirement in 40 C.F.R. §98.36(b)(3) to report that value to EPA. However, if sources
are required to report the actual maximum rated heat input capacity of the kilns, NLA objects to
providing that information because it provides information about the existing capability of the
kilns to produce lime. NLA proposes that in accordance with 40 C.F.R. §98.37, any information
regarding the actual maximum rated heat input capacity of the unit be retained in company
records and made available for review upon request by EPA.
Response: EPA believes that the definition of "maximum rated heat input capacity" in §98.6
clarifies that this term refers to "the hourly heat input to a unit (in mmBtu/hr), when it combusts
the maximum amount of fuel per hour that it is capable of combusting on a steady state basis, as
of the initial installation of the unit, as specified by the manufacturer." This is consistent with
the commenter's interpretation.
Commenter Name: Dan F. Hunter
Commenter Affiliation: ConocoPhillips Company
Document Control Number: EPA-HQ-OAR-2008-0508-0515.1
Comment Excerpt Number: 26
Comment: Table C-l: ConocoPhillips believes it would be useful and burden-reducing if EPA
supplied an emission factor and default HHV for used oil combustion. Units that burn used oil,
at least in the case of our Alaska operations, are very small and do not warrant the rigor of Tier 3
or 4 emission estimation methods.
Response: EPA has not provided default values for used oil in Table C-l because the carbon
content of used oil varies greatly and little data is available on which to support a credible default
value. Had the commenter indicated published values then EPA would have been able to
consider them for inclusion. However, the commenter should consult the revised Table C-l, as
factors are provided for many other petroleum products, which may be applicable to used oil.
Furthermore, EPA has revised the rule so that most units with a maximum rated heat input
capacity less than 250 mmBtu/hr combusting fuels not listed in Table C-l will not be required to
report emissions from those fuels.
225
-------
Commenter Name: Ram K. Singhal
Commenter Affiliation: Rubber Manufacturers Association (RMA)
Document Control Number: EPA-HQ-OAR-2008-0508-0600
Comment Excerpt Number: 15
Comment: As EPA's view is that emission factors for fuel combustion are far more accurate
than direct measurements of GHGs exiting stacks as part of a combined train of exhausted
emissions, we not only do not believe direct emissions measurements are necessary, but disagree
that they are preferable. In addition, because of the cost and disruption caused by the installation
and maintenance of emission measurements, or even performance testing on a regular basis, we
think that the ambiguity in the proposal about when such methods will be required is
unreasonable and profoundly unwise, particularly in comparison to how sound information on
other pollutants is collected. We further object to the absence of a basis for calibration plans and
for QA/QC plans for collecting GHG emissions data.
Response: See the response to comment EPA-HQ-OAR-2008-0508-0455.1 excerpt 7 and the
response to comment EPA-HQ-OAR-2008-0508-0580 excerpt 10 for EPA's rationale and
approach to the use of CEMS.
EPA does not have the view that emission factors for fuel combustion are far more accurate than
direct measurements of GHGs existing the stacks.
EPA acknowledges the commenter's concerns about possible ambiguity regarding Tier 4
applicability. EPA has revised §98.33(b)(4)(ii) of the final rule to clarify that all six criteria
specified in subparagraphs (A) through (F) must be met before Tier 4 is required.
EPA is requiring the use of CEMS due to the complexity of monitoring solid fuel consumption
and the heterogeneous nature of the solid fuels. Many of these fossil fuel-fired units with a
pollutant CEMS have an existing diluent monitor (O2 or CO2) that can be used to determine CO2
emissions. The incremental cost of adding a monitor to meet Tier 4 monitoring requirements is
not unduly burdensome for a large unit that combusts solid fossil fuels, and is already required to
install, certify, maintain, and operate a CEMS or flow rate monitor, and to perform ongoing QA
testing of the existing monitors.
See the Preamble, Section II. M., for the response on the general recordkeeping requirements.
EPA believes that the ongoing QA requirements for fuel flow meters are essential to ensure the
quality of the emissions data reported and has specified these as part of the Monitoring Plan.
226
-------
Commenter Name: Dan F. Hunter
Commenter Affiliation: ConocoPhillips Company
Document Control Number: EPA-HQ-OAR-2008-0508-0515.1
Comment Excerpt Number: 27
Comment: Table C-3: CH4 and N20 factors are not defined, but should be added, for the
following fuel types currently listed in §98.38, Table C-l: 1. Ethane; 2. Biogas; 3. Isobutane; 4.
n-Butane; 5. Natural Gasoline; 6. Other Oil (> 401 def. F); 7. Pentanes Plus; 8. Petrochemical
Feedstocks; 9. Special Naphtha; and 10. Unfinished Oils.
Response: In response to the comment, EPA has extensively revised the default emission
factors used to calculate CH4 and N20 emissions, adding generic fuel-based emission factors
covering all fuels listed in Table C-l. For example, many of the fuels mentioned by the
commenter are covered by the CH4 and N20 emission factors for "Petroleum" in Table C-2.
EPA has clarified in the final rule that only CH4 and N20 emissions from combustion of those
fuels listed in Table C-2 of Subpart C are required to be reported.
Commenter Name: Claire Olson
Commenter Affiliation: Basin Electric Power Cooperative
Document Control Number: EPA-HQ-OAR-2008-0508-0637.1
Comment Excerpt Number: 14
Comment: EPA has suggested frequent analysis for fuels, varying by the type of fuel. Since
many of the facilities have consistent feedstocks, a full analysis of the feedstock or fuel on a
daily basis creates an added expense that does not improve the accuracy of the reporting. Basin
Electric urges EPA to allow flexibility to the facilities in the frequency and complexity of the
fuel analysis that is commensurate with the variability of the feedstock and its relative impact on
the accuracy of the GHG reporting. For example, with coal-fired facilities occasional ultimate
analyses provides the information required for a full carbon balance, and this can be coupled
with more frequent proximate analyses to provide assurance that the quality variation is within
reasonable tolerance of what is considered typical fuel.
Response: The mandatory fuel sampling and analysis requirements for Tiers 2 and 3 have been
considerably revised. §98.34 of the final rule requires that natural gas be sampled semiannually.
For other fuels such as oil and coal, which are delivered in shipments or lots, requiring monthly
sampling may be impractical. For fuel oil and coal, a representative sampling is required for
each fuel lot, i.e., for each shipment or delivery. For other liquid fuels and biogas, quarterly
sampling is required. For other solid fuels, excluding municipal solid waste, weekly composite
sampling with monthly analysis is required. For other gaseous fuels, the daily sampling
requirement has been retained, but only for facilities with existing equipment in place that is
capable of providing the data. Otherwise, weekly sampling is required.
227
-------
Commenter Name: See Table 10
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0635
Comment Excerpt Number: 52
Comment: EPA's approach with regard to CH4 and N20 departs entirely from direct
measurement. For these two gases, EPA instead proposes to use "EPA-provided default
emission factors and annual heat input values" - which are generally among the least accurate
emission calculation methods. We do not support this approach. While it is true that CH4 and
N20 are relatively minor considerations in this source category, they should still be measured
with a reasonable degree of accuracy. We recommend that EPA, at a minimum, require
"periodic stack testing to derive site-specific emission factors for CH4 and N20," as it suggests
in the Preamble. Such testing, incorporated into improved emissions factors, will catch any
surprisingly large emissions sources and will improve the accuracy of the monitoring system as a
whole. Accurately characterizing N20 emissions will be particularly important for fluidized bed
coal plants. As EPA explains in AP-42: Formation of N20 during the combustion process is
governed by a complex series of reactions and its formation is dependent upon many factors.
Formation of N20 is minimized when combustion temperatures are kept high (above 1575 °F)
and excess air is kept to a minimum (less than 1 percent). N20 emissions for coal combustion
are not significant except for fluidized bed combustion (FBC), where the emissions are typically
two orders of magnitude higher than all other types of coal firing due to areas of low temperature
combustion in the fuel bed. [FOOTNOTE: AP-42 at 1.1-5 - 1.1-6.] The National Coal Council
has similarly explained: N20 has a GWP 296 times that of C02. Because of its long lifetime
(about 120 years) it can reach the upper atmosphere, depleting the concentration of stratospheric
ozone, an important filter of UV radiation. N20 is emitted from fluidized bed coal combustion;
global emissions from FBC units are 0.2 Mt/year, representing approximately 2% of total known
sources. N20 emissions from [pulverized coal] units are much lower. Typical N20 emissions
from FBC units are in the range of 40-70 ppm (at 3% 02). This is significant because at 60 ppm,
the N20 emission from the FBC is equivalent to 1.8% C02, an increase of about 15% in C02
emissions for an FBC boiler. Several techniques have been proposed to control N20 emissions
from FBC boilers, but additional research is necessary to develop economically and
commercially attractive systems. [FOOTNOTE: 309 National Coal Council, Coal-Related
Greenhouse Gas Management Issues (May 2003) at 7 (Ex 49)] In light of these unusually high
emissions, we recommend that EPA require CEMS for plants of this type. If it does not, it
should at least apply facility-specific emissions factors.
Response: See the response to comment EPA-HQ-OAR-2008-0508-0561.1 excerpt 2 for
information on EPA's approach to CH4 and N20 emissions from stationary combustion. As
stated in the proposed rule, in seeking a balance between accuracy of reporting information,
burden to reporters, and size of emissions source, EPA decided that the direct measurement
option (CEMS or source test to develop source specific emission factors) was too costly for the
small improvements in data quality that it might achieve. The CH4 and N20 emissions from
stationary combustion are relatively low compared to the C02 emissions. EPA believes using
fuel-specific default emission factors to calculate CH4 and N20 emissions is in accordance with
methods used in other programs and provides data of sufficient accuracy.
EPA disagrees that CEMS should be required. As in the proposed rule, a CEMS methodology
was not selected for measuring N20 primarily because the cost impacts of requiring the
228
-------
installation of CEMS is high in comparison to the relatively low amount of N20 emissions (even
on a CC^e basis) that would be emitted from stationary combustion equipment.
Commenter Name: Rich Raiders
Commenter Affiliation: Arkema Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-0511.1
Comment Excerpt Number: 51
Comment: Arkema operates a material recovery operation at one facility where the facility uses
an alumina regeneration system to condition process fluids and roasts the spent alumina onsite
for recycling. This natural gas combustion activity would be included in Subpart C applicability,
but the process is not included in any other Part 98 subpart. The alumina is placed into the
roaster system as a solid exhibiting an organic coating. As the alumina progresses through the
heated rotating drum system, the organic materials evolve from the alumina, so that when the
alumina is clean when removed from the roaster system. As a consequence of roasting, organic
materials on the alumina surface are evolved from the alumina, where some of the materials may
coincidentally combust as the alumina is heated at or near the autoignition temperature of some
of the constituents. The natural gas combustion vent and roasting vent are discharged through
separate vent systems. The C02 generation from the organic evolution phase of the roasting
process represents a small fraction of the total roasting CO2 emissions, far less than the
comparable fuels-based minimum heat input value described above. EPA does not include any
case-by-case determination method for Subpart C reporters to determine or calculate GHG
emissions from this type of activity, or exclude consideration of the secondary material's
minimal fuel value that does not contribute significant heat value to the underlying combustion
activity. EPA should provide a calculation method where the reporter could measure the total
organic content of a material being roasted, determine if the material contributes significant heat
value per the comparable fuel definition, calculate GHG emissions from material evolution if
required, add any GHG emissions to the total fuel combustion emissions reported under Subpart
C if necessary, and file any annual reporting for the stream. Arkema is concerned that a GHG
reporting rule could, because of the difficulties in complying with the proposed Part 98, cause
the company to dispose of several tons of solid waste per week, rather than manage the
insignificant amounts of GHG emissions evolving from the roasting alumina. The only
compliance option that might be feasible in the current Subpart C would be placing the natural
gas portion of the roaster, from where most of the GHGs are emitted, into a Tier 1 or 2 system,
and the roaster process exhaust system, where very little GHG are actually emitted, into Tier 4
where a continuous emission monitor ("CEM") system would be required. Were Arkema forced
to cease roasting as an economic decision for Part 98 compliance, the solid waste disposal costs
and associated burden with unnecessarily consuming natural resources that are better left in a
recycling system should be part of EPA's cost considerations. EPA could not have intended for
facilities roasting materials for recycling to cease recycling activities and/or investing in CEM
systems for trivial GHG emission streams. Arkema has advocated in several portions of this
comment document for a case-by-case determination system to address unusual situations like
this, where the facility can propose a compliance option that balances the EPA need for
reasonably accurate GHG emissions data and the cost of compliance for each individual process.
Response: EPA has added language to §98.33 clarifying and revising the use of the four tiers. It
is not EPA's intent to require Tier 4 methods to calculate emissions from this type of process.
229
-------
Tier 4 is only required when the unit meets all of the criteria listed in §98.33(b)(4)(ii) or (iii).
Tier 3 is only required to calculate emissions for a fuel for which emission factors are not
provided when Tier 4 is not required, the fuel is not exempted from reporting in §98.30, and the
unconventional fuels provide, on average, at least ten percent of the annual heat input to an
individual unit with a maximum rated heat input capacity greater than 250 mmBtu/hr or group of
units served by a common supply pipe. Most units with a maximum rated heat input capacity
less than 250 mmBtu/hr may report using Tier 1 or Tier 2, and according to the final rule will not
be required to report emissions from fuels for which default values are not provided. Therefore,
in this case it appears that only the emissions from the combustion of natural gas in the unit
would need to be reported because there are no default emission factors for organic materials on
the alumina surface.
Commenter Name: Rich Raiders
Commenter Affiliation: Arkema Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-0511.1
Comment Excerpt Number: 49
Comment: Thermal oxidizers are used to control emissions of a variety of processes, dispose of
non-hazardous wastes, pre-heat process fluids, and heat or boil water. These devices combust a
variety of materials, but typically burn natural gas as the primary or pilot fuel. Facilities
operating thermal oxidizers are normally required to document the amount of material routed to
the device, the device destruction efficiency, and the amount of fuel used in the device. In the
proposed Subpart C, thermal oxidizers seem to fall into the Tier 3 requirements, where operators
are required to measure heat input, molecular weight, and carbon content on a daily basis. Many
thermal oxidizer systems are installed on existing systems that were retrofitted from designs
which are years or decades old. As such, many of these systems are not designed with any valid
location to measure the parameters required by the proposed Tier 3 requirements. For example,
one Arkema thermal oxidizer system collects vapors from three separate headers that are only
combined at the thermal oxidizer. EPA has published existing standards for appropriate
sampling and measurement locations (40 CFR 60, Appendix A, Method 1) that cannot be
achieved in many thermal oxidizer systems without the operator incurring millions in dollars to
retrofit the device to accommodate instrument sampling. Although Arkema cannot provide an
industry-wide estimate of how many combustion devices would not readily accommodate
appropriate stream sampling, the company suggests that many similar devices, where the only
required parametric monitoring consists of firebox temperature monitoring, exist in the field that
would require expensive retrofits to obtain valid heat value, carbon content, and molecular
weight determinations. EPA should provide a Tier 3 alternate allowing facilities that can
calculate the appropriate Tier 3 parameters in lieu of sampling when the facility has the ability to
calculate combustion device loadings. This option should only be required when the heat load
from the thermal oxidizer load meets the comparable fuels minimum heat input contribution
described above. EPA should allow facilities required to comply with existing CAA provisions
that require combustion device inlet loading determinations to calculate combustion device
loadings on a periodic basis. Another complication concerning carbon content and molecular
weight measurement is that many compounds routed to many emission control devices are not
properly measured by the same instrument set. EPA has published regulations that require that
monitoring instruments that measure organic chemical concentrations must be able to detect the
organic compounds being measured within an order of magnitude of standard instrument
230
-------
concentrations, or the complying facility must change instruments to provide an instrument that
can adequately quantify the stream in question. This situation often emerges in vent streams
containing halogens (fluorine, chlorine, bromine, iodide), sulfur, nitrogen, and other similar
anions. Arkema operates systems where two gas chromatograph systems are required to measure
various organic compounds within a single facility to accommodate the different molecules that
must be measured to demonstrate compliance. Facilities operating control devices, where the
waste gas stream contributes significant heat value that can calculate combustion device loadings
without use of instruments should be provided a calculated combustion device loading in
proposed Subpart C. The heating value calculations, which already exist in Title V permit basis
calculations, would allow facilities that would need to expend significant funds retrofitting
existing ductwork configurations to avoid unnecessary expenditures that do not increase
reporting accuracy.
Response: See the Preamble, Section III. C., for the response on the definition of the source
category.
EPA has revised §98.33 to deal with certain unconventional combustion processes and types of
fuel. In the Preamble, EPA has explained that "devices such as thermal oxidizers and pollution
control devices . . . would report only the GHG emissions from the firing of supplemental fossil
fuels." EPA believes that these provisions satisfy the intent of Part 98, to collect accurate and
consistent GHG emissions data that can be used to inform future decisions.
Commenter Name: Gregory A. Wilkins
Commenter Affiliation: Marathon Oil Corporation
Document Control Number: EPA-HQ-OAR-2008-0508-0712.1
Comment Excerpt Number: 48
Comment: Marathon supports not requiring stack test data to derive site specific emission
factors for CH4 and N2O emissions. EPA considered this approach to estimate CH4 and N2O
emissions. This would have been costly with little benefit. Marathon supports the use of fuel-
specific default emission factors if these emissions are not excluded entirely.
Response: EPA appreciates the supportive feedback, and has maintained these specifications in
the final rule. EPA has also revised the rule so that only CH4 and N2O emissions from those
fuels listed in Table C-2 of Subpart C are required to be reported.
Commenter Name: Gregory A. Wilkins
Commenter Affiliation: Marathon Oil Corporation
Document Control Number: EPA-HQ-OAR-2008-0508-0712.1
Comment Excerpt Number: 47
Comment: Marathon opposes the sampling requirements under the Tier 3 methodology.
Marathon would be forced into this tier for refinery fuel gas combustion because there is no
emission factor for refinery fuel gas given by EPA. This tier would require daily sampling of
carbon content of the fuel gas. Marathon proposes that EPA allow the option of using an
231
-------
industry derived emission factor or a facility specific derived emission factor if it is determined
that fuel gas samples are consistent over a period of time. If mandatory sampling is required,
Marathon proposes that the sampling frequency is lessened as the fuel gas characteristics have
limited variability. For this frequency, Marathon proposes monthly or weekly sampling of fuel
gas. These requirements would reduce burden and cost on collecting the samples, the associated
QA/QC, and the current reporting requirements while still giving accurate estimation of
emissions. It is not cost effective for the benefit received to require daily sampling of refinery
fuel gas.
Response: EPA believes that the Tier 3 methodology is appropriate for units larger than 250
mmBtu/hr combusting refinery gas, due to its potential variability. For gaseous fuels other than
natural gas or biogas, the daily sampling requirement has been retained, but only for facilities
with existing equipment in place that is capable of providing the data. Otherwise, weekly
sampling is required. The commenter should note that EPA has provided a default emission
factor and HHV for refinery gas, which will allow smaller sources combusting refinery gas to
use Tier 1 or Tier 2.
Commenter Name: Gregory A. Wilkins
Commenter Affiliation: Marathon Oil Corporation
Document Control Number: EPA-HQ-OAR-2008-0508-0712.1
Comment Excerpt Number: 46
Comment: Marathon interprets that the use of Tier 4 methodology (use of CEMs) only apply to
large stationary combustion units that are fired with solid fuels and that have existing CEMs.
Tier 4 methodology is not and should not be required if a facility has a CEM but does not
combust solid fossil fuel or does not have a CO, monitor on the CEM. Additionally, the
Preamble states that an upgrade would be required if a CO2 monitor or an O2 monitor was not
present or if a flow meter was not installed. Marathon interprets this to mean that these upgrades
would only be required for the CEMs if solid fossil fuel was being combusted. Also, Marathon
interprets the Preamble language on page74 FR 16483 to mean that CEMs currently installed
would not be required to monitor other types of fuel (besides solid fossil fuel) combusted but
could be used if chosen by the facility. If a facility has a CEM but does not combust solid fossil
fuel and does not have a CO2 monitor on the CEM, they should not be required to install a CO2
monitor and use Tier 4 reporting. Marathon requests that this clarification be made in section
98.33(b)(5) by adding "and" after each defining statement for Tier 4 use.
Response: EPA acknowledges the commenter's concerns regarding Tier 4 applicability. EPA
has revised §98.33(b)(4)(ii) of the final rule to clarify that all six criteria specified in
subparagraphs (A) through (F) must be met before Tier 4 is required. Therefore a source that
does not burn a solid fuel is not required to meet Tier 4.
232
-------
Commenter Name: Rich Raiders
Commenter Affiliation: Arkema Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-0511.1
Comment Excerpt Number: 43
Comment: EPA should also encourage facilities to not modify combustion units to adjust the
balance between CO2 and carbon monoxide ("CO"), or the balance between CO2 and oxides of
nitrogen ("NOx") in individual combustion units subject to Subpart C. Although GHG reporting
may identify combustion improvement opportunities at some locations, Part 98 should not be
used to cause facilities to modify combustion practices that are tuned to comply with other CAA
regulatory requirements.
Response: In response to the comment, EPA does not believe that any additional language is
needed to encourage facilities not to modify their combustion practices. Because the rule
focuses solely on reporting GHG emissions, it is not appropriate for it to comment on GHG
reduction strategies.
Commenter Name: Rich Raiders
Commenter Affiliation: Arkema Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-0511.1
Comment Excerpt Number: 42
Comment: At least one Arkema facility uses combined gas metering to track combusted
pipeline fuel entering several similar combustion systems, including one system using pressure
swing adsorption ("PSA") to remove the non-methane fraction from pipeline natural gas. EPA
should allow facilities using centralized pipeline fuel metering systems, but distributing the fuel
to a number of combustion devices, to report GHG emissions based on the combined stream.
Further, facilities should be allowed to use process knowledge and design specifications to
determine the heating value and composition of the pipeline-origin commodity fuels, rather than
requiring fuel composition determination on each stream reaching each individual combustion
device.
Response: Under the proposed and revised rule, a facility may calculate GHG emissions for a
group of units (rather than unit-by-unit emissions) when the same liquid or gaseous fuel is used
by each unit and is fed by a metered common pipe (e.g., a natural gas meter at the facility gate).
See the common pipe reporting provisions in §98.36. This flexibility is consistent with existing
protocols and methodologies allowed by EPA in existing programs.
EPA has made changes to the proposed rule to clarify that fuel sampling and analysis data
provided by the supplier may be used in the emission calculations as an alternative to
determining heating value and composition, and that fuel billing meters may be used to quantify
fuel consumption. EPA did not include the commenter's suggestion to allow process knowledge
and design specifications to determine heating value and composition of pipeline-origin
commodity fuels because this information would be very difficult to verify and is not expected to
be any more accurate than the alternatives provided. However, EPA has expanded the use of
Tier 2 Calculation Methodology to units of any size combusting only distillate oil and/or natural
233
-------
gas. EPA has revised the pipeline natural gas sampling frequency to require that natural gas be
sampled semiannually.
Commenter Name: Fiji George
Commenter Affiliation: El Paso Corporation
Document Control Number: EPA-HQ-OAR-2008-0508-0398.1
Comment Excerpt Number: 40
Comment: El Paso recommends allowing alternate Tier 2 calculations for homogeneous
gaseous fuels such as pipeline quality natural gas. The alternate Tier 2 would allow using fuel
carbon content instead of high heating value. For majority of natural gas transmission facilities,
the high heating value of the transported gas is not directly measured but rather calculated based
on gas composition. Therefore, our facilities can easily implement C02 emission calculations
based on carbon content. However, it is recommended that annual average carbon content could
be used in lieu of monthly fuel and carbon content data as explained above in order to minimize
reporting burden. This request is consistent with EPA's programmatic goals outlined in the
Preamble related to consistency with existing reporting programs and minimizing reporting
burden.
Response: The IPCC and the "Inventory of U.S. Greenhouse Gases and Sinks" do not use
carbon contents of mass or volume of fossil fuels rather than HHV because carbon content
typically varies less per HHV than it does for a given mass or volume. EPA has followed this
approach in Part 98. However, the commenter could use gas composition data to determine both
HHV and carbon content per unit HHV.
EPA has expanded the use of the Tier 2 Calculation Methodology to include units greater than
250 mmBtu/hr that combust only pipeline natural gas and/or distillate oil. However, these units
still have the option of using Tier 3 calculations, based on measured carbon content.
The mandatory fuel sampling and analysis requirements for Tiers 2 and 3 have been considerably
revised. Section 98.34 of the final rule requires that natural gas be sampled semiannually.
Commenter Name: Kelly R. Carmichael
Commenter Affiliation: NiSource
Document Control Number: EPA-HQ-OAR-2008-0508-1080.2
Comment Excerpt Number: 12
Comment: NiSource supports EPA's decision to not require CEMS methodology for measuring
CH4 and N2O emissions from Stationary Fuel Combustion Sources and, therefore, not requiring
installation of CEMS for that purpose. NiSource agrees with EPA that this option is too costly
for the small improvement in data quality that may be achieved instead of using the proposed
approach of using fuel-specific default emission factors.
Response: EPA appreciates the supportive feedback, and has maintained these specifications in
the final rule. EPA has also revised the rule so that only CH4 and N2O emissions from those
fuels listed in Table C-2 of Subpart C are required to be reported.
234
-------
Commenter Name: Michael DiMauro
Commenter Affiliation: Massachusetts Municipal Wholesale Electric Company (MMWEC)
Document Control Number: EPA-HQ-OAR-2008-0508-0580
Comment Excerpt Number: 16
Comment: For Units with a design heat input < 250 MMBtu/hr the Proposed Rule does not
allow use of Tier I monitoring procedures and calculation methods if fuel sampling and analysis
to determine the fuel high heat content is currently being performed on a monthly or more
frequent basis either on-site or by the supplier - see 98.33(b)(1). Such sources must conform
with Tier II monitoring procedures and calculation methods. For many dual (oil/gas) fuel units,
high heat (Btu/scf) values for natural gas are provided by the fuel supplier on a monthly basis,
but high heat (Btu/gal or Btu/lb) values for oil are only provided with each fuel shipment, and
such deliveries can occur much less frequently than monthly depending on the size of on-site oil
tanks and the frequency of oil firing. 1. The GHG Reporting rule should allow dual fuel units to
monitor CO2 emissions generated by each fuel type using different Tier schemes, if applicable.
It should not be required that the same Tier monitoring method (i.e. I or II) be used for all fuel
types fired by a stationary combustion unit. 2. The rule should clarify how to determine whether
the Tier II methodology is applicable to oil, for a dual fuel unit that receives oil deliveries
occasionally at non-periodic intervals (i.e. during some months, multiple deliveries may occur, in
other months no oil deliveries may occur). It is suggested that if sources that receive oil high
heat values from the fuel supplier with each oil shipment (delivery) are required to conform with
the Tier II methodology, then such units should be allowed to use fuel supplier values alone
(with no supplemental on-site sampling), even if the fuel supplier analysis data is received less
frequently than monthly.
Response: In response to comments, EPA has added language to the final rule to clarify the use
of tiers. Section 98.33(b)(6) of the final rule explains that different tiers may be used for
different fuels in the same unit, unless the use of Tier 4 is required or elected. Furthermore, in
response to comments, EPA has added flexibility to the use of the four tiers. In the final rule,
Tier 2 may be used to calculate emissions from a unit of any size that only combusts distillate
fuel oil and/or pipeline quality natural gas. EPA has also considerably revised the minimum
sampling frequencies that trigger, and are required for Tier 2. In the final rule, for example, Tier
2 is to be used for natural gas if it is sampled and analyzed semiannually, or more frequently, and
for fuel oil if at least one representative sample from each lot is analyzed. Furthermore, EPA has
clarified in the final rule that analysis data from fuel suppliers may be used in emissions
calculations. In this case it appears that Tier 2 would be used to calculate emissions from both
fuels combusted in the oil/gas unit.
235
-------
Commenter Name: J. P. Blackford
Commenter Affiliation: American Public Power Association (APPA)
Document Control Number: EPA-HQ-OAR-2008-0508-0661.1
Comment Excerpt Number: 2
Comment: APPA requests that EPA clarify the criteria that must be met for a utility to be
required to report its GHG emissions from electric generation using Tier 4 methodology
(§98.33(b)(5)(ii)). APPA is concerned that the proposed rule does not specify that all of the
criteria must be met in order for a utility to be required to report using Tier 4 methodology.
APPA believes that EPA intended this to be the case since in the "Information Sheet" for Subpart
C — General Stationary Fuel Combustion Sources has a flow chart on page 3 which implies that
all the conditions must be met. APPA requests that EPA specifically state that a utility must
meet all the conditions to be required to report under Tier 4 methodology, otherwise, they are
permitted to report under Tier 3 or lower, as appropriate. If this is not specifically stated and
future interpretation mandates that units that operate in excess of 1,000 hours and combust solid
fuel install CEMS, it will pose a significant challenge for APPA utility members. Some APPA
member utilities operate coal-fired units that are not required to install CEMS. These are
generally smaller units (on the order of 25 MW); therefore, the capital cost as well as the
operational cost of these CEMS for units of this size would be prohibitive. These costs would
have to be passed on to the community at a time when communities and its residents can least
afford them. The slight increase in accuracy gained by using CEMS as opposed to Tier 3
methodology would not justify the expenditures the utility would be required to make.
Response: EPA acknowledges the commenter's concerns regarding Tier 4 applicability. EPA
has revised §98.33(b)(4)(ii) of the final rule to clarify that all six criteria specified in
subparagraphs (A) through (F) must be met before Tier 4 is required.
Commenter Name: Lawrence W. Kavanagh
Commenter Affiliation: American Iron and Steel Institute (AISI)
Document Control Number: EPA-HQ-OAR-2008-0508-0695.1
Comment Excerpt Number: 13
Comment: Stove stacks are not typically equipped with the instrumentation necessary to
comply with Tier 3 methodology, and requirements to install such equipment are in conflict with
statements elsewhere in the rule that new monitoring equipment is not required. Moreover,
requirements for efficient and productive operation of blast furnaces dictate a very stable
operation, including stove heating practices. This means that the chemistry and heating value of
blast furnace gas and the resulting products of combustion at any given facility will be fairly
consistent over time. Accordingly, if reporting of blast furnace stove stack CO2 emissions is
retained in the final rule, we respectfully request that Tier 1 methodology apply. Total annual
CO2 emissions can be determined with sufficient certainty and accuracy by averaging routine
blast furnace gas carbon analyses or documented default values and estimated consumption rates.
Reporting of emissions associated with blast furnace stoves and blast furnace gas-fired boilers,
whether under Tier 1 or Tier 2, necessitates the addition of a blast furnace gas default value in
Table C-l or C-2.
236
-------
Response: See the Iron and Steel source category section of the Preamble and the source
category comment response document.
The commenter should note that EPA has added emission factors to Table C-l for both blast
furnace gas and coke oven gas. This will reduce the burden on sources by allowing units smaller
than 250 mmBtu/hr combusting these fuels to use Tier 1 or Tier 2. However, units larger than
250 mmBtu/hr combusting these fuels will be required to report using Tier 3, due to the fuels'
potential variability and the the size of the unit which makes it potentially larger source of
emissions. The commenter should note that the fuel sampling requirements have been reduced
to weekly for units combusting alternative gaseous fuels which do not have the equipment in
place for daily sampling.
Commenter Name: J. P. Blackford
Commenter Affiliation: American Public Power Association (APPA)
Document Control Number: EPA-HQ-OAR-2008-0508-0661.1
Comment Excerpt Number: 12
Comment: Methane (CH4) and nitrous oxide (N2O) make up a very small portion of total GHG
emissions from the combustion of fossil fuels. APPA supports simplified methodology for
calculating these emissions as the opportunity to enhance the accuracy of the total GHG
emissions in aggregate would not justify the additional effort required.
Response: EPA appreciates the supportive feedback, and has maintained these specifications in
the final rule. EPA has also revised the rule so that only CH4 and N2O emissions from those
fuels listed in Table C-2 of Subpart C are required to be reported.
Commenter Name: Lawrence W. Kavanagh
Commenter Affiliation: American Iron and Steel Institute (AISI)
Document Control Number: EPA-HQ-OAR-2008-0508-0695.1
Comment Excerpt Number: 12
Comment: The proposed rule requires the reporting of CO2 emissions from blast furnace stoves
under Subpart C. Blast furnace stoves are refractory-lined chambers that serve as heat
exchangers to heat the incoming blast air. The source of heat is the off-gas from the blast
furnace, which typically has a heating value of about 90 BTU/cubic foot. The blast furnace gas
contains both CO2 and CO, that when burned emits CO2. The original source of carbon in the
blast furnace gas is coke or other carbon-bearing fuels (e.g., natural gas, oil, or pulverized coal)
or raw materials (limestone, dolomite) that combine with the oxides in the iron ore or pellets.
About 25% of the blast furnace gas is used in the stoves, and CO2 is emitted as a product of
combustion from the stove stacks. (The remainder of blast furnace gas is typically used as a
boiler fuel to provide steam to drive the blast air turbines or to provide steam or electricity for
use elsewhere in the plant.) Because the amount of blast furnace gas consumed in stoves would
typically exceed 250 MMBTUH, Subpart C would require the use of Tier 2 or Tier 3 calculation
methodology. With respect to potential applicability of Tier 4 to blast furnace stove, see our
comments for coke oven combustion stacks regarding necessary clarifications to §98.33(b)(5).
237
-------
The C02 emissions associated with combustion of blast furnace gas are already accounted for
under reporting requirements of fuel suppliers. Although part of the CO and CO2 in blast
furnace gas could be attributed to limestone or dolomite fluxes, it is impossible to discern the
relative contribution of carbon contained blast furnace gas from coke or other reducing agents
versus that contained in the fluxes. Tier 2 relies on monthly measured heat values and default
emission factors (from Tables C-l or C-2), and the quantity of fuel combusted based on company
records. Tier 3 requires the use of monthly measurements for fuel carbon content, molecular
weight, and fuel quantities. However, we believe that both of these requirements are
unnecessary and believe that Tier 1 (based on annual emissions and default emission factors) is
an acceptable calculation methodology for the following reasons.
Response: See the Iron and Steel source category section of the Preamble and the source
category comment response document.
See the Preamble, Section II., for a discussion of upstream and downstream reporting.
The commenter should note that EPA has added emission factors to Table C-l for both blast
furnace gas and coke oven gas. This will reduce the burden on sources by allowing units smaller
than 250 mmBtu/hr combusting these fuels to use Tier 1 or Tier 2. However, units larger than
250 mmBtu/hr combusting these fuels will be required to report using Tier 3, due to the fuels'
potential variability and the the size of the unit which makes it potentially larger source of
emissions. The commenter should note that the fuel sampling requirements have been reduced
to weekly for units combusting alternative gaseous fuels which do not have the equipment in
place for daily sampling.
Commenter Name: Rhea Hale
Commenter Affiliation: American Forest & Paper Association (AF&PA)
Document Control Number: EPA-HQ-OAR-2008-0508-0909.1
Comment Excerpt Number: 11
Comment: If EPA insists that CEMs are required, then it should provide clarification regarding
under which standards they are to be operated. The rule is unclear as to whether Part 75, Part 60
or state requirements are to be followed. In certain areas it appears that facilities are allowed to
choose which provisions to follow and in others it does not.
Response: EPA agrees that the proposed language could be confusing, and has added language
to the final rule to clarify that any one of the alternate initial certification procedures for CO2
CEMS is acceptable. EPA has also clarified that the requirements of Part 75, Part 60, or an
applicable State continuous monitoring program are equally applicable for ongoing quality
assurance.
238
-------
Commenter Name: Jeffry C. Muffat
Commenter Affiliation: 3M Company
Document Control Number: EPA-HQ-OAR-2008-0508-0793.1
Comment Excerpt Number: 11
Comment: 3M owns and operates a hazardous waste incinerator used to manage its various
waste streams. We will not be able to use either Tier 1 or Tier 2 calculation methodologies listed
in Subpart C because there are no default values for their "fuel" in Tables C-l and C-2. The Tier
3 calculation methodology provides an onerous calculation option which requires each waste
stream to be tested or estimated for carbon content. For the 3M-owned hazardous waste
incinerator this would equate to thousands of waste streams. Such testing or estimation work is
not a standard part of typical operations and should not be required as a part of a reporting rule.
Tier 4 requires use of CO2 CEM data. Most hazardous waste incinerators, including the
hazardous waste incinerator owned by 3M, do not have C02 monitors currently installed. We
are concerned that carbon dioxide monitors will not be available for all who need to purchase
such devices. Even if they can be purchased, it will take time to install, calibrate and ensure the
operation of such devices. We will need more than the 2-3 months contemplated by the effective
date of the proposed rule to accomplish such tasks. To address this problem, 3M has two
suggestions. The first one is to require reporting only from those facilities that have a default
emissions factor in either Tables C-l or C-2. This would cover most of the major combustion
sources while not subjecting the minor sources to extensive testing requirements. The second
suggestion is to add a Tier 5 to Subpart C so facilities have an option to develop site-specific
emissions factors. Adding the ability to do this would give these facilities another tool to allow
for accurate estimates of carbon dioxide emissions.
Response: EPA has revised §98.30 to specify that units that combust hazardous waste will not
be required to report GHG emissions unless CEMS are used or another fuel for which default
factors are provided is also combusted in the unit. Only emissions from supplemental fuels need
to be reported.
Commenter Name: Keith Overcash
Commenter Affiliation: North Carolina Division of Air Quality (NCDAQ)
Document Control Number: EPA-HQ-OAR-2008-0508-0588
Comment Excerpt Number: 10
Comment: Comments on the combustion methodology: 1. It is widely recognized that the
emission factors for methane and nitrous oxide from stationary source combustion depend on
both the fuel and the technology type. EPA's calculation approach utilizing simplified
technology-independent factors is contrary to the current methodology used by the World
Resources Institute, The Climate Registry, and guidance from the Intergovernmental Panel on
Climate Change. Different technologies for coal combustion, such as bituminous fluidized bed
combustors, have significantly higher N2O emission factors; due to the large global warming
potential of this GHG, this can make a significant difference in total GHG emissions for some
facilities. NC DAQ believes that EPA should be consistent in its calculation methods with these
organizations; it is more technically correct and will reduce the burden of reporting via different
methods. 2. EPA should develop and provide as part of the rule default heat content and CO2,
239
-------
CH4 and N20 emission factors for additional fuels. EPA provides C02 emission factors for
additional fuels in Table C-2; however, not all fuels in that table have corresponding CH4 or
N20 factors in Table C-3. Does this mean that sources emitting these will need to develop site-
specific factors based on the results of source testing? We are particularly concerned that
sources meeting the threshold and burning small quantities of fuels not addressed in the EPA's
Emission Factor tables will be required to spend resources on testing these fuels. This issue may
also be addressed by utilizing a de minimis level (see comment 14); nonetheless we still
recommend that EPA add information that would allow emissions to be computed for additional
fuels. In addition, the "solvent" fuel (Table C-2) should be described in more detail. In
particular, does "solvent" fuel represent the VOC being combusted in a thermal oxidizer?
Facilities that combust rendered animal fat, a fuel used commonly in NC food processing
industries, are likely to be subject to reporting requirements; this fuel should be added to the
emission factor tables. NC has recommended emission factors for this fuel in its guidance
document on combustion: http://daq.state.nc.us/monitor/eminv/forms/StationaryCombustion
Sources.pdf. The recommendation is to treat animal fat as "waste oil." NC provides an input-
based emission factor calculated as 9.2 kg C02/gal based on heating value of 124,586 Bt/gal.
This value is based on a source test found in a permit (reference available in above pdf
document).3. EPA should provide a calculation methodology for thermal oxidizers used for
controlling VOC emissions. There are two sources of GHG emissions for this process: 1)
emissions resulting from combustion of the fuel added to the oxidizer (e.g., natural gas or oil that
may be needed to allow the oxidizer to reach the combustion temperatures required to destroy
the VOC) and 2) emissions resulting from the combustion of the VOC. If the rule does intend to
cover emissions resulting from the VOC portion of the emissions (which it appears to do, since
that process fits under the combustion definition), then there should be simplified approaches
provided to compute emissions; otherwise this source should be exempted.
4. While we recognize the benefits of direct measurements, we also recognize that the degree of
fluctuation of fuel characteristics does not justify the cost of fuel sampling. EPA should provide
flexibility to facilities in being able to use supplier data to characterize the fuel characteristics
used in computing emissions or reduce fuel sampling frequency if the variability in fuel quality
is determined to be insignificant.
Response: See the Preamble, Section II. C., and the response to comment EPA-HQ-OAR-2008-
0508-0561.1 excerpt 2 for information on the rationale for reporting for CH4 and N20.
EPA's approach to CH4 and N20 emission factors is consistent with the IPCC Guidelines in that
default emission factors are appropriate for sources that are not considered key sources.
Technologically dependent emission factors for N20 are used at the national level for mobile
sources because of the significantly larger contribution of these sources than stationary sources.
The default emissions factors used in this rule come from the IPCC Guidelines and were
established on the basis of measurement sampling from stationary sources, and do reflect broadly
combustion conditions across a variety of conditions. The use of fuel-specific emission factors is
in accordance with methods used in other programs and provides data of sufficient accuracy,
given the small amount of emissions, for the purposes of this rule.
EPA has also extensively revised the default emission factors used to calculate CH4 and N20
emissions, adding generic fuel-based emission factors covering all fuels for which C02 default
values are provided. EPA has specified in the final rule that only CH4 and N20 emissions from
combustion of those fuels listed in Table C-2 of Subpart C are required to be reported.
240
-------
EPA has revised §98.33 to deal with certain unconventional combustion processes and types of
fuel. In the Preamble, EPA has explained that "devices such as thermal oxidizers and pollution
control devices . . . would report only the GHG emissions from the firing of supplemental fossil
fuels." EPA believes that these provisions satisfy the intent of Part 98, to collect accurate and
consistent GHG emissions data that can be used to inform future decisions.
The commenter should note that Tables C-l and C-2 of the proposed rule have been consolidated
into Table C-l of the final rule, and the "solvent" fuel has been deleted. Furthermore, EPA has
added default values for rendered animal fat and other biogenic fuels to Table C-l.
EPA has substantially revised the Tier 2 and Tier 3 sampling requirements. In many cases,
sampling frequency has been reduced to ease the burden on reporters.
Commenter Name: Jeffrey A. Sitler
Commenter Affiliation: University of Virginia (UVA)
Document Control Number: EPA-HQ-OAR-2008-0508-0675.1
Comment Excerpt Number: 9
Comment: UVA has stationary combustion units that operate on natural gas, distillate oil, and
coal. Based on our current fuel analysis frequencies, these units fall somewhere between Tier 1
and Tier 2 calculations. §98.34(c)(1) and (2) state that monthly sampling and analysis of natural
gas and distillate oil is required and weekly sampling of coal is required. Our natural gas
supplier provides the heat content on a monthly basis. Natural gas is very stable in quality. As
part of our Title V, we obtain fuel certifications for coal and oil delivered to our permitted units.
Distillate oil heating values have changed recently with the removal of sulfur, however, it very
constant for the heat and sulfur content of the fuel. To provide an improvement over Tier 1
calculations, we request that we be allowed to use fuel supplier data for fuel oil and natural gas
quality in the Tier 2 calculations. Monthly sampling by UVA of these fuels would be overkill
given the low variability in these fuel supplies and our other permit requirements. Our coal
supplier is required to sample each and every rail car of coal and provide us with the analysis
before delivery. Once the coal is delivered, it is stored in silos until it is burned. In addition, we
are not a large coal consumer, usually less than 20,000 tons/year. The quality of the coal we
burn does not vary significantly and storing the coal in a silo maintains its delivered quality. We
request that we be allowed to use fuel supplier data for coal quality in the Tier 2 calculations.
Resampling this coal is unnecessary.
Response: The mandatory fuel sampling and analysis requirements for Tiers 2 and 3 have been
considerably revised. The final rule requires that natural gas be sampled semiannually. For fuel
oil and coal, a representative sampling is required for each fuel lot, i.e., for each shipment or
delivery. The final rule also clarifies that fuel sampling and analysis data provided by the
supplier may be used in the emission calculations.
241
-------
Commenter Name: Rhea Hale
Commenter Affiliation: American Forest & Paper Association (AF&PA)
Document Control Number: EPA-HQ-OAR-2008-0508-0909.1
Comment Excerpt Number: 4
Comment: If the use of default emission factors as described in Tier 1 requirements, applied at
the facility level, are not the primary source of data for stationary source combustion, EPA
should provide specific changes as outlined below:
1. EPA should allow use of vendor fuel purchase records in conjunction with vendor provided
fuel specific heating values and carbon content. Using vendor supplied data will result in
calculated emissions that are just as accurate as those based on fuel analysis performed by the
final consumer. This would lessen the burden on facilities and make the standard more cost
effective, while likely providing more accurate data. In this scenario, one vendor could perform
the required test and make it available to all customers. Costs would be decreased and one value
would be used for the same fuel as opposed to slightly different values that each facility is likely
to generate by using different labs. There is no technical basis that would suggest that a facility
level fuel test is more accurate than one done by the fuel vendor. While we are working together
with the Western Climate Initiative (WCI) to continue to improve its GHG Reporting
Requirements, in its recent release of the final draft of the GHG Reporting Requirements, vendor
supplied heating and carbon values are accepted.
2. Direct measurement of fuel properties, as required by Tier 2 and 3 in the proposal, should be
optional. Most regulated facilities have internal control procedures to determine which method
is the most consistent and accurate for their operations given their fuels and fuel systems and
multiple data collection and reporting requirements. In addition, AF&PA recommends that the
250 MMBtu threshold for the Tiering system be based on fossil fuel energy input and not the
energy input from biogenic sources. The extra cost of the higher measurement standard is not
warranted generally, but particularly for biogenic fuels.
3. AF&PA recommends that the Tier 1 methodology be allowed for gaseous and liquid fossil
fuels in units of all sizes and not limited to those less than 250 MMBTU/hr. The impacts
associated with GHGs from these types of fuels are well understood and accepted and there is no
additional benefit to requiring Tier 3 methodology for larger units that combust these fuels. In
addition, the allowance for biomass combustion in 98(b)2 should be expanded to allow for liquid
and gaseous biomass fuels, as biomass fuels are currently available in all three forms and are
likely to become more widely available in the future. There should not be a measurement cost
penalty for using biomass fuels in any of their available forms.
4. Similarly, EPA proposes to require monthly heating value determinations and monthly carbon
content determinations for spent pulping liquors. Instead, AF&PA recommends that EPA allow
the use of the IPCC (2006) default heating value of 11.8 TJ LHV/Gg (equivalent to 10.7 MMBtu
HHV short ton BLS).
Response: See the Preamble, Section II. L., on General Monitoring Requirements for the overall
rationale for methodologies required under this rule.
EPA chose not to adopt simplified calculation methods as a general monitoring approach (e.g.,
using default emission factors) for all units because the data would be less accurate than under
the selected option and would not make use of site-specific data that many facilities already have
available and refined calculation approaches that many facilities are already using. EPA is not
allowing reporters full flexibility to use any method because the accuracy and reliability of the
242
-------
data would be unknown. Because consistent methods would not be used under such an
approach, the reported data would not be comparable across similar facilities.
The final rule clarifies that fuel sampling and analysis data provided by the supplier may be used
in the emission calculations, and that fuel billing meters may be used to quantify fuel
consumption. To simplify the emission calculations in Tiers 2 and 3, arithmetic averaging of
HHV and carbon content data is permitted if these data are obtained at least at the minimum
frequency specified in §98.34, but less frequently than monthly (see §98.33(a)(2)(ii)). If
sampling is more frequent, the reporter must calculate a weighted average according to Equation
C-2b. However, regardless of the sampling frequency, the owner or operator must use the results
of all available valid fuel analyses in the emissions calculations.
EPA has expanded the use of the Tier 2 Calculation Methodology for C02 emissions to include
units with a maximum rated heat input capacity greater than 250 mmBtu/hr in which the only
fossil fuels combusted are pipeline natural gas and/or distillate oil. The mandatory fuel sampling
and analysis requirements for Tiers 2 and 3 have also been considerably revised. The final rule
requires that natural gas be sampled semiannually. For fuel oil and coal, a representative
sampling is required for each fuel lot, i.e., for each shipment or delivery. For other liquid fuels
and biogas, quarterly sampling is required. For other solid fuels, excluding municipal solid
waste, weekly composite sampling with monthly analysis is required. For other gaseous fuels,
the daily sampling requirement has been retained, but only for facilities with existing equipment
in place that is capable of providing the data. Otherwise, weekly sampling is required.
EPA has expanded the use of the Tier 1 Calculation Methodology for CO2 emissions to include
units greater than 250 mmBtu/hr that combust the biogenic fuels listed in Table C-l, unless the
owner or operator already determines the HHV of the biogas or biodiesel at least quarterly. In
this case Tier 2 shall be used. The commenter should note that EPA has added emission factors
to Table C-l for liquid and gaseous biomass-derived fuels including biogas, ethanol, biodiesel,
rendered animal fat, and vegetable oil.
Regarding the use of the IPCC default high heat value for spent pulping liquors, EPA has not
incorporated the commenter's suggestion. The final rule retains the requirement to periodically
determine the HHV.
Commenter Name: Kimberly S. Lagomarsino
Commenter Affiliation: Mississippi Lime
Document Control Number: EPA-HQ-OAR-2008-0508-1568
Comment Excerpt Number: 4
Comment: Mississippi Lime Company agrees with EPA's proposal to allow HHV's (for Tier 2
calculations) to be obtained from fuel suppliers, as contained in Section V.C.3.a of the Preamble.
Such a proposal greatly simplifies data collection endeavors for affected facilities.
Response: EPA appreciates the commenter's support. The final rule further clarifies that fuel
sampling and analysis data provided by the supplier may be used in the emission calculations.
243
-------
Commenter Name: Linda Farrington
Commenter Affiliation: Eli Lilly and Company (Lilly)
Document Control Number: EPA-HQ-OAR-2008-0508-0680.1
Comment Excerpt Number: 25
Comment: The requirement in §98.33(c)(4) to generate site specific CH4 and N20 emissions
factors based on the results of source testing when default factors have not been provided in
Table C-3 is very costly, and provides little to no environmental benefit. Since emission factors
for hazardous waste and process vent streams are not provided in Table C-3, source testing will
be the only option available for hazardous waste incinerators or thermal oxidizers. Comments
submitted to this docket by the Coalition for Responsible Waste Incineration (CRWI) include
further technical justification for not reporting CH4 and N20 based upon the likelihood of these
compounds being emitted from high temperature incineration processes.
Response: EPA acknowledges the concerns of the commenter. EPA has decided to retain the
requirement to report CH4 and N20 emissions both in metric tons of each gas and in metric tons
of C02e. To this end, EPA has also decided to retain the separate emission factors and
calculations for CH4 and N20. EPA believes that using fuel-based default emission factors to
report these gases separately provides an appropriate balance between easing the reporting
burden on facilities and collecting useful data on GHG emissions.
The final rule excludes from calculations any CH4 and N20 emissions from fuels for which
default emission factors have not been provided. Table C-2 has been revised to include CH4 and
N20 emission factors for more fuels, including blast furnace gas and coke oven gas, as well as
generic emission factors covering all fuel types listed in Table C-l. EPA has also deleted the
provision in the proposed rule which allowed facilities burning other fuels to develop site-
specific emission factors based on the results of source testing. Finally, hazardous waste
incinerators that do not combust any supplemental fuels are excluded from the stationary
combustion source category in §98.30. Only emissions from supplemental fuels combusted in
these units must be reported.
Commenter Name: Jeffrey A. Sitler
Commenter Affiliation: University of Virginia (UVA)
Document Control Number: EPA-HQ-OAR-2008-0508-0675.1
Comment Excerpt Number: 3
Comment: UVA has twenty-nine small fuel oil burning units spread across campus, none of
which have any metering. Currently, it appears that §98.34(c) requires monthly measuring of the
fuel to meet these proposed regulations. We suggest that in lieu of metering or manual stick
readings, we use fuel delivery metering to document fuel usage. Over a several year period of
record, any discrepancies between delivered and burned fuel will disappear.
Response: EPA has revised the rule to allow the use of Tier 2 for units of any size combusting
only pipeline quality natural gas and/or distillate oil. The Tier 2 methods do not require direct
fuel flow measurement, but instead require fuel consumption to be quantified using company
records, which could include fuel delivery metering. A definition of "company records," as it
pertains to quantifying fuel consumption, has been added to §98.6. The commenter should note
244
-------
that the fuel sampling frequencies in §98.34 have been substantially revised: the final rule
requires fuel oil to be sampled once per fuel lot, rather than monthly.
Commenter Name: See Table 6
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0679.1
Comment Excerpt Number: 118
Comment: §98.38, Table C-3. The fuel type of "Totes" should be "Tires".
Response: EPA has corrected this error in the final rule.
Commenter Name: David R. Case
Commenter Affiliation: Environmental Technology Council (ETC)
Document Control Number: EPA-HQ-OAR-2008-0508-0664.1
Comment Excerpt Number: 2
Comment: The Proposed 4-Tier Emission Calculation Methods Cannot Be Practically Applied
By Hazardous Waste Incinerators To Calculate C02e Emissions. The methods EPA has
proposed for calculating CC^e emissions do not practically and reasonably apply to such
facilities. The Tier 4 methodology requires the use of a certified CEMS to quantify C02 mass
emissions. This method requires the installation of a CO2 monitor and a stack gas volumetric
flow rate monitor, and is intended for facilities that already have existing CEMS equipment
installed. In fact, EPA's rationale is that the incremental cost of adding a diluent gas monitor or
flow monitor, or both, "would likely not be unduly burdensome" for a facility that is "already
required to install, certify, maintain, and operate CEMS and to perform ongoing QA testing of
the existing monitors." However, hazardous waste incinerators, although stringently regulated
under MACT emission standards, are not required to have CEMS. Most hazardous waste
incinerators do not have gas monitors or stack flow monitors, so this rule would require these
facilities to install, certify, maintain, and operate expensive equipment solely for the purpose of
calculating CC^e emissions. A reasonable estimate of the cost to purchase and install such
equipment at a hazardous waste incinerator is in excess of $100,000, exclusive of personnel
training costs and ongoing certification and maintenance. We do not believe that EPA has or can
justify the imposition of such high costs on a relatively small sector of facilities for the marginal
benefit, if any, of including hazardous waste incinerators in the GHG emission reporting
program. The Tier 3 methodology requires periodic determination of the carbon content of the
fuel, using consensus standards (ASTM methods) and direct measurement of the amount of fuel
combusted. However, the "fuel" for hazardous waste incinerators is a wide range of chemical
wastes that have highly varying carbon content. As explained above, hazardous waste
incinerators do not use a homogenous fossil fuel or process input that can be sampled weekly and
composited for monthly analysis. To the contrary, incinerators process whatever chemical
wastes are obtained from customers on a batch feed basis. The hazardous wastes range from
contaminated water to chemical sludges, from aerosol cans to bulk liquids, from high BTU
refinery slop oil to dilute solvent streams. The hazardous wastes vary enormously not only in
composition and physical properties, but even more dramatically from day-to-day and month-to-
245
-------
month. To make matters even more complicated, the wastes are often mixed and agitated at the
point of waste feed into the incinerator to achieve necessary BTU, constituent content, and
physical properties for safe and effective operation of the hazardous waste incinerator.
Determining the carbon content of hazardous waste feeds to an incinerator for purposes of the
Tier 3 calculation would be almost a chimerical task. The weekly sampling and monthly
composite analysis methodology in the proposed rule would be problematic. The cost and
operational burden of sampling and analysis to obtain representative data on the carbon content
of the wide and varying range of hazardous waste streams that are destroyed in an incinerator
cannot, and has not, been justified by EPA. We do not believe that the Tier 3 methodology can
be practically applied to hazardous waste incinerators. The Tier 2 and 1 methods do not appear
to be available to hazardous waste incinerators. Tier 2 applies only to units with lower heat input
capacity, and default emission factors for both Tier 2 and 1 do not appear to apply to hazardous
wastes. We do not believe there is any practical method for calculating C02e emissions from the
incineration of hazardous wastes. Before hazardous waste incinerators can be included in a
GHG emission reporting program, EPA must adequately explain and justify how emission
calculations would be conducted on a practical and reasonable basis.
Response: EPA, in response to these concerns, has revised the rule so that units that combust
hazardous waste will only be required to report GHG emissions from any supplemental fuels (for
which default values are provided) that are combusted in the unit.
Commenter Name: Paul J. Wolff
Commenter Affiliation: WolffWare
Document Control Number: EPA-HQ-OAR-2008-0508-0729.1
Comment Excerpt Number: 2
Comment: Two techniques that can be used to measure CO2 emissions are CEMS and with a
carbon mass balance. Both of these have accuracy limitations that will obscure the effect heat
rate improvements have on reducing CO2 emissions. A review of unit efficiencies computed
from CEMS data can show step events and long term trends with changes that exceed 10%. A
key challenge with CEMS is that it is very difficult to measure a gas flow rate with a high degree
of accuracy. This problem is compounded when multiple units emit through a common stack.
The most significant error for the carbon mass balance will be the sampling and weighing error
of the fuel stream. The magnitude of this error is difficult to quantify, however, ASME PTC 4
[Footnote: American Society of Mechanical Engineers. "PTC 4 - 1998 Fired Steam
Generators," 1999. 3 U.S. Geological Survey Coal Quality Database] provides some insight. A
typical uncertainty for an input-output method, which also requires that the fuel stream be
weighed and sampled, is stated to be in the range of 3 to 6%. The largest contributor to the error
is created by sampling and weighing the fuel stream to determine the chemical energy entering
the boiler. Similar errors can be expected to occur with a carbon mass balance approach, even
under well controlled test conditions. The most effective means to report CO2 emissions is to
require that coal fired plants measure and report unit efficiency and then to quantify CO2
emissions from efficiency with a fixed emission factor [see DCN: EPA-HQ-OAR-2008-0508-
0729.1 for equation]. Basing the CO2 emissions on unit efficiency is appropriate because it is
what plant personnel will manage to control the CO2 emissions. There are well defined methods
published by the ASME (ASME performance test codes) for measuring the efficiency of the
Rankine power cycle and of the individual components. The ASME heat loss method in
246
-------
conjunction with a measurement of turbine cycle efficiency is one of the most accurate ways to
quantify the efficiency of a fossil unit. The heat loss method has improved accuracy over the
input-output approach because it is not based on determining the total heat input by weighing
and sampling the fuel stream. Basing the CO2 emissions on a fixed emission factor is
appropriate because once a plant chooses to burn a certain type of coal, any changes that occur
will be due to random variations in the fuel and in the measurement of its carbon content. This
approach is also consistent with EPA's current method for determining heat rate from C02
emissions. Furthermore coal data in a USGS database3 supports this idea. Figure 1 [See DCN:
EPA-HQ-OAR-2008-0508-0729.1 for figures provided by commenter] presents the data,
categorized by coal rank, of the CO2 emission factor for the coal in the USGS database. To
create these plots, the data were categorized by coal rank and averaged based on the BTU value
(the bins were 500 BTU's). These data show that the emission factors computed from the USGS
data agree well with the EPA emission factors. This is especially true for bituminous coal and
for subbituminous coal when restricted to a range of 8,000 to 10,000 BTU. Figures 2 through 5
present the emission factors for given coal ranks categorized by selected geographic regions.
Figure 2 presents the emission factors for bituminous coal for various geographic regions, while
Figure 3 presents the variation relative to the EPA emission factor. The geographic regions
selected were the ones containing the most coal samples. Figure 3 shows that in general there
are small differences in the emission factors for bituminous coal among the different coal
regions. For example bituminous emission factors deviate by no more than 2.7% from the EPA
recommended value. This is within the measurement tolerance that would be achieved with
sampling and measurement methods. Figures 4 and 5 show that the variation for subbituminous
and lignite are larger, 3.6 and 4.8% respectively, however the size of the data sets are
substantially smaller than the bituminous data set. Therefore, for a given coal rank, any
differences between emission factors are within or very close to the measurement tolerances.
The variation of the coal for a given coal rank and geographic region is shown in Figures 6 and
7. Figure 6 shows the variation among individual data points that occurs for bituminous coal in
the Northern Applachian Region while Figure 7 quantifies the variation in the data by showing
the minimum, maximum, and the percent difference between the minimum and maximum
values. The maximum difference is 13.7% and generally exceeds 9% for most of the values.
This range is consistent with variations I have observed in batches of coal received by a given
power plant. If CO2 emissions are based on the actual measurement of the carbon concentration
in the fuel, similar variations would result in the CO2 measurement. These random variations
obscure the connection between unit efficiency and CO2 emissions and will reduce the incentive
for power companies to maintain and improve unit efficiency. There is a unique opportunity to
create legislation that provides the necessary incentives for power companies to improve the
efficiency of their coal fired units. There are several benefits to be gained by following this
approach: 1. There would be a clear and measurable incentive for power companies to improve
the efficiency of their coal fired units. The potential economic incentives include an industry
wide reduction in CO2 emissions that could range from 57 to 95 million metric tons. The
financial incentives include a reduction in fuel costs for the power industry that range from 1.4 to
2.4 billion dollars. 2. There would be a clear incentive for power companies to create more
energy from more efficient units. The benefits for this are comparable to the benefits that would
be received by increasing the efficiency of a unit. 3. Fixed emission factors would eliminate the
need for power companies to implement extensive programs to sample the fuel and measure
carbon at the plant level. It would also eliminate a factor that could be gamed to artificially
reduce a unit's CO2 emissions.
247
-------
Response: See the Preamble, Section II. L., for the response on the general monitoring
approach.
EPA is not opposed to innovative, alternative approaches for estimating CO2 mass emissions.
The commenter suggests that basing C02 emissions on unit efficiency and a "fixed emission
factor" will provide more accurate data than mass balance methods or CEMS. However, the
commenter did not provide any supplementary information, proposed rule language, or cost
analysis to demonstrate how the proposed method could be implemented. In view of this, EPA
has not incorporated the commenter's suggested approach into the final rule, but is willing to
consider it in a future rulemaking, if the necessary technical details of the method and cost
estimates are provided for Agency review.
Commenter Name: Catherine H. Reheis-Boyd
Commenter Affiliation: Western States Petroleum Association (WSPA)
Document Control Number: EPA-HQ-OAR-2008-0508-0983.1
Comment Excerpt Number: 2
Comment: WSPA notes that there is a conflict between language in the Preamble and the text
shown in the rule. The Preamble states that CEMS are only required for combustion devices
fired by solid fuels, or otherwise required by existing rules or permits. However, the rule
language regarding selection of the "Tier" level (Section 98.33 (b)(5)), as currently written,
would require CEMS for any combustion unit that has a maximum rated heat input greater than
250,000 Btu/hr or that ran for more than 1,000 hours in any year since 2005. California
refineries have already invested significant capital and hardware down a different path that yields
equivalent, if not greater, accuracy using continuous High Heating Value (HHV) or carbon
content analyzers. These installations are already in use in fulfilling the obligations under
California's Mandatory Reporting Regulation. EPA's provision requiring CEMs would be
duplicative, and result in no additional information nor serve any useful purpose in a GHG
program. Recommendation: EPA should eliminate the conflict by modifying the language in
the rule to match the Preamble. EPA should also expressly allow the use of HHV and/or carbon
content analyzers in Tier 3.
Response: EPA acknowledges the commenter's concerns regarding Tier 4 applicability. EPA
has revised §98.33(b)(4)(ii) of the final rule to clarify that all six criteria specified in
subparagraphs (A) through (F) must be met before Tier 4 is required. The commenter should
note that the Tier 2 methods use measured HHV, while the Tier 3 methods use measured carbon
content. Please refer to §98.34 for more information on acceptable HHV and carbon content
sampling and analysis methods.
248
-------
Commenter Name: Matthew Frank
Commenter Affiliation: Wisconsin Department of Natural Resources
Document Control Number: EPA-HQ-OAR-2008-0508-1062.1
Comment Excerpt Number: 9
Comment: The framework outlined in the proposed rule for GHG reporting for ethanol
production is straightforward, understandable and comprehensive. If EPA requires the
calculation of these emissions, please identify the emission factors to be used.
Response: See the Preamble section on ethanol production.
At this time, EPA is not going final with the Ethanol Production Subpart. The sources of GHG
emissions at ethanol production facilities that were to be reported under the proposed rule were
stationary fuel combustion, onsite landfills, and onsite wastewater treatment. EPA has decided
not to finalize the portion of 40 CFR Part 98, Subpart HH (Landfills) that addresses industrial
landfills, nor 40 CFR Part 98, Subpart II (Wastewater Treatment). Stationary fuel combustion
sources at ethanol production facilities are subject to the requirements of 40 CFR Part 98,
Subpart C if general stationary fuel combustion emissions exceed the 25,000 metric tons C02e
threshold. As EPA considers next steps, we will be reviewing the public comments and other
relevant information.
Based on careful review of comments received on the proposal Preamble, rule and technical
support documents under proposed 40 CFR Part 98, Subparts J, HH, and II, EPA will perform
additional analysis and consider alternatives to data collection procedures and methodologies
contained in those subparts.
EPA has revised the list of fuels in Table C-l, and has added emission factors for a number of
biogenic fuels, including ethanol.
Commenter Name: See Table 8
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0709.1
Comment Excerpt Number: 9
Comment: Proposed section 98.33(b)(5) on 74 Fed. Reg. 16,634 would require the use of Tier 4
calculation methodology - i.e. continuous emissions monitoring (CEMS) - for a unit that falls in
four listed categories: There are no "ands" or "ors" between the four listed categories, so we do
not know whether a unit would be subject to CEMS if it fell into just one category, or if it would
only trigger CEMS if it fell into all four categories. We request that EPA clarify this provision.
We assume you meant to insert the word "or" in the list, so that a unit would trigger CEMS if it
fell into any one category. Further, we oppose the imposition of CEMS on any unit that "has
operated for more than 1,000 hours in any calendar year since 2005." See section
98.33(b)(5)(C). A unit might operate more than 1,000 hours and yet still be a minor source that
has not had to previously install CEMS to comply with some other regulatory requirement. [This
would be burdensome and would impose an unnecessary economic hardship on smaller sources.
For natural gas-fired sources, there is no need to impose CEMS. An accurate measure of CC^e
249
-------
from combustion of natural gas can be calculated based on the natural gas used by the unit, as
measured by the gas billing meter. As we discuss with respect to Subpart NN below, these gas
billing meters are the "cash registers" that determine how much natural gas a customer has used
and must pay for. There are strong economic interests on both sides of the transaction to ensure
that this data is accurate. No purpose would be served by requiring expensive and duplicative
CEMs for such gas billing metered units.
Response: EPA acknowledges the commenter's concerns regarding Tier 4 applicability. EPA
has revised §98.33(b)(4)(ii) of the final rule to clarify that all six criteria specified in
subparagraphs (A) through (F) must be met before Tier 4 is required. The final rule also clarifies
that fuel sampling and analysis data provided by the supplier may be used in the Tier 2 and 3
emission calculations, and that fuel billing meters may be used to quantify fuel consumption.
Commenter Name: Sean M, O'Keefe
Commenter Affiliation: Hawaiian Commercial and Sugar Company (HC&S)
Document Control Number: EPA-HQ-OAR-2008-0508-1138.1
Comment Excerpt Number: 9
Comment: EPA has proposed a four-tiered approach to monitoring and calculating C02
emissions from stationary combustion sources, and proposes requiring stationary combustion
sources with heat inputs greater than 250 million BTU per hour (250 MMBTU/hr) to utilize the
most stringent emissions calculation methods (i.e., Tiers 3 and 4) while sources smaller than 250
MMBTU/hr in size would be allowed to use more simplified methods (Tiers 1 and 2) with the
option to use the more stringent methods if desired. The use of Tier 3 emissions calculation
methods will impose significantly greater burdens and costs on regulated facilities than would
the use of Tier 2 or Tier 1 emissions calculation methods. The Tier 2 calculation methodology
would require the use of the monthly measured higher heating value (HHV) of each fuel
combusted (if available) in conjunction with default fuel-specific CO2 emission factors and
would allow fuel consumption to be based on company records; if monthly measured HHV is not
available, then the Tier 1 methodology (employing both a fuel-specific default CO2 emission
factor and higher heating value) could be used. The Tier 3 methodology would require periodic
determination of the carbon content of the fuel (and molecular weight for gaseous fuels), along
with direct measurement of the amount of fuel combusted. In addition to incurring ongoing
analytical costs, facilities utilizing the Tier 3 methodology may need to install specialized fuel
sampling equipment in order that representative samples of fuels can be obtained for analysis in
compliance with referenced methods. In some cases, means for direct measurement of the
amount of fuel combusted may also need to be installed. A&B believes that requiring units
larger than 250 MMBTU/hr in size to use Tier 3 methods will unfairly and arbitrarily impose
higher costs and regulatory burdens on some facilities and will not significantly improve the
accuracy of overall estimates of GHG emissions, since facilities with multiple small emission
units may have the same or higher overall emissions than facilities with a single larger unit. The
rule should allow facility operators to select from any of these three emissions calculation
methodologies rather than imposing a stricter standard based on an arbitrary emission unit size
threshold.
Response: See the Preamble, Section II. L., on General Monitoring Requirements for the overall
rationale for methodologies required under this rule, and the response to comment EPA-HQ-
OAR-2008-0508-0909.1 excerpt 4 and EPA-HQ-OAR-2008-0508-0580 excerpt 10 for the
rationale for methodologies required under Subpart C.
250
-------
EPA has revised the rule to significantly expand the use of Tier 1 and Tier 2 Calculation
Methodologies. In general, units of any size combusting the biogenic fuels listed in Table C-l
may use Tier 1. The 250 mmBtu/hr restriction on the use of Tier 2 has been lifted for units in
which the only fossil fuels combusted are pipeline quality natural gas and/or distillate oil, in view
of the homogeneous nature of these fuels. For a homogeneous fuel such as pipeline natural gas,
monthly sampling is not necessary. For other fuels such as oil and coal, which are delivered in
shipments or lots, requiring monthly sampling may be impractical; new fuel lots or deliveries
may not be received on a monthly basis. Therefore, §98.34 has been revised to require that
natural gas be sampled semiannually. For fuel oil and coal, a representative sampling sample is
required for each fuel lot, i.e., for each shipment or delivery. For other liquid fuels and biogas,
quarterly sampling is required. For other solid fuels, excluding municipal solid waste, weekly
composite sampling with monthly analysis is required. For other gaseous fuels, the daily
sampling requirement has been retained, but only for facilities with existing equipment in place
that is capable of providing the data. Otherwise, weekly sampling is required.
The final rule clarifies that fuel sampling and analysis data provided by the supplier may be used
in the emission calculations, and that fuel billing meters may be used to quantify fuel
consumption. To simplify the emission calculations in Tiers 2 and 3, averaging of HHV and
carbon content data is permitted if these data are obtained at least at the minimum frequency
specified in §98.34, but less frequently than monthly (see §98.33(a)(2)(ii)). If sampling is more
frequent, the reporter must calculate a weighted average according to Equation C-2b. However,
regardless of the sampling frequency, the owner or operator must use the results of all available
valid fuel analyses in the emissions calculations.
Commenter Name: Rhea Hale
Commenter Affiliation: American Forest & Paper Association (AF&PA)
Document Control Number: EPA-HQ-OAR-2008-0508-0909.1
Comment Excerpt Number: 9
Comment: AF&PA believes that the proposed rule requires Tier 4 methodology for
determining CO2 from boilers with fuel input capacity greater than 250 MMBtu/hr, and where a
required CEMs has been already installed and the CEMs has a gas monitor of any kind, or a
volumetric flow rate monitor, or both and the unit burns solid fossil fuels or MSW as a primary
or secondary fuel. AF&PA seeks clarification that all of these conditions must be true to require
Tier 4 methodology and not just certain elements.
Response: EPA acknowledges the commenter's concerns regarding Tier 4 applicability. EPA
has revised §98.33(b)(4)(ii) of the final rule to clarify that all six criteria specified in
subparagraphs (A) through (F) must be met before Tier 4 is required.
251
-------
Commenter Name: Lawrence W. Kavanagh
Commenter Affiliation: American Iron and Steel Institute (AISI)
Document Control Number: EPA-HQ-OAR-2008-0508-0695.1
Comment Excerpt Number: 9
Comment: Subpart C requires reporting of combustion unit CH4 and N20 emissions using
default values for various fuels shown in Table C-3. No values are presented for coke oven gas.
We are not aware of any reliable emission factors for these gases for coke oven gas combustion
but believe concentrations of these gases to be insignificant, if present at all, in the combustion
products of coke oven gas and suggest deleting this requirement for coke oven gas combustion
sources.
Response: EPA acknowledges the concerns of the commenter. Table C-2 has been revised to
include CH4 and N20 emission factors for more fuels, including blast furnace gas and coke oven
gas, as well as generic emission factors covering all fuel types listed in Table C-l. Section
98.33(c) of the final rule excludes from calculations any CH4 and N20 emissions from fuels that
are not listed in Table C-2. EPA has also deleted the provision in the proposed rule which
allowed facilities burning other fuels to develop site-specific emission factors based on the
results of source testing.
Commenter Name: Jennifer Reed-Harry
Commenter Affiliation: PennAg Industries Association
Document Control Number: EPA-HQ-OAR-2008-0508-0948.1
Comment Excerpt Number: 9
Comment: We recommend that food processing operations which utilize alternative energy
products, such as animal by-products, be required to conduct annual sampling vs. monthly
sampling. When using a known, consistent energy source, the sampling documents consistent
results. Requiring monthly sampling is an unnecessary expense which will not yield different
results than annual sampling.
Response: EPA has revised the tier requirements. The use of Tier 1 calculation methods for
C02 emissions has been expanded to include units greater than 250 mmBtu/hr that combust the
biogenic fuels listed in Table C-l, provided that the owner or operator does not analyze or
receive the results of an analysis for HHV of the biogas or biodiesel combusted at least quarterly.
In that case, Tier 2 shall be used. Table C-l has been revised to include default values for a
number of biogenic fuels, including rendered animal fat.
252
-------
Commenter Name: Lawrence W. Kavanagh
Commenter Affiliation: American Iron and Steel Institute (AISI)
Document Control Number: EPA-HQ-OAR-2008-0508-0695.1
Comment Excerpt Number: 8
Comment: Boilers located at independent coke plants would also be obligated to report C02
emissions from combustion of fuels in these units. Typically they are fired with excess coke
oven gas but may be supplemented with natural gas. (As is the case for emissions associated
with coal combustion under Subpart KK, CO2 emissions attributed to natural gas consumption
are accounted for under obligations for natural gas suppliers in Subpart NN.) Although some
coke plants have boilers with rated capacities below 250 MMBTUH and would qualify for Tier 1
methodology, other plants have boilers with capacities exceeding 250 MMBTUH and would be
required to apply Tier 2 or Tier 3 methodology. For all of the reasons noted above, we
respectfully request that Tier 1 methodology apply to coke oven gas-fired boilers regardless of
size. Reporting of emissions associated with coke oven combustion stacks and coke oven gas-
fired boilers or other combustion sources, whether under Tier 1 or Tier 2, necessitates the
addition of a coke oven gas and blast furnace gas default values in Table C-l or C-2.
Response: The commenter should note that EPA has added emission factors to Table C-l for
both blast furnace gas and coke oven gas. This will reduce the burden on sources by allowing
units smaller than 250 mmBtu/hr combusting these fuels to use Tier 1 or Tier 2. However, units
larger than 250 mmBtu/hr combusting these fuels will be required to report using Tier 3, due to
the fuels' potential variability. The commenter should note that the fuel sampling requirements
have been reduced to weekly for units combusting alternative gaseous fuels which do not have
the equipment in place for daily sampling. EPA has also removed the cumulative 250 mmBtu/hr
restriction on unit aggregation, and has clarified the common pipe reporting option.
Commenter Name: Rhea Hale
Commenter Affiliation: American Forest & Paper Association (AF&PA)
Document Control Number: EPA-HQ-OAR-2008-0508-0909.1
Comment Excerpt Number: 7
Comment: AF&PA believes the methodologies for calculating emissions from biomass
combustion should be as simple as possible. It is encouraged by the inclusion of Tier 1
methodology for biomass combustion for units of all sizes. In the pulp and paper industry, most
boilers which burn biomass also burn one or more fossil fuels. Where a facility is co-firing
biomass, it should be allowed to estimate the fossil fuel-related emissions using a mass balance
approach (emission factors and activity data) as in other fuel combustion calculations. Facilities
with regulated Continuous Emissions Monitoring systems (CEMs) can use them as an alternative
method if a reasonable means exists to translate CEMs data into GHG estimates. In such
instances, however, back-calculating of biogenic carbon dioxide from biomass (versus fossil
fuels) using operating and emissions factors remains a necessary calculation making the added
value of the monitoring to be little or none. Whether or not a C02 monitor is in place, emissions
from biomass need to be calculated (or back-calculated from steaming rate and fossil fuel use
data) in order to be backed out of the GHG emissions estimates. EPA does not address boilers
that burn a combination of fossil and biomass fuels where CEMs are not used. From existing
guidance one may assume that the Tier 1 methods can be used for estimating the biomass-related
253
-------
emissions from combination fuel fired boilers not equipped with CEMs, but this is not clear from
the guidance. AF&PA interprets the proposed rule to allow Tier 1 methods for estimating
biomass-related emissions as appropriate for boilers burning biomass in addition to fossil fuels,
and requests clarification from EPA on this topic.
Response: EPA has considerably revised the methods provided to calculate CO2 emissions
from biogenic fuels. Emissions from biogenic fuels combusted in a unit of any size can be
calculated using Tier 1, provided that the fuels combusted are listed in Table C-l and the mass of
the biogenic fuel combusted can be accurately quantified using available information. However,
if the fuels combusted consist of biogas or biodiesel, and the HHV of the fuel is sampled at least
at the minimum required frequency, Tier 2 shall be used. EPA believes that the methods
provided in §98.33(e) are sufficient for calculating biogenic emissions from combination boilers,
and that it is not necessary to include the Tier 5 methods from the Pulp and Paper TSD.
Commenter Name: Rhea Hale
Commenter Affiliation: American Forest & Paper Association (AF&PA)
Document Control Number: EPA-HQ-OAR-2008-0508-0909.1
Comment Excerpt Number: 3
Comment: The approach which would best satisfy EPA's stated intent (and is AF&PA's
preferred approach) would be to follow the conventions established by the Canadian and
European Union's programs and allow the use of national average fuel-specific emission factors,
those factors published by the IPCC, or site specific factors determined (through experience) to
be even more appropriate for the specific example under evaluation. Direct measurement of
carbon content and heat content of fuels is an additional burden that is not justified by relative
improved accuracy. Instead we propose that activity data and default emissions factors as
described in Tier 1 requirements, applied at the facility level, be the primary source of data for
stationary source combustion - as is allowed under most, if not all, GHG reporting systems. This
approach will allow for quality and consistent data with respect to reported emissions. EPA
could continue to allow the more advanced Tiers as options facilities might use as deemed
appropriate to the circumstances.
Response: See the Preamble, Section II. L., for the response on the general monitoring
approach.
See the response to comment EPA-HQ-OAR-2008-0508-0464.1 excerpt 4 for a description of
EPA's approach to tiers.
EPA disagrees with the commenter's suggestion of allowing Tier 1 reporting for all units and
facilities. EPA did not choose to adopt a simplified calculation method approach (e.g., using
default emission factors) for all units because the data would be less accurate than under the
selected option and would not make use of site-specific data that many facilities already have
available and refined calculation approaches that many facilities are already using.
However, EPA has significantly expanded the use of Tier 1 and Tier 2 Calculation
Methodologies. Most units of any size combusting the biogenic fuels listed in Table C-l may
use Tier 1. The 250 mmBtu/hr restriction on the use of Tier 2 has been lifted for units in which
254
-------
the only fossil fuels combusted are natural gas and/or distillate oil, in view of the homogeneous
nature of these fuels. However, the 250 mmBtu/hr unit size cutoff remains for units that combust
other fossil fuels, and higher tiers are required for those units.
Commenter Name: Robert D. Bessette
Commenter Affiliation: The Council of Industrial Boiler Owners (CIBO).
Document Control Number: EPA-HQ-OAR-2008-0508-0513.1
Comment Excerpt Number: 4
Comment: EPA is proposing use of default emission factors for those emissions from fuel
combustion, but requests comment on more specific factors that could be applied. By EPA's
own admission, the total quantity of potential CH4 and N2O emissions from fuel combustion is
insignificant compared to C02 emissions. Since reductions in C02 emissions associated with
reduced fuel use will automatically reduce CH4 and N2O emissions, there is simply no
justification to impose additional costs for any more detailed approach to those emissions. In
fact, they could be considered de minimis and ignored with no major impact on overall results.
CIBO recommends that both CH4 and N20 emissions be excluded from stationary fuel
combustion source reporting. The overall levels of emissions from these two gases are
disproportionately low as compared to C02 (e.g., total C02e emissions of CH4 and N20 from
natural gas combustion is less than 0.1% of the C02 emissions for natural gas combustion per
Tables C-l and C-3 of the proposed rule), and therefore estimating and reporting their emissions
creates a disproportionately high burden on sources.
Response: See the Preamble, Section II. C., and the response to comment EPA-HQ-OAR-2008-
0508-0561.1 excerpt 2 for information on the rationale for reporting for CH4 and N20.
EPA has decided to retain in the final rule the requirement to report CH4 and N20 from
stationary combustion sources. EPA believes that the use of fuel-specific emission factors for
these pollutants strikes an appropriate balance between minimizing the burden on reporters and
obtaining valuable GHG emission data. EPA has, however, revised the final rule to exclude CH4
and N20 emissions from fuels for which the rule does not provide emission factors, and has
deleted the provision allowing the owner or operator of a facility to develop site-specific
emission factors for such fuels. EPA believes that this change will reduce the reporting burden
on facilities.
Commenter Name: Robert D. Bessette
Commenter Affiliation: The Council of Industrial Boiler Owners (CIBO).
Document Control Number: EPA-HQ-OAR-2008-0508-0513.1
Comment Excerpt Number: 25
Comment: §98.33 - Stationary fuel combustion source emissions calculation methods. The
proposed methods require use of annual fuel consumption from company records. Specific
alternative methods of determining fuel consumption are not spelled out, but it is assumed that
the covered entities would have considerable flexibility in determining the annual fuel
consumption. The following is but one example of the complications of determining fuel use.
255
-------
For many solid fuel fired units such as stoker coal fired boilers and pulverized coal fired boilers
utilizing volumetric coal feeders, there is no way to measure weight rate of coal feed to the
boilers. In those cases, alternative methods of determining heat input and annual fuel
consumption need to be used. For example, the Tier 2 methodology for Medical Solid Waste
(MSW) fired units allows for use of boiler steam output and the maximum rated heat input to
design steam output ratio to determine heat input.
A similar approach could also be used for other solid fuel fired units. Similarly, in cases where
byproduct fuels are fired or co-fired, the covered entity should have latitude to utilize any
methods appropriate for the unit that provide representative determination of CO2 emissions.
Providing flexibility in fuel consumption determination methodology will decrease the cost of
the reporting program with an insignificant impact on overall emissions accounting accuracy. It
is assumed that this is EPA's intention based on the reference to relying on company records.
Response: The use in Tier 2 of steam production and combustion unit efficiency to calculate
CO2 emissions is extended to other solid fuels in addition to municipal solid waste (MSW).
These parameters may also be used to quantify the amount of biomass combusted in a unit.
In Tiers 1, 2, and 3, solid fuel consumption is determined by company records. EPA has defined
the term "company records" in §98.6 of the final rule. EPA believes that the revised definition
provides appropriate guidance as to what records a facility may use to determine fuel
consumption.
Commenter Name: Robert D. Bessette
Commenter Affiliation: The Council of Industrial Boiler Owners (CIBO).
Document Control Number: EPA-HQ-OAR-2008-0508-0513.1
Comment Excerpt Number: 26
Comment: §98.33 and Table C-l - GHG emission calculations and Table C-l. These correctly
reference use of higher heating values. However, there is no stipulation that the HHV for solid
fuels must be based on the As-Received analysis, which includes moisture content and represents
the quality of the fuel as it is combusted. The alternative approach is to use the dry analysis,
which excludes moisture and corrects all other components for zero moisture. The correct
approach is to use the As-Received analysis per ASTM test methods. The HHV values given in
table C-l are representative of typical As-Received heating values. This needs to be clearly
stated in the rule to avoid confusion and to ensure accurate results.
Response: EPA does not agree with the commenter. For consistency in implementing the
mandatory reporting rule, the high heat values must be on a dry basis. The moisture content of
coal "as-received" can vary considerably from site to site.
256
-------
Commenter Name: Robert D. Bessette
Commenter Affiliation: The Council of Industrial Boiler Owners (CIBO).
Document Control Number: EPA-HQ-OAR-2008-0508-0513.1
Comment Excerpt Number: 27
Comment: §98.33(a) - Requirement to determine C02 emissions from fuel combustion for each
stationary unit. EPA should provide more flexibility in the calculation and reporting
requirements in order to allow use of available data that is representative of the combustion units.
For example, if total fuel use is metered for a facility or combination of combustion sources, the
use of the combined data should be allowed for determining total emissions for those sources on
a monthly or annual basis. The Tier 3 methodology at 74 FR 16632 mentions that tank drop
measurements may be used; the drop in tank level is only representative of fuel combusted for
the combination of combustion units supplied from that common storage tank. Section
98.36(c)(3) of the proposed rule allows use of common pipe configurations. 74 FR 16638.
Since EPA allows use of those methods, a similar approach should be allowed for any
combustion unit types for any Tier and included in paragraph §98.33(a) for clarity.
Response: Combining units that have a common fuel source or exit through a common stack is
allowed in the proposed and revised rule. In addition, the cumulative 250 mmBtu/hr heat input
capacity limit on the aggregation of units into a group has been dropped. Rather, the 250
mmBtu/hr restriction applies only to the individual units in the group. Therefore, for reporting
purposes, individual units with maximum rated heat input capacities of 250 mmBtu/hr or less
may be aggregated without limit into a single group, provided that the Tier 4 methodology is not
required for any of the units, and all units in the group use the same tier for any common fuel(s)
that they combust. Units with maximum rated heat inputs greater than 250 mmBtu/hr must
report as individual units, unless they burn the same type of fuel (oil or gas) provided by a
common pipe or supply line; in that case, the owner or operator may opt to use the common pipe
reporting provisions in §98.36(c)(3). Units using Tier 4 must report as individual units unless
they share a monitored common stack; in that case, the common stack reporting provisions of
§98.36(c)(2) may be used.
Commenter Name: Robert D. Bessette
Commenter Affiliation: The Council of Industrial Boiler Owners (CIBO).
Document Control Number: EPA-HQ-OAR-2008-0508-0513.1
Comment Excerpt Number: 28
Comment: For liquid fuels, fuel delivery documentation or invoices should be allowed as being
indicative of fuel combusted in units combusting that fuel, with proper year-end inventory
correction. Similarly, natural gas volume identified by the gas supplier for a facility by billing or
invoice data should be allowable for use in determining total annual volume combusted in
applicable combustion units.
Response: EPA has revised the rule to allow the use of Tier 2 for units of any size combusting
only distillate oil and/or pipeline quality natural gas. Tier 2 allows the use of company records to
determine fuel use. The final rule also clarifies that fuel billing meters may be used to quantify
fuel consumption in Tiers 1-3. To simplify the emission calculations in Tiers 2 and 3,
257
-------
averaging of HHV and carbon content data is permitted if these data are obtained at least at the
minimum frequency specified in §98.34, but less frequently than monthly (see §98.33(a)(2)(ii)).
If sampling is more frequent, the reporter must calculate a weighted average according to
Equation C-2b. However, regardless of the sampling frequency, the owner or operator must use
the results of all available valid fuel analyses in the emissions calculations.
Commenter Name: Robert D. Bessette
Commenter Affiliation: The Council of Industrial Boiler Owners (CIBO).
Document Control Number: EPA-HQ-OAR-2008-0508-0513.1
Comment Excerpt Number: 29
Comment: EPA should precisely state how the Tier system affects reporting requirements. For
example, EPA should provide answers to questions such as the following: If a facility reports in
a certain Tier for one unit, must it report using that Tier for all units at the facility? If a facility
reports using a certain Tier for one unit, can it go back to using a lower Tier in the future for that
unit if circumstances change (i.e., a modification to the unit that deems old data unusable for
estimating emissions after the modification)? If a facility volunteers to report at a certain Tier
for one year, must it continue to use that Tier for reporting in every year after?
Response: In response to comments, EPA has added §98.33(b)(6) of the final rule to explain
that different tiers may be used for different fuels in the same unit, unless the use of Tier 4 is
required or elected, in which case the "total reported CO2 emissions from the combustion of all
fuels shall be based solely on CEMS measurements." It is EPA's intent that different tiers may
be used for different units at a facility. However, it is not EPA's intent that facilities modify
units to qualify for a lower reporting tier, such as through the removal of existing CEMS. EPA
selected the tier approach to reporting in an effort to appropriately balance the burden on
reporters with the need to collect accurate data on greenhouse gas emissions.
Commenter Name: Robert D. Bessette
Commenter Affiliation: The Council of Industrial Boiler Owners (CIBO).
Document Control Number: EPA-HQ-OAR-2008-0508-0513.1
Comment Excerpt Number: 30
Comment: §98.33(a)(1) - Fuel analysis. Tier 1 methodology only allows use of the Table C-l
default values. Tier 2 requires use of monthly analyses. EPA should provide more flexibility by
allowing use of site specific fuel analysis values that would be more representative of fuels
combusted than the default values. Those site specific values could be available from site
samples and analyses or from supplier provided analyses on some frequency that is less frequent
than monthly.
Response: The rule allows facilities to use a higher tier than the minimum required. EPA has
also revised the sampling requirements for Tiers 2 and 3. For a homogeneous fuel such as
pipeline natural gas, monthly sampling is not necessary. For other fuels such as oil and coal,
which are delivered in shipments or lots, requiring monthly sampling may be impractical; new
fuel lots or deliveries may not be received on a monthly basis. Therefore, §98.34 has been
258
-------
revised to require that natural gas be sampled semiannually. For fuel oil and coal, a
representative sampling sample is required for each fuel lot, i.e., for each shipment or delivery.
For other liquid fuels and biogas, quarterly sampling is required. For other solid fuels, excluding
municipal solid waste, weekly composite sampling with monthly analysis is required. The final
rule also clarifies that fuel sampling and analysis data provided by the supplier may be used in
the emission calculations.
Commenter Name: Robert D. Bessette
Commenter Affiliation: The Council of Industrial Boiler Owners (CIBO).
Document Control Number: EPA-HQ-OAR-2008-0508-0513.1
Comment Excerpt Number: 31
Comment: §98.33(a)(2) and (3) - Monthly fuel analysis. Tier 2 and 3 methodology requires
monthly analyses of fuels. Gaseous fuels (especially pipeline quality natural gas) and liquid
fuels meeting a purchase specification typically do not vary significantly over time, so that a
single analysis or supplier analysis would be adequate to provide site specific CO2 emissions
quantification. The analysis could be verified on an annual basis either by onsite sampling and
analysis or by supplier analysis if required. On-site gas sampling is not an easy task, and
reliance on fuel supplier analyses should be encouraged. In addition, a common sample and
analysis is applicable to all combustion units on the site that combust the particular fuel; use of
common analyses should be specifically provided in the rule. EPA should provide these
flexibility measures as a means to lower compliance and reporting costs.
Response: EPA has revised the Tier 2 and 3 sampling requirements. The use of Tier 2
calculation methods for CO2 emissions has been expanded to include units greater than 250
mmBtu/hr that combust only pipeline natural gas and/or distillate oil. For a homogeneous fuel
such as pipeline natural gas, monthly sampling is not necessary. For other fuels such as oil and
coal, which are delivered in shipments or lots, requiring monthly sampling may be impractical;
new fuel lots or deliveries may not be received on a monthly basis. Therefore, §98.34 has been
revised to require that natural gas be sampled semiannually. For fuel oil and coal, a
representative sampling sample is required for each fuel lot, i.e., for each shipment or delivery.
For other liquid fuels and biogas, quarterly sampling is required. For other solid fuels, excluding
municipal solid waste, weekly composite sampling with monthly analysis is required.
The final rule also clarifies that fuel sampling and analysis data provided by the supplier may be
used in the emission calculations, and that a single analysis of a fuel is applicable to all units at
that facility combusting the fuel.
Commenter Name: Robert D. Bessette
Commenter Affiliation: The Council of Industrial Boiler Owners (CIBO).
Document Control Number: EPA-HQ-OAR-2008-0508-0513.1
Comment Excerpt Number: 32
Comment: §98.33(a)(2) and (3) - Tier 2 and 3 require monthly analyses of fuels. Solid fuels in
many cases are obtained from multiple sources, so that determining monthly analyses would
259
-------
entail considerable cost. EPA should allow for use of representative samples and analyses on a
less frequent basis. A provision should also be included to allow use of common solid fuel
analyses for all units combusting a particular fuel and for supplier-provided analysis.
Response: EPA has revised the Tier 2 and 3 sampling requirements. For fuel oil and coal, a
representative sampling sample is required for each fuel lot, i.e., for each shipment or delivery.
The data from the analysis of this sample may then be used for any units combusting the fuel.
The final rule also clarifies that fuel sampling and analysis data provided by the supplier may be
used in the emission calculations.
Commenter Name: Robert D. Bessette
Commenter Affiliation: The Council of Industrial Boiler Owners (CIBO).
Document Control Number: EPA-HQ-OAR-2008-0508-0513.1
Comment Excerpt Number: 33
Comment: §98.33(b)(5) and §98.36(c)(2). Tier 4 (CEMS) methodology should specifically
address and allow for CEMS installation and monitoring at various potential locations, e.g., in a
common stack for multiple units, in a stack or duct upstream of a stack serving a single unit, in a
common duct serving multiple units. Flexibility in application can reduce the cost of
compliance. §98.36(c)(2) does mention common stacks, but not common duct arrangements.
EPA should clarify in the final rule that other potential arrangements might be used. In addition,
Tier 4 should permit flexibility for sources where CEMS are already located on site. There is no
provision for alternatives or allowing a different Tier for reporting if there is a case where it is
not feasible to upgrade the CEMS, but where the source could use another Tier to ensure
reporting compliance.
Response: EPA acknowledges the commenter's concerns. In the final rule, EPA has added
provisions for the use of CEMS in common stack or duct arrangements to §98.36(c)(2). The
commenter has not provided an explanation of how it might not be feasible to upgrade to CEMS,
making it impossible for EPA to determine whether or not additional flexibility is warranted.
Commenter Name: Robert D. Bessette
Commenter Affiliation: The Council of Industrial Boiler Owners (CIBO).
Document Control Number: EPA-HQ-OAR-2008-0508-0513.1
Comment Excerpt Number: 35
Comment: §98.33(c)(4) references Table C-4, but there is no Table C-4 in the rule.
Response: The provisions in §98.33(c)(4) of the proposed rule have been deleted.
260
-------
Commenter Name: Steven J. Rowlan
Commenter Affiliation: Nucor Corporation (Nucor)
Document Control Number: EPA-HQ-OAR-2008-0508-0605.1
Comment Excerpt Number: 6
Comment: There are substantial differences between GHG and acid rain reduction through
control of SO2 and NOx emissions, the focus of the ARP. These differences suggest that there
should be a different focus between the two programs. One of the most fundamental differences
is that CEMS are not a useful answer to the problem of variability. EPA has suggested that
CEMS are a useful answer to the variability inherent in the steel process. This is less true than
EPA may think. CEMS in the ARP are successful because the basic configuration of the electric
power industry and its units lends itself to CEMS installation and accurate measurement. The
same is much less true of the iron and steel industry. ARP facilities are typically using highly
engineered, fully enclosed, controlled combustion sources designed to evacuate through a stack
with minimal emissions. Iron and steel facilities are working with less-controlled, open process
sources that generally cannot be fully enclosed, that suffer from significant process fugitive
emissions requiring secondary capture, and which are typically semi-controlled for a variety of
other minor sources. Thus, in a typical EAF melt shop, the canopy is controlling not only EAF
emissions, but also partial contributions from preheaters and other apparatus (the rest of these
emissions are typically lost fugitively through roof monitors, doors and similar openings). Thus,
a CEMS is not measuring only EAF operations, but also a number of other sources, plus a large
quantity of ambient influent air through the upper canopy.
Response: See the response to comment EPA-HQ-OAR-2008-0508-0455.1 excerpt 7 and the
response to comment EPA-HQ-OAR-2008-0508-0580 excerpt 10 for EPA's rationale and
approach to the use of CEMS.
This comment pertains to Electric Arc Furnace monitoring under the Iron and Steel subpart. See
the individual source category section of the Preamble and separate comment response document
for Iron and Steel.
Commenter Name: Burl Ackerman
Commenter Affiliation: J. R. Simplot Company
Document Control Number: EPA-HQ-OAR-2008-0508-1641
Comment Excerpt Number: 13
Comment: The rule allows for aggregation of units that have a combined maximum rated heat
input capacity of 250 mmBtu/hr or less. We recommend allowing all units at a facility to be
aggregated together. This will allow the facility to maintain a single fuel meter for each fuel type,
which, in turn, will reduce the regulatory burden and expense and still provide facility level
information as required by the rule.
Response: EPA has dropped the cumulative 250 mmBtu/hr heat input capacity limit on the
aggregation of units. Rather, the 250 mmBtu/hr restriction applies only to the individual units in
the group. Therefore, for reporting purposes, individual units with maximum rated heat input
capacities of 250 mmBtu/hr or less may be aggregated without limit into a single group, provided
261
-------
that the Tier 4 methodology is not required for any of the units, and all units in the group use the
same Tier for any common fuel(s) that they combust. Units with maximum rated heat inputs
greater than 250 mmBtu/hr using Tiers 1, 2, and 3 must report as individual units, unless they
burn the same type of fuel (gas or oil), and the fuel is provided by a common pipe or supply line;
in that case, the owner or operator may opt to use the common pipe reporting provisions in
§98.36(c)(3).
Commenter Name: Steven J. Rowlan
Commenter Affiliation: Nucor Corporation (Nucor)
Document Control Number: EPA-HQ-OAR-2008-0508-0605.1
Comment Excerpt Number: 19
Comment: Nucor supports the recommendation of SMA/SSINA that carbon content testing of
pipeline quality natural gas be eliminated or the burden of providing that information shifted to
the supplier, where one test would cover multiple facilities and eliminates the possibility of
inconsistent carbon content reporting from facilities sharing a common pipeline. See
SMA/SSINA comments, II. A.
Response: EPA has expanded the use of the Tier 2 calculation methodology based on fuel
heating value to units of any size in which the only fossil fuels combusted are pipeline quality
natural gas and distillate oil, in view of the homogeneous nature of these fuels. The final rule
also revises the fuel sampling and analysis requirements for pipeline natural gas such that
sampling and analysis is required only semiannually, and that data provided by the supplier may
be used in the emission calculations.
Commenter Name: Pamela F. Faggert
Commenter Affiliation: Dominion
Document Control Number: EPA-HQ-OAR-2008-0508-1741
Comment Excerpt Number: 8
Comment: For combustion sources affected by Subpart C, we assume the provisions proposed
in 98.33(b)(6), which allows the use of Tier 3 methods if the Tier 4 specified monitoring systems
are not installed by January 1, 2010, would prevent a unit from being required to install Tier 4
monitoring equipment simply to determine applicability. We believe this is appropriate and
request that EPA clarify that the use of Tier 3 methods is allowed to determine initial
applicability if Tier 4 monitoring is not in place. In general, for Subpart C, EPA needs to
explicitly state that if required equipment is not already being collected, analyzed or installed, the
unit or facility may use the next lower Tier to estimate emissions for applicability purposes.
Response: EPA respects the effort that may be required to determine applicability and has
modified the final rule in order to provide clarity. As stated in Subpart A of the final rule, any
method in §98.33(a) may be used to calculate CO2 emissions from general stationary combustion
units for the purposes of applicability determination. EPA expects that a source should be able
to determine applicability without installing new equipment.
262
-------
Commenter Name: Rich Raiders
Commenter Affiliation: Arkema Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-0511.1
Comment Excerpt Number: 36
Comment: EPA should clarify the §98.6 "fuel" definition to indicate that fuel "means solid,
liquid or gaseous combustible materials that is intended to provide substantial heat input, as
measured by HHV value, into a combustion device." EPA has previously recognized that
materials below 5,000 British Thermal Units ("BTU") per pound ("lb") of material, as-fired, do
not contribute significant heat of combustion in a combustion device. (74 Fed. Reg. 54, January
2, 2009, citing 63 Fed. Reg. 33781 and 64 Fed. Reg. 24251, the RCRA Comparable Fuels rule).
In the existing comparable fuels regulations, EPA has addressed how much heating value is
required before a material being combusted beneficially contributes heat generation. EPA's
current scientific review indicates that heating values of materials being combusted below
between 2,600 and 5,000 BTU/lb do not significantly contribute to the heat of combustion. As
heat generation directly relates to combustion GHG emissions, which is EPA's interest in this
proposal, EPA should limit the definition of "fuel" for Part 98 purposes to the RCRA comparable
fuels definition. Below we clarify why the fuel definition should be restricted to materials
intended to be combusted and providing significant heat value to a combustion device. Many
materials described below may be combusted that do not significantly contribute to heating
value, and should not be included as fuels subject to Part 98 monitoring, recordkeeping, and
reporting. The EPA proposed definition of "fuel" includes all materials combusted at a reporting
facility. This definition seems to inadvertently capture the thousands of air pollution control
devices ("APCD") placed into service over the last half century to control volatile organic
compound (" VOC") and other air emissions. Thousands of facilities have installed APCDs to
comply with various EPA requirements, including the following: 1. Prevention of Significant
Deterioration ("P SD") program at 40 CFR 51 and 52, specifically Best Available Control
Technology ("BACT") and Lowest Achievable Emission Rate ("LAER") obligations; 2. NSPS
at 40 CFR 60; 3. National Emissions Standards for Hazardous Air Pollutants ("NESHAP") at 40
CFR 61; 4. MACT at 40 CFR 63 and 65; 5. Reasonably Achievable Control Technology
("RACT") under the National Ambient Air Quality Standards ("NAAQS") programs
implemented by the permitting authorities around the country; and 6. Various state and local air
pollution control requirements. Facilities have installed these devices to bring many airsheds
into NAAQS compliance as the several NAAQS standards have evolved, avoid potential public
health and nuisance issues, and balance the needs of the manufacturing facilities and their
surrounding communities. As these emission control technologies have evolved over the
decades, EPA and the permitting authorities have developed a wide ranging collection of
applicable requirements governing the design and operations of these devices, including
regulating the required emissions loading to the device, the destruction and removal efficiency
("DRE"), and/or outlet emission rates of various materials. These emission control devices
combust the "supplemental" fuel, typically natural gas, and the "vent gas" fuel, the materials
being subjected to emission control. Most emission control devices manage vent gases
containing carbon-bearing materials.
Response: EPA has expanded the list of exempted source categories to include portable
equipment, emergency generators, flares, and units that combust hazardous waste. EPA believes
that the content of the final rule addresses this comment through the revision of §98.33(b)(4) of
263
-------
the final rule, which provides a detailed discussion of the use of the Tier 1 and Tier 2 Calculation
Methodologies. This section clarifies the criteria for applicability of these methodologies. In
response to the comment, the Tier 1 and Tier 2 methodologies shall be used if a unit has a
maximum heat capacity rating of 250 mmBtu/hr or below, or any size if it combusts natural gas
or distallate fuel oil. Therefore, the use of Tier 1 and 2 is linked to the fuels listed in Table C-l
of the rule. It is EPA's intent that reporters, for combustion equipment such as APCDs that
would be subject to Tier 1 or Tier 2 methods, are only expected to report emissions from the
combustion of fuels that are specifically listed in Table C-l. If the fuel is not included in Table
C-l, than an emission calculation is not expected for that fuel type.
Commenter Name: Gary Moore
Commenter Affiliation: Pensacola Plant of Ascend Performance Materials LLC
Document Control Number: EPA-HQ-OAR-2008-0508-0366.1
Comment Excerpt Number: 2
Comment: Offgas streams from various chemical processes are required to be controlled in
flares, thermal oxidizers, boilers or other thermal control devices by various Federal Rules such
as the HON, MON or PSD regulations. These off gas streams typically have low BTU values
and do not independently support combustion. It is unclear from the definitions in§98.6 whether
these off gas streams would be classified as fuels as they are not combustible in the traditional
use of the term. A clarification of the definition of fuel is required. We propose that these off
gas streams which are controlled for regulatory purposes be excluded from the definition of fuel
or that a minimum heat input of 300 BTU/scf be added to the definition of fuel. (This value
comes from EPA's minimum heat input allowed for assisted flares in 40 CFR 60.18(c)(3)(ii).)
Response: EPA has expanded the list of exempted source categories to include portable
equipment, emergency generators, flares, and units that combust hazardous waste. EPA believes
that the content of the final rule addresses this comment through the revision of §98.33(b)(4) of
the final rule, which provides a detailed discussion of the use of the Tier 1 and Tier 2 Calculation
Methodologies. This section clarifies the criteria for applicability of these methodologies. In
response to the comment, the Tier 1 and Tier 2 methodologies shall be used if a unit has a
maximum heat capacity rating of 250 mmBtu/hr or below, or any size if it combusts natural gas
or distallate fuel oil. Therefore, the use of Tier 1 and 2 is linked to the fuels listed in Table C-l
of the rule. It is EPA's intent that reporters, for combustion equipment such as APCDs that
would be subject to Tier 1 or Tier 2 methods, are only expected to report emissions from the
combustion of fuels that are specifically listed in Table C-l. If the fuel is not included in Table
C-l, than an emission calculation is not expected for that fuel type.
264
-------
5. DETAILED GHG EMISSION CALCULATION
PROCEDURES/EQUATIONS IN THE RULE
Commenter Name: Randy Armstrong
Commenter Affiliation: Shell Oil Company
Document Control Number: EPA-HQ-OAR-2008-0508-0651.1
Comment Excerpt Number: 8
Comment: Table C-3 (74 FR 16640-1664 1) Table C-3 in subpart C should include default
methane (CH4) and nitrous oxide (N20) emission factors for flexigas, consistent with the
emissions factors adopted in California. Flexigas is a low Btu gas produced during flexicoking,
where thermal cracking converts heavy hydrocarbons into light hydrocarbons. The applicable
California emission factors for flexigas (referred to a derived gas, low BTU gases) are 0.3 g CH4
per mmBtu and 0.1 g N20 per mmBtu.
Response: EPA has clarified the methodology for calculating CH4 and N20 emissions in the
final rule. Reporting of these emissions is required only for the fuels listed in the CH4 and N20
emission factor table (now Table C-2). Flexigas has not been added to Table C-2, therefore CH4
and N20 emission calculations are not required.
Commenter Name: Leslie Bellas
Commenter Affiliation: National Lime Association (NLA)
Document Control Number: EPA-HQ-OAR-2008-0508-0520.1
Comment Excerpt Number: 51
Comment: In Equation C-6 (40 C.F.R. 98.33), C02 = 5.18 x 10(-7) * Cco2 * Q needs to be
clarified. This formula is similar to the formula listed in Appendix F of Part 75, except that the
conversion factor in Part 75 is 5.7 x 10(-7). NLA requests clarification on why a different
conversion factor was used in the Proposed Rule. Similarly, the unit label for Cco2 is not
correct. It is shown as tons/scf - % C02, which is not mathematically correct. It should be
corrected to show (tons/scf)/% C02 as shown in Appendix F of Part 75. Finally, this Equation
should be clarified so that the % C02 concentration (term Cco2) is not entered into the formula
as a decimal fraction. For example, if the % C02 is 25%, then 25 should be used in the formula,
not 0.25. This is because the conversion factor is in units of (tons/scf)/% CO. This is misleading
as most calculations using a percent call for the decimal fraction representation.
Response: EPA has corrected the unit label for the conversion factor. It now reads
(metric tons/scf/% C02). EPA believes that the value of the conversion factor provided in
Equation C-6 is accurate, given these revised units.
265
-------
Commenter Name: Dan F. Hunter
Commenter Affiliation: ConocoPhillips Company
Document Control Number: EPA-HQ-OAR-2008-0508-0515.1
Comment Excerpt Number: 21
Comment: Industrial and municipal solid waste incinerators appear to be subject to Tier 2
reporting in Subpart C. A HHV value is required in the equation contained in the subpart but no
default value is provided. A default value would be helpful and reduce the risk and burden of
complying with the weekly sampling/monthly composite analyses requirements of §98.34(c).
The risk associated with sampling and analytical errors is large and the liability EPA references
for missed data at 74 FR 16474 make this onerous. We do not believe this is warranted for such
small emission sources as field industrial waste incinerators.
Response: EPA has added default HHV values for tires and municipal solid waste. Also, the
final rule allows Tier 1 for a unit that combusts municipal solid waste but does not produce
steam, if the use of Tier 4 is not required. However, EPA will require Tier 3, for the combustion
of other fuels not listed in Table C-l provided that Tier 4 is not required, fuels are not exempted
from reporting, and the fuels provide at least ten percent of the annual heat input to the unit.
Commenter Name: Keith Adams
Commenter Affiliation: Air Products and Chemicals, Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-1142.1
Comment Excerpt Number: 20
Comment: The proposed rule refers to a section §98.33(a)(l)(iv)(D) while describing the data
needs for employing CO2 CEMS. There is no such §98.33(a)(l)(iv)(D). Perhaps the agency
meant to reference §98.33(e)(3)(ii)(D)?
Response: EPA has corrected this error. The paragraph referenced in the comment
(§98.33(a)(4)(i) in the final rule) now refers to §98.33(a)(4)(iv).
Commenter Name: Dan F. Hunter
Commenter Affiliation: ConocoPhillips Company
Document Control Number: EPA-HQ-OAR-2008-0508-0515.1
Comment Excerpt Number: 20
Comment: For Tier 1 calculations, the Preamble (page 16473) says, "small stationary
combustion units could use a default emission factor and heat rate to estimate emissions, and no
fuel measurements would be required." A similar clarifying statement should added to the
regulatory language in 98.33(a)(1).
Response: EPA believes that the language in §98.33(a)(1) clearly states that units using Tier 1
may use a fuel-specific default CO2 emission factor and fuel consumption from company
records. Fuel flow meters are not required for Tier 1 calculations. EPA has revised the
266
-------
definition of "company records" to provide further clarification as to what types of records are
acceptable for the purposes of determining fuel consumption.
Commenter Name: Michael DiMauro
Commenter Affiliation: Massachusetts Municipal Wholesale Electric Company (MMWEC)
Document Control Number: EPA-HQ-OAR-2008-0508-0580
Comment Excerpt Number: 15
Comment: The formulas enumerated in 98.33 for the calculation of C02 emissions only allow
for the measurement of oil consumption in volumetric units (i.e., gallons). However, certain
types of oil meters measure oil directly as a mass flow (lb/hr) rather than a volume flow
(gal/hour), i. Therefore, Formulas C-l, C-2a, and C-4 should be modified to account for
situations in which oil usage is measured or documented in lbs rather than gallons. Note the
formulas themselves should not require modification, only the Legend, ii. Table C-l should
provide default "high heat values" for oil in units of MMBtu/lb as well as units of MMBtu/gal.
Response: EPA appreciates your comment and has added language to the description of these
equations in §98.33 clarifying that fuel can be expressed as volume or mass flow measurements
for liquid fuels. Also, Table C-l was expanded to include high heat values in units of mass and
volume, depending on the fuel type.
Commenter Name: Michael DiMauro
Commenter Affiliation: Massachusetts Municipal Wholesale Electric Company (MMWEC)
Document Control Number: EPA-HQ-OAR-2008-0508-0580
Comment Excerpt Number: 13
Comment: It is suggested that the language in 98.33(a)(1) and 98.33(a)(2) describing the use of
company records to document fuel usage be made consistent. For Tier I monitoring, the
Proposed rule specifies that CO2 emissions are calculated from "annual fuel consumption"
determined from company records (98.33(a)(1)); while for Tier II monitoring, the Proposed rule
specifies that CO2 emissions are calculated from "the quantity of fuel combusted" as determined
from company records (98.33(a)(2). Since the same type of company records would be used
irrespective of whether the Tier I or Tier II monitoring scheme is applied, it would be preferable
if both provisions employed the same term to describe fuel usage (i.e., either "consumption" or
"combustion") in order to avoid confusion.
Response: The descriptions of the Tier 1 and Tier 2 methodologies in §98.33 were revised to
address the noted inconsistency, and the description of the fuel variable under Equation C-l and
Equation C-2 are consistent. In addition, EPA refers the commenter to the definition of
"company records" in §98.6 of the final rule for additional clarification regarding the use of the
term.
267
-------
Commenter Name: Mary J. Doyle
Commenter Affiliation: BG North America, LLC (BG)
Document Control Number: EPA-HQ-OAR-2008-0508-0714.1
Comment Excerpt Number: 11
Comment: BG supports the continued use of the current part 75 reporting requirements with
this clarification. Proposed section 98.43 requires owners or operators of EGUs to "continue to
monitor and report C02 mass emissions as required under §§75.13 and 75.64 of this chapter."
Section 75.13 could be read to require all EGUs to have installed stack flow monitors or measure
the carbon content of the fuel they burn. That is contrary to existing Part 75 reporting for gas
and oil-fired EGUs. BG asks EPA to clarify that gas and oil-fired units be allowed to continue to
use fuel flow monitors and Carbon based F-factors consistent with Appendix D and Appendix G
of Part 75. Further, EPA should make clear that that gas and oil-fired EGUs will not be required
to install stack flow monitors and conduct carbon sampling of the fuel they are combusting in
connection with the proposed GHG reporting requirement.
Response: The final rule takes into account units that are not in the Acid Rain Program, but are
required to monitor and report Part 75 heat input data under other regulatory programs such as
the Clean Air Interstate Regulation (CAIR). New methods have been added to the four-tiered
C02 emissions calculation methodologies in §98.33(a) for stationary combustion units.
One new method allows oil- and gas-fired units that report heat input data using Appendix D of
Part 75 to use Equation G-4 in Appendix G of Part 75 to calculate hourly CO2 mass emissions,
which are summed over the reporting year. Another allows low mass emitting sources under
§75.19 to calculate CO2 mass emissions using their reported heat input data together with fuel-
specific default CO2 emission factors.
In addition, units that continuously monitor heat input using flow monitors and diluent gas (CO2
or O2) monitors may calculate CO2 mass emissions using the CEMS data together with
appropriate equations from Appendix F of Part 75.
Finally, Subpart D of the final rule provides a CO2 calculation methodology for units that are not
in the Acid Rain Program, but report CO2 mass emissions year-round using Part 75
methodologies. At present, many units subject to the Regional Greenhouse Gas Initiative
(RGGI) in the Eastern U.S. are in this category. For the purposes of Part 98, the CO2 emissions
from these units are calculated and reported the same way as the CO2 emissions from Acid Rain
Program units.
Commenter Name: Dan F. Hunter
Commenter Affiliation: ConocoPhillips Company
Document Control Number: EPA-HQ-OAR-2008-0508-0515.1
Comment Excerpt Number: 22
Comment: For Tier 3 methodology, the Preamble states this methodology is required for a unit
with a maximum heat input capacity of greater than 250 mmBtu/hr. In 98.33(b)), "the Tier 3
Calculation Methodology may be used for a unit of any size, combusting any type of fuel, except
268
-------
when use of Tier 4 is required or elected." This section does not include language requiring the
use of Tier 3 for units greater than 250 mmBtu/hr. ConocoPhillips requests EPA modify the
language in this paragraph to "This methodology is required for liquid and gaseous fossil fuel-
fired units with a maximum heat input capacity greater than 250 mmBtu/hr, and is required for
solid fossil-fuel fired units that are not subject to Tier 4 provisions."
Response: In response to comments, EPA has substantially revised §98.33(b), describing which
tier a reporter is to use. Provided that the use of Tier 4 is not required, EPA has decided to allow
the use of Tier 1 methods for units of any size combusting distillate oil or natural gas, as long as
the owner or operator does not routinely sample the fuel for HHV or receive the results of such a
sampling at a frequency greater than or equal to the minimum frequency listed in §98.34, and
Tier 2 methods for units of any size combusting only pipeline quality natural gas and/or distillate
fuel oil.
Commenter Name: Keith A. Nagel
Commenter Affiliation: ArcelorMittal USA and Severstal North America
Document Control Number: EPA-HQ-OAR-2008-0508-0496.1
Comment Excerpt Number: 8
Comment: Section 98.33(a)(1) allows combustion sources to use less burdensome Tier 1 and
Tier 2 methodologies where default emissions factors and heat input capacities are established
for the type(s) of fuel burned. Those useful approaches can minimize the burden of reporting
emissions from combustion sources while retaining high levels of accuracy. To make these
methodologies available to the many steelmaking sources that combust blast furnace gas and/or
coke oven gas, we request that EPA publish default CO2 emission factors and high heat values
for these process gases in Table C-l as part of the final rule. EPA's Technical Support
Document for the Iron and Steel Industry (the "Steel TSD") already contains information
(including from well-respected international sources) regarding parameters that, while not
perfect, are adequate for inclusion: 1. Page 5 of the Steel TSD indicates that blast furnace gas
has a heating value of approximately 90 Btu/ft3; 2. Page 13 of the Steel TSD indicates that coke
oven gas has a heating value of 500-600 Btu/ft3 (which can be averaged to 550 Btu/ft3); 3. Page
6 of the Steel TSD indicates that the CO2 emission factor for blast furnace gas is 260
MMTCChe/TJ (from IPCC guidelines); and 4. Page 14 of the Steel TSD indicates that the CO2
emission factor for coke oven gas is 0.35 MMTCC^e/mt coke (from IPCC guidelines). The steel
industry stands ready to work with EPA to take whatever steps are needed to finalize default and
high heat values based on this information in time for promulgation in the final rule. Publication
of these factors should be made with the mutual understanding that these values are not the "final
word" on the heating value or emissions factors for these process gases and that future
refinement based on additional study and testing is expected. To the extent individual facilities
disagree with the initial numbers included in the final rule, they would retain the flexibility to
voluntarily use Tier 3 or Tier 4 methodology as appropriate.
Response: EPA has included additional emission factors for Blast Furnace Gas and Coke Oven
Gas in Table C-l of the final rule.
269
-------
Commenter Name: Leslie Bellas
Commenter Affiliation: National Lime Association (NLA)
Document Control Number: EPA-HQ-OAR-2008-0508-0520.1
Comment Excerpt Number: 22
Comment: 40 C.F.R. § 98.33(a)(4)(iv) permits the use of an 02 monitor to meet the CEMS
monitoring requirement for Tier 4. However, the Proposed Rule does not clearly indicate
whether a facility with an 02 monitor would be required to use a CEMS. An 02 monitor can be
used to indicate C02 emissions from combustion emissions because the concentration of both
C02 and 02 is dependent on the amount of air that is available for the combustion of fuels. 02
cannot always, however, indicate the amount of C02 emissions from lime process emissions
because process emissions are not dependent on how fuel is burned. 40 C.F.R. §98.33(a)(4)(iv)
should be clarified to state that sources not allowed to use 02 data as a surrogate for C02 would
not be subject to Tier 4 solely on the basis of having an 02 monitor. 40 C.F.R. §98.33(e)(2)(i),
Equation C-12 refers to measuring the "hourly C02 concentration" and the "hourly stack gas
volumetric flow rate." This Equation should be revised to replace "hourly C02 concentration"
with "hourly average C02 concentration" and "hourly stack gas volumetric flow rate" with
"hourly average stack gas volumetric flow rate" because the source will determine the hourly
average C02 concentration and flow rate based on multiple samples that must be collected in
accordance with Part 60 and 75 requirements.
Response: EPA has revised the final rule to provide clarity concerning gas monitors and Tier 4
requirements. Accordingly, Tier 4 shall be used if the unit meets six conditions, one of which is
"The installed CEMS include a gas monitor of any kind or a stack gas volumetric flow rate
monitor, or both . . ." Further, in §98.33(a)(5)(iv) EPA describes that "an oxygen (02)
concentration monitor may be used in lieu of a C02 concentration monitor to determine the
hourly C02 concentrations in accordance with Equation F-14a or F-14b (as applicable) in
Appendix F to Part 75 ... if the effluent gas stream monitored by the CEMS consists solely of
combustion products (i.e., no process C02 emissions are mixed with the combustion products)."
Commenter Name: Ted Michaels
Commenter Affiliation: Energy Recovery Council (ERC)
Document Control Number: EPA-HQ-OAR-2008-0508-0544.1
Comment Excerpt Number: 6
Comment: 98.33 Calculation Methodologies In Tier 2 Equation C-2b. The "B" ratio is
incorrect and should be revised consistent with the Western Climate Initiative calculation on
which it was based. Revised ratio should be: Ratio of boilers maximum design rated heat input
capacity to its design rated steam output capacity (mmBtu/lb steam). Same comment for
equation C-lOb forN20 and CH4 calculations.
Response: EPA appreciates the comment but believes that the ratio as described under Equation
C-2c is satisfactory as written. The Agency directs the commenter to the definition of
"maximum rated heat input capacity" in §98.6 for further clarification on this matter.
270
-------
Commenter Name: Ted Michaels
Commenter Affiliation: Energy Recovery Council (ERC)
Document Control Number: EPA-HQ-OAR-2008-0508-0544.1
Comment Excerpt Number: 3
Comment: ERC Recommends Using the DOE 1605 (b) Methodology or a Modified Tier 2
Calculation Methodology Consistent with the WCI and DOE GHG reporting rules, EPA's final
MRR should eliminate the requirement that large MWCs use the Tier 4 methodology. The DOE
1605 (b) approach is very similar to the calculation methodology used for reporting annual
emissions of criteria pollutants and HAPs as required by Title V operating permits. Each year
MWC facilities must conduct multiple stack or performance tests (under NSPS Subpart Eb/Cb)
on all MWC units, over several days using EPA Methods 1 - 29. Some MWC facilities stack test
twice per year, as some state requirements are more restrictive than the federal standards. The
DOE approach would take advantage of these extensive testing requirements. The modified Tier
2 methodology would utilize multiple stack results over several days as follows: 1. Calculate
facility average C02 concentration (%), stack gas flow rate (DSCF/Hour) and boiler load or
steam production (Klbs/hour). 2. Calculate a Stack Flow to Load Ratio (SFLR) or DSCF/Hr per
Klbs/hr steam production. The SFLR is analogous to the proposed Tier 2 "B" design heat input
to steam ratio used in Equation C-2b, but could be considered more representative since it is
based on actual test data. 3. Obtain biogenic/non-biogenic C02 fractions using ASTM Methods
D 7459 and D 6866-06a from integrated gas samples collected during stack testing. 4. Use C02
concentration, total steam production and SFLR to calculate MWC unit and facility wide annual
CO2 emissions. The above approach modifies the Tier 2 methodology slightly since actual CO2
concentrations are used (not a fixed emission factor), and mass C02 emissions are calculated
from actual stack gas flow and actual steam production rather than using a fixed design heat
input. Table 2 below summarizes 2008 non-biogenic CO2 emissions from large (i.e., greater
than 250 tpd) MWC facilities calculated in accordance with the proposed alternative
methodology. [See submittal data table provided by the commenter.] Based on the above, a
proposed third equation to Tier 2 Calculation Methodology would be: [See submittal data table
provided by the commenter.] We recommend that the ASTM D6866-06a non-biogenic carbon
fraction results be directly included in the calculation methodology for Municipal Solid Waste
combustion. This will improve transparency in reporting GHG CO2 emissions and eliminate
potential for error in apportioning non-biogenic and biogenic CO2 emission.
Response: See the Preamble, Section II. E., for an explanation of how this rule relates to State
and regional programs, and Section II. D. for the response on how this rule relates to other U.S.
government climate change efforts. EPA appreciates the commenter's suggested adjustment to
the Tier Calculation Methodology, however EPA cannot accommodate each individual
suggestion. Please note that the final rule significantly expands the use of Tier 1 and Tier 2
Calculation Methodologies.
271
-------
Commenter Name: Edward N. Saccoccia
Commenter Affiliation: Praxair Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-0977.1
Comment Excerpt Number: 3
Comment: The proposed rule imposes the Tier 4 calculation methodology on sources meeting
the conditions specified under §98.33(b)(5)(ii). As worded, it appears any one of the (A), (B),
(C), or (D) conditions would result in the Tier 4 method being required. This does not match the
intent expressed in the Preamble to the proposed rule, and summarized in Preamble table C-l. In
particular, Table C-l appears to indicate that Tier 4 is required only for Solid Fossil Fuel fired
units >250 mmBTU/hr (meeting other criteria, as well) and that Gaseous Fossil Fuel fired and
Liquid Fossil Fuel fired combustion units are required to use no more rigorous than Tier 3
methods. The current language of §98.33(b)(5)(ii) would imply any of the conditions described
in §98.33(b)(5)(ii)(A), (B), (C) or (D) trigger the Tier 4 method requirement. We believe the
agency's intent is that all of the conditions described in §98.33(b)(5)(ii)(A), (B), (C) and (D) are
necessary in order to trigger the Tier 4 method requirement. Clarify the requirement to employ
the Tier 4 calculation method. Resolve the apparent discrepancy between the intent to limit Tier
4 to only Solid Fossil Fuel fired combustion units, per Table C-l of the Preamble, with the actual
imposition of Tier 4 described under §98.33(b) (5) (ii). Clarify that in order for Tier 4 to be
required under §98.33(b)(5)(ii), all the conditions under §98.33(b)(5)(ii)(A), (B), (C), and (D)
must be met. Specifically, conditions (A), (B), (C), and (D) should be separated by the word
"and" - absent that, an implied "or" would force this calculation method on many other
combustion units for which it was not intended.
Response: EPA acknowledges the commenter's concerns regarding Tier 4 applicability. EPA
has revised the final rule to clarify that all six criteria must be met before Tier 4 is required.
However, EPA disagrees with suggestions that Tier 4 should only be required if the installed
CEMS include a CO2 monitor. The Tier 4 CEMS requirement is limited to larger solid fossil
fuel units with an existing pollutant CEMS and certified gas monitor or volumetric flow rate
monitor. EPA is requiring the use of CEMS due to the complexity of monitoring solid fuel
consumption and the heterogeneous nature of the solid fuels. Many of these fossil-fuel fired
units with a pollutant CEMS have an existing diluent monitor (O2 or CO2) that can be used to
determine CO2 emissions. EPA's estimates of monitoring costs are averages for a representative
facility and may not represent the actual cost in individual circumstances.
Commenter Name: William C. Herz
Commenter Affiliation: The Fertilizer Institute (TFI)
Document Control Number: EPA-HQ-OAR-2008-0508-0952.1
Comment Excerpt Number: 5
Comment: EPA should revise the NPRM to allow use of Tier 3 calculation methodology for
those units required to use Tier 4 under 40 C.F.R. §98.33(b)(5)(ii) until the unit's first scheduled
shutdown or other routine maintenance outage or turnaround based on regular industry practice.
The NPRM's proposed 40 C.F.R. §98.33(b)(6)(ii) requires all sources to have stack flow
volumetric analyzers and CO2 concentration analyzers installed by Jan. 1, 2011. 74 Fed. Reg. at
16,634. For boiler American Society of Mechanical Engineers (ASME) Section 1 requirements,
272
-------
five-year inspections are required. Combustion sources would be forced to shut down to install
stack flow volumetric analyzers and CO2 concentration analyzers. Facilities should be able to
use Tier 3 for no more than five years, until the facility's scheduled five-year ASME boiler
inspection cycle. This approach would avoid the costs and environmental and safety
implications of an additional shutdown by ensuring that the already-scheduled shutdown will
coincide with the opportunity to install monitoring equipment necessary to comply with Tier 4
calculation methodology.
Response: EPA appreciates your comment and has adjusted the required Tier 4 start date for
units that require CO2 or O2 monitor installations to January 1, 2011 if the monitor cannot be
installed by January 1, 2010. Such units will report Tier 2 or Tier 3 to report for 2010. See
§98.33(b). EPA considers this to be a reasonable amount of time to meet the Tier 4 requirements
while also ensuring that Tier 4 facilities are employing consistent methodologies within a
reasonable timeframe.
Commenter Name: John Piotrowski
Commenter Affiliation: Packaging Corporation of America (PCA)
Document Control Number: EPA-HQ-OAR-2008-0508-1029.1
Comment Excerpt Number: 4
Comment: PCA urges the Agency to limit emission calculations and recordkeeping
requirements to fuel use tracking in combination with internationally accepted GHG calculation
protocols such as the WRI/WBCSD Greenhouse Gas Protocol Calculation Tools and
ICFPA/NCASI Spreadsheets for Calculating GHG Emissions from Pulp and Paper
Manufacturing. The Agency's proposed emission calculation methodologies involving frequent
fuel sampling and analysis, add-on CO2 CEMs, daily process gas analysis, and detailed
requirements for determining GHG releases from industrial wastewater treatment plants and
landfills that are not only onerous, but they depart from existing, defensible and widely accepted
procedures. In addition to being unnecessarily rigorous, the cost of complying with the Agency's
requirements is high and comes at a time when our industry is already reeling from the impact of
a severe and global economic decline. We believe that the Tier 1 requirements, when used in
conjunction with an analytical tool like the ICFPA/NCASI Spreadsheets for Calculating GHG
Emissions from Pulp and Paper Manufacturing will adequately and accurately represent carbon
dioxide emissions from stationary combustion sources regardless of size or type of fuel fired. As
our industry is a major energy consumer, it has been - and continues to be - in our best interest to
carefully track fuel use and fuel cost. Therefore, we employ a number of mechanisms to account
for fuel use as a matter of good business management. However, in the event that the tiered
structure is retained in the rule, direct measurement of fuel higher heating value, carbon content,
and molecular weight, as required by Tiers 2 and 3 should be optional but not required. Also, we
recommend that the 250 MMBtu threshold be based solely on fossil fuel use and exclude
biomass fuels. We object to the Rule's proposal to require the use of CO2 CEMs on stationary
sources with a rated capacity greater than 250 MMBtu/hr for several reasons: First, as cited
above, there are effective alternative options to accurately quantify CO2 emissions for stationary
sources and those methods are workable for sources regardless of rated capacity. Second, we
have power islands configured in a manner where effluent gases from multiple boilers co-mingle
in a common exhaust stack. In this configuration, installing a dedicated CO2 CEMs on one
boiler but not another is problematic particularly if the CEMs sampling probe must be installed
273
-------
prior to a control device. Attempting to analyze raw effluent gases in situ would likely result in
chronic operating, maintenance and data reliability problems that would complicate, if not
compromise, data quality. Third, a common stack configuration would appear to require
dedicated fuel meters on each boiler - something that would require extensive downtime to
install. This kind of project is typically reserved for planned maintenance outages that occur
annually. As we are already past the annual outage period at all of our mills for 2009, the
earliest this work would be done is in 2010 which means that 2011 would be the first year that a
full complement of data would be available. Fourth, the pulp and paper industry is a heavy user
of woody biomass fuel; this is particularly true at integrated facilities. Our company has a
number of large (i.e., > 250 MMBtu/hr heat input) biomass-fired boilers that would be subject to
the proposed C02 CEMs requirement. As the Rule's intent is to quantify and report fossil-fuel
derived CO2 emissions, we believe that requiring the installation of costly CEMs on biomass
boilers for the purpose of quantifying non-reportable biogenic C02 emissions is an unnecessary
expenditure of resources. At the very minimum, large biomass-fired boilers should be exempt
from C02 CEMs monitoring requirements. However, we maintain that the proposed
requirement to install CEMs on any boiler is unnecessary since there are simple, reasonable and
defensible alternative methods available. Again, and we emphasize, CEMs systems (and
ancillary support equipment) are very expensive to install, operate and maintain, particularly at a
time when our industry is under extreme financial duress. These costs are compounded by the
attendant requirements associated with missing data and data reporting requirements associated
with CEMs operation at §98.35 and §98.36. Fifth, our industry frequently routes non-
condensible gases (NCGs) to lime kilns and recovery furnaces for thermal destruction per sector-
related MACT requirements. Proposed Tier 3 requirements impose daily gas analysis on days
when NCGs are utilized. This presents a monumental logistical, analytical and cost burden on
facilities handling NCGs in this fashion. In fact, we find that GHG emissions from the
combustion of NCGs at our kraft mills accounts for less than 0.1% of total facility GHG releases.
The effort associated with daily fuel analysis is grossly disproportional to any presumed data
quality benefit assumed under the Rule. This requirement should be dropped in favor of a fuel
throughput multiplied by a generally accepted emission factor calculation.
Response: See the Preamble, Section II. L., on General Monitoring Requirements for the overall
rationale for methodologies required under this rule, and the response to comment EPA-HQ-
OAR-2008-0508-0909.1 excerpt 4 and EPA-HQ-OAR-2008-0508-0580 excerpt 10 for the
rationale for methodologies required under Subpart C.
EPA disagrees with the commenter's suggestion that Tier 1 should be permitted for all emissions
monitoring. However, EPA has significantly relaxed the Tier requirements. The final rule
significantly expands the use of Tier 1 and Tier 2 Calculation Methodologies. The 250
mmBtu/hr restriction on the use of Tier 2 has been lifted for units that combust natural gas and
distillate oil, in view of the homogeneous nature and low variability in the characteristics of these
fuels. However, the 250 mmBtu/hr unit size cutoff remains for units that combust residual oil
and solid fossil fuel. EPA has also revised the criteria that trigger mandatory use of Tier 3. Tier
3 must be used for units larger than 250 mmBtu/hr, that combust fuels other than pipeline natural
gas and/or distillate oil if Tier 4 is not required, the fuels are not exempted from reporting, and
the fuels provide at least ten percent of the annual heat input to the unit. EPA believes that this
provision will ease the monitoring burden on facilities which co-fire small quantities of waste
liquids or gases along with fossil fuels such as coal.
The mandatory fuel sampling and analysis requirements for traditional fossil fuels have been
relaxed for Tiers 2 and 3. EPA agrees with the commenters that for a homogeneous fuel such as
274
-------
pipeline natural gas, monthly sampling is not necessary. For other fuels such as oil and coal,
which are delivered in shipments or lots, requiring monthly sampling may be impractical; new
fuel lots or deliveries may not be received on a monthly basis. Therefore, §98.34 has been
revised to require that natural gas be sampled semiannually. For fuel oil and coal, a
representative sampling is required for each fuel lot, i.e., for each shipment or delivery. For
other liquid fuels and biogas, quarterly sampling is required. For other solid fuels, excluding
municipal solid waste, weekly composite sampling with monthly analysis is required. For other
gaseous fuels, the daily sampling requirement has been retained, but only for facilities with
existing equipment in place that is capable of providing the data. Otherwise, weekly sampling is
required, which may be postponed in favor of monthly sampling until 2011 if new equipment
must be purchased or if existing equipment must be upgraded to meet the weekly sampling and
analysis requirements.
The final rule clarifies that fuel sampling and analysis data provided by the supplier may be used
in the emission calculations, and that fuel billing meters may be used to quantify fuel
consumption. To simplify the emission calculations in Tiers 2 and 3, averaging of HHV and
carbon content data is permitted if these data are obtained at least at the minimum frequency
specified in §98.34, but less frequently than monthly (see Equation C-2b). However, regardless
of the sampling frequency, the owner or operator must use the results of all available valid fuel
analyses in the emissions calculations.
Fuel flow meters are required for units combusting liquid or gaseous fuels and using Tier 3
reporting, though EPA has clarified that fuel billing meters and any fuel drop tank measurements
based on consensus-based standards may be used. However, EPA has revised §98.34(d) to allow
facilities until January 1, 2011 to calibrate these fuel flow meters. Facilities that operate
continuously with infrequent outages may postpone the initial flow meter calibration until the
next scheduled maintenance outage.
The final rule clarifies the applicability of the Tier 4 methodology. Many commenters were
unsure whether only one or all six of the conditions listed in §98.33 must be met to trigger the
requirement to use CEMS. EPA's intent has always been that a source must meet all six
conditions to require the use of Tier 4. This has been made clear in the final rule text. One of
these conditions is that "the unit combusts solid fossil fuel or municipal solid waste, either as a
primary or secondary fuel." Therefore, units combusting only solid biomass (such as wood)
would not be required to use Tier 4, and units of any size combusting wood, wood waste, or
other solid biomass-derived fuels may use Tier 1 to report emissions.
EPA has clarified the use of common stack reporting for units using CEMS, and has added
common duct provisions. See §98.36(c)(2), which allows the owner or operator to report the
combined emissions from the units sharing the common stack or duct, in lieu of separately
reporting the GHG emissions from the individual units, if the common stack is monitored per
Tier 4. Also, fuel flow meters are not required for Tier 4, and the final rule has been revised to
state that Tier 4 CO2 emissions need not be reported by fuel type. Therefore the owner or
operator would not need to install separate fuel flow meters. The owner or operator will need to
report separately the common stack CO2 emissions from fossil fuel and biomass fuel.
To calculate CH4 and N2O emissions by fuel type, when CEMS (which are not fuel-specific) are
used, the total heat input measured by the CEMS must be apportioned to each fuel type. The
owner or operator should use the best available information (e.g., fuel feed rates, GCV values,
etc.) to do the necessary heat input apportionment.
275
-------
Commenter Name: William C. Herz
Commenter Affiliation: The Fertilizer Institute (TFI)
Document Control Number: EPA-HQ-OAR-2008-0508-0952.1
Comment Excerpt Number: 4
Comment: EPA states in the NPRM Preamble that units will not be required to install
monitoring systems to comply with the NPRM. 74 Fed. Reg. 16,493. However, the NPRM, as
proposed in 40 C.F.R. §98.33(b)(5)(ii), appears to require all combustion sources with any type
of analyzer to add stack gas volumetric flow rate monitors and CO2 concentration analyzers and
report under Tier 4. Several ammonia facilities have analyzers in place but do not have the stack
gas volumetric flow rate monitors and CO2 concentration analyzers required under Tier 4
methodology. Units cannot comply with Tier 4 requirements without installation of stack gas
volumetric flow rate monitors and CO2 concentration analyzers. Such installation would prove
extremely costly (at least $275,000 per unit) and would be necessary at many facilities falling
under this section's requirements. Such a requirement is contrary to EPA's express intent in the
Preamble not to require installation of monitoring systems, but instead allow units to rely on Tier
3 rather than incur the installation expense of new equipment. EPA should clarify that a facility
is not required to report using Tier 4 calculation methodology under the proposed 40 C.F.R.
§98.33(b)(5)(ii) unless that unit meets all of the conditions specified in subparagraphs (A)
through (F) of that section. In the alternative, EPA should include language in 40 C.F.R.
§98.33(b)(5)(ii) clarifying that Tier 4 requirements will not apply to facilities that do not
presently have stack gas volumetric flow rate monitors and C02 concentration analyzers. For
example, under proposed 40 C.F.R. §98.33(b)(5)(iii)(A), units with a maximum rated heat input
capacity of 250 mmBtu/hr or less that do not have stack gas volumetric flow rate monitors and
CO2 concentration analyzers are not required to report under Tier 4. 74 Fed. Reg. at 16,634.
TFI would suggest a similar approach for facilities regulated under 40 C.F.R. §98.33(b)(5)(ii).
As such, TFI recommends the following revision to proposed 40 C.F.R. §98.33(b)(5)(ii):
98.33(b) (5) The Tier 4 Calculation Methodology: (ii) Shall be used for a unit if the unit has
both a stack gas volumetric flow rate monitor and a CO2 concentration monitor. While TFI
would prefer that EPA clarify that units that do not meet all of the conditions specified under 40
C.F.R. §98.33(b)(5)(ii)(A) through (F) may rely on Tier 3 calculation methodology, the above-
recommended revisions to 40 C.F.R. §98.33(b)(5)(ii) would accomplish EPA's stated intent of
not requiring installation of new monitoring equipment.
Response: EPA acknowledges the commenter's concerns regarding Tier 4 applicability. EPA
has revised the rule to clarify that all six criteria specified in subparagraphs (A) through (F) must
be met before Tier 4 is required. Among these criteria is that the unit has a maximum rated heat
input capacity greater than 250 mmBtu/hr. However, EPA disagrees with suggestions that Tier 4
should only be required if the installed CEMS include a CO2 monitor. The Tier 4 CEMS
requirement is limited to larger solid fossil fuel units with an existing pollutant CEMS and
certified volumetric flow rate monitor or gas monitor. EPA is requiring the use of CEMS due to
the complexity of monitoring solid fuel consumption and the heterogeneous nature of the solid
fuels. Many of these fossil-fuel fired units with a pollutant CEMS have an existing diluent
monitor (O2 or CO2) that can be used to determine CO2 emissions. EPA's estimates of
monitoring costs are averages for a representative facility and may not represent the actual cost
in individual circumstances.
276
-------
Commenter Name: Michael S. Dae
Commenter Affiliation: Energy Developments, Inc. (EDI)
Document Control Number: EPA-HQ-OAR-2008-0508-0706.1
Comment Excerpt Number: 4
Comment: Table C-l of Subpart C includes High Heat Values (HHV) for various fuel types.
However, no specific HHV is listed for methane or LFG. The BTU value of methane is well
established at 1,011 BTU/standard cubic foot (scf). Since LFG primarily consists of methane
and carbon dioxide the HHV of LFG can be calculated based on its methane content, EDI
requests that EPA consider adding a HHV for LFG to the Biogas fuel type in Table C-l. This
value should be on the 1,011 BTU/scfm value for methane and the methane content of the LFG.
HHV (mmBTU/scf) = [(1,011 BTU/scf) X (% Methane*/100)] / 1,000,000. Adding the above
proposed calculation to Table C-l could allow LFGTE facilities to calculate CO2 emissions
using the Tier 1 calculation, This would remove the requirement to sample the fuel gas on a
monthly basis to determine HHV. Because the quality of LFG can vary daily based on
operational and atmospheric factors, EDT believes that the proposed method for calculating the
HHV from LFG would provide a more accurate value than that based on a single monthly gas
sample. This method would actually be based on an increased data set and would provide better
representation of the fuel combusted without the resultant sampling and analysis costs.
Response: EPA appreciates your comment and has included default HHV values in Table C-l
for captured methane.
Commenter Name: Vince Brisini
Commenter Affiliation: RRI Energy Inc. (RRI)
Document Control Number: EPA-HQ-OAR-2008-0508-0618.1
Comment Excerpt Number: 9
Comment: As liquid and gaseous fuel quantities are not only measured on a volume basis, US.
EPA should expand its annual CO2 mass emissions formulas for liquid and gaseous fuels to
account for fuel quantities measured on either a volume or mass basis. The equations provided
in Tier 3 for calculating annual CO2 mass emissions for liquid and gas-fired combustion sources
(i.e., Equations C-4 and C-5 of the proposed GHG reporting rule), would only allow for to be
measured on a volume basis. However, companies use fuel flow meters that may directly
measure the volume or mass of the fuel combusted.
Response: EPA appreciates your comment and has allowed mass flow measurements for liquid
fuels by adding the following language to §98.33(b):
"Fuel flow meters that measure mass flow rates may be used for liquid fuels, provided
that the fuel density is used to convert the readings to volumetric flow rates. The density
shall be measured at the same frequency as the carbon content, using ASTM D1298-99
(Reapproved 2005) Standard Test Method for Density, Relative Density (Specific
277
-------
Gravity), or API Gravity of Crude Petroleum and Liquid Petroleum Products by
Hydrometer Method (incorporated by reference, see §98.7)."
Commenter Name: Keith A. Nagel
Commenter Affiliation: ArcelorMittal USA and Severstal North America
Document Control Number: EPA-HQ-OAR-2008-0508-0496.1
Comment Excerpt Number: 29
Comment: Section 98.33(b)(6) allows sources working to install C02 CEMS to defer reporting
until January 1, 2011 and provides that those sources "shall use the Tier 3 Calculation
Methodology in 2010." One primary reason we are considering the potential use of C02 CEMS
at certain sources is because Tier 3 reporting is either technically infeasible or unreasonably
burdensome (absent the changes requested in these comments). Thus, it will not always be
viable to use Tier 3 for the interim CO2 CEMS installation period. Instead of specifying Tier 3
for this interim period, the Proposed Rule should allow sources to use the best available
information.
Response: The final rule requires data collection for calendar year 2010, but has been changed
since proposal to allow use of best available monitoring methods for the first part of 2010. EPA
has clarified in §98.33(b) for those units installing and certifying CEMS to meet Tier 4
requirements, they may use either Tier 2 or 3 in 2010. It should also be noted that there were
substantial revisions to Tiers 2 and 3, and the commenter should revisit these requirements.
Commenter Name: Jeffrey L. Clark
Commenter Affiliation: Environmental Coordinator, Teck Alaska Incorporated
Document Control Number: EPA-HQ-OAR-2008-0508-0142
Comment Excerpt Number: 6
Comment: Monthly analysis of carbon content of fuels seems excessive. Again is EPA being
too precise without being accurate.
Response: The mandatory monthly fuel sampling and analysis requirements for traditional
fossil fuels have been relaxed for Tiers 2 and 3. EPA agrees with the commenter that for a
homogeneous fuel such as pipeline natural gas, monthly sampling is not necessary. For other
fuels such as oil and coal, which are delivered in shipments or lots, requiring monthly sampling
may be impractical; new fuel lots or deliveries may not be received on a monthly basis.
Therefore, §98.34 has been revised to require that natural gas be sampled semiannually. For fuel
oil and coal, a representative sampling is required for each fuel lot, i.e., for each shipment or
delivery. For other liquid fuels and biogas, quarterly sampling is required. For other solid fuels,
excluding municipal solid waste, weekly composite sampling with monthly analysis is required.
For other gaseous fuels, the daily sampling requirement has been retained, but only for facilities
with existing equipment in place that is capable of providing the data. Otherwise, weekly
sampling is required, which may be postponed in favor of monthly sampling until 2011 if new
equipment must be purchased or if existing equipment must be upgraded to meet the weekly
sampling and analysis requirements.
278
-------
The final rule clarifies that fuel sampling and analysis data provided by the supplier may be used
in the emission calculations, and that fuel billing meters may be used to quantify fuel
consumption. To simplify the emission calculations in Tiers 2 and 3, averaging of HHV and
carbon content data is permitted if these data are obtained at least at the minimum frequency
specified in §98.34, but less frequently than monthly (see Equation C-2b). However, regardless
of the sampling frequency, the owner or operator must use the results of all available valid fuel
analyses in the emissions calculations.
Commenter Name: Leslie Bellas
Commenter Affiliation: National Lime Association (NLA)
Document Control Number: EPA-HQ-OAR-2008-0508-0520.1
Comment Excerpt Number: 50
Comment: 40 C.F.R. 98.33(c)(4) refers to Table C-4, but no such table appears in the Proposed
Rule.
Response: In the final rule, language in §98.33 that references Table C-4 has been deleted.
Commenter Name: Lorraine Krupa Gershman
Commenter Affiliation: American Chemistry Council (ACC)
Document Control Number: EPA-HQ-OAR-2008-0508-0423.2
Comment Excerpt Number: 50
Comment: In §98.33(a)(3)(iii), the proposed Tier 3 methodology for a gaseous fuel requires the
use of Equation C-5, which contains the term MVC. MVC is defined as the molar volume
conversion factor and is stated to be equal to 849.5 scf per kg-mole at standard conditions for this
equation and also throughout the rule. However, in §98.6, Definitions, EPA defines the term
"Standard Conditions or Standard Temperature and Pressure" as meaning 60 degrees F and 14.7
psia. Using a temperature of 60° F, molar volume is calculated to be (10.73)(520)/(14.7) = 379.6
scf/lb-mole x 2.2 = 835 scf/kg-mole. Thus, there appears to be a discrepancy between the
standard conditions in the definitions and the standard conditions for the conversion factor in
Equation C-5. It appears EPA may have used a temperature of 68 °F to obtain a molar volume of
849.5 scf/kg-mole. Thus, the molar volume that is required to be used doesn't match with a
standard temperature of 60 °F. EPA could either revise the molar volume to closer to 835 or
revise the definition of Standard Conditions to reflect a temperature of 68 °F.
Response: EPA has revised the definition of "Standard conditions or standard temperature and
pressure (STP)" in §98.6 to mean "68 degrees Fahrenheit and 14.7 pounds per square inch
absolute." Given this revised definition, EPA believes that the value for MVC provided in
Equation C-5 is correct.
279
-------
Commenter Name: Lorraine Krupa Gershman
Commenter Affiliation: American Chemistry Council (ACC)
Document Control Number: EPA-HQ-OAR-2008-0508-0423.2
Comment Excerpt Number: 49
Comment: Calculation of Part 75 F factors should be allowed in Tier 3 as allowed in Tier 4.
Response: EPA has revised the rule to expand the use of Tier 2, which combines measured heat
content with an emission factor similar to an F-factor, to large units greater than 250 mmBtu/hr
that burn natural gas or distillate oil. EPA is providing additional alternative methods to
reporters with units that report heat input data to EPA using Part 75, which allow the use of
Appendix F and Appendix G methods in Part 75.
Commenter Name: Leslie Bellas
Commenter Affiliation: National Lime Association (NLA)
Document Control Number: EPA-HQ-OAR-2008-0508-0520.1
Comment Excerpt Number: 49
Comment: 40 C.F.R. 98.33(a)(l)(4)(i) refers to "(a)(l)(iv)(D) of this section," but NLA was
unable to locate this provision. Did EPA intend to refer to 40 C.F.R. 98.33(a)(4)(i)?
Response: EPA has corrected this error. The paragraph (§98.33(a)(5)(i) in the final rule) now
refers to §98.33(a)(5)(iv).
Commenter Name: Lorraine Krupa Gershman
Commenter Affiliation: American Chemistry Council (ACC)
Document Control Number: EPA-HQ-OAR-2008-0508-0423.2
Comment Excerpt Number: 46
Comment: Stationary fuel combustion source emissions calculation methods require use of
annual fuel consumption from company records. Specific alternative methods of determining
fuel consumption are not spelled out, but it is assumed and hoped that the covered entities would
have considerable flexibility in determining the annual fuel consumption. The following is but
one example of the complications of determining fuel use. For many solid fuel fired units, such
as stoker coal fired boilers and pulverized coal fired boilers utilizing volumetric coal feeders,
there is no way to measure weight rate of coal feed to the boilers. In those cases, alternative
methods of determining heat input and annual fuel consumption need to be used. For example,
the Tier 2 methodology for MSW fired units allows for use of boiler steam output and the
maximum rated heat input to design steam output ratio to determine heat input. A similar
approach could also be used for other solid fuel fired units. Similarly, in cases where byproduct
fuels are fired or co-fired, the covered entity should have latitude to utilize any methods
appropriate for the unit that provide representative determination of CO2 emissions. Providing
flexibility in fuel consumption determination methodology will decrease the cost of the reporting
280
-------
program with an insignificant impact on overall emissions accounting accuracy. It is assumed
that this is EPA's intention based on the reference to relying on company records.
Response: EPA acknowledges the commenter's concerns, and has defined the term "company
records" in §98.6 of the final rule. EPA believes that the revised definition provides appropriate
guidance as to what records a facility may use to determine fuel consumption.
Commenter Name: Leslie Bellas
Commenter Affiliation: National Lime Association (NLA)
Document Control Number: EPA-HQ-OAR-2008-0508-0520.1
Comment Excerpt Number: 32
Comment: 40 C.F.R. 98.33 does not specify whether solid fuel calculations should use
throughputs for "dry" or "as received" fuel. 40 C.F.R. 98.33(a) should be revised to specify that
all fuel calculations should use dry solid fuel throughputs for consistency and more accurate
results.
Response: EPA believes that fuel high heating value calculations should be done on an as-
received basis, and that no additional language is necessary in the rule to clarify this.
Commenter Name: Leslie Bellas
Commenter Affiliation: National Lime Association (NLA)
Document Control Number: EPA-HQ-OAR-2008-0508-0520.1
Comment Excerpt Number: 21
Comment: The proposed definition of "continuous emissions monitoring system" (CEMS) in
40 C.F.R. §98.6 includes those systems that have a gas monitoring system or only a flow
monitor. The definition of CEMS is significant because facilities with CEMS are required to use
the Tier 4 calculation methodology. The Proposed Rule's definition of CEMS is overbroad in
that it could be interpreted to include those facilities that only have a flow monitor or an in-situ
monitor. In-situ systems are used to monitor pollutant gases in the stack without extracting a
stack gas sample. These systems are mounted on the stack and are typically designed to monitor
one pollutant per monitor. Upgrading these systems to monitor other pollutants is not
mechanically possible for many of these systems, especially since different pollutants can require
different methods of detection. Sources with in-situ systems that are required to monitor CO2
could be required to remove the monitor from the stack and send it off-site for upgrades and
calibration, which in the case of at least one of our members would take a minimum of three
months. This would result in the source violating the Title V permit requirements to maintain
and operate the monitor for the original pollutant. In the Preamble, Tier 4 requirements are
based on the source's ability to use the existing CEMS equipment or perform "an appropriate
upgrade of the existing CEMS." The Preamble does not refer to installing a new system, as
would be required for many facilities that have in-situ monitors and not gas extraction monitors.
This leads NLA to conclude that Tier 4 requirements are based on a source's ability to upgrade
existing gas extraction systems by adding new monitoring components. The Proposed Rule's
definition of CEMS is inconsistent with the definition of CEMS found in other EPA regulations,
281
-------
such as 40 C.F.R. §72.2. For example, the definition of CEMS in the Proposed Rule requires
that readings be "recorded" every 15 minutes, while 40 C.F.R. Part 75 requires readings be
"taken" every 15 minutes and the hourly average be recorded for compliance purposes.
Incorporating different definitions in each EPA regulation to describe the same CEMS
equipment will lead to confusion and error on the part of facility operators. The Proposed Rule's
definition of CEMS should be revised to differentiate between monitors that can readily be
upgraded to measure C02 and those that cannot. The Proposed Rule's definition of CEMS
should be based on 40 C.F.R. §72.2, which provides that a CEMS is comprised of six component
parts that sample, analyze, measure and provide a permanent record of emissions for specified
pollutants. [Footnote: Continuous emission monitoring system or CEMS means the equipment
required by part 75 of this chapter used to sample, analyze, measure, and provide, by readings
taken at least once every 15 minutes, a permanent record of emissions, expressed in pounds per
hour (lb/hr) for sulfur dioxide and in pounds per million British thermal units (lb/mmBtu) for
nitrogen oxides. The following systems are component parts included in a continuous emission
monitoring system: (1) Sulfur dioxide pollutant concentration monitor; (2) Flow monitor; (3)
Nitrogen oxides pollutant concentration monitors; (4) Diluent gas monitor (oxygen or carbon
dioxide); (5) A continuous moisture monitor when such monitoring is required by part 75 of this
chapter; and (6) A data acquisition and handling system.] NLA's Proposal and Rationale: NLA
proposes that the definition of CEMS in 40 C.F.R. §98.6 be revised as follows: Continuous
emission monitoring system or CEMS means the total equipment required to sample, analyze,
measure, and provide, by means of readings taken at least once every 15 minutes, a permanent
record of emissions, expressed in pounds per hour (lb/hr) from stationary sources. The following
systems are component parts included in a continuous emission monitoring system: (1) pollutant
concentration monitor; (2) flow monitor; (3) diluent gas monitor when such monitoring is
required by part 75 of this chapter, part 60 of this chapter, or an applicable State continuous
monitoring program; (4) a continuous moisture monitor when such monitoring is required by
part 75 of this chapter, part 60 of this chapter, or an applicable State continuous monitoring
program; and (5) a data acquisition and handling system. NLA proposes that 40 C.F.R.
§98.33(b)(5)(ii)(E) be revised to state: The installed CEMS include a gas monitoring system that
has been certified in accordance with the requirements of part 75 of this chapter, part 60 of this
chapter, or an applicable State continuous monitoring program and is either capable of measuring
CO2 in pounds per hour, or physically capable of being upgraded to measure CO2 in pounds per
hour, in accordance with the requirements of part 75 of this chapter, part 60 of this chapter, or an
applicable State continuous monitoring program. NLA's proposal is consistent with EPA's intent
to require sources to make use of existing equipment and not impose substantial operational
burdens by the need to add an entire gas extraction system. See Preamble, 74 Fed. Reg. at
16,483 (looking for an appropriate upgrade of the CEMS).
Response: EPA disagrees with the commenter's request. The Tier 4 CEMS requirement is
limited to larger solid fossil fuel units with an existing pollutant CEMS or volumetric flow rate
monitor. EPA is requiring the use of CEMS due to the complexity of monitoring solid fuel
consumption and the heterogeneous nature of the solid fuels. Many of these fossil-fuel fired
units with a pollutant CEMS have an existing diluent monitor (O2 or CO2) that can be used to
determine CO2 emissions. Regarding Tier 4 applicability, EPA has revised the rule to clarify
that all six criteria specified in §98.33(b)(4), subparagraphs (A) through (F), must be met before
Tier 4 is required. Among these criteria is the requirement that the installed CEMS include a gas
monitor of any kind or a stack gas volumetric flow rate monitor, or both and the monitors have
been certified, either in accordance with the requirements of 40 CFR Part 75, Part 60 of this
chapter, or an applicable State continuous monitoring program. With respect to the timing for
282
-------
meeting the Tier 4 requirements, EPA refers the commenter to §98.33(b)(5)(ii) which allows a
facility until January 1, 2011 to begin reporting according to the Tier 4 methodology, if all of the
monitors needed to measure C02 mass emissions have not been installed and certified by
January 1, 2010. In this case, a facility may use Tier 2 or Tier 3 to report GHG emissions for
2010
Commenter Name: Leslie Bellas
Commenter Affiliation: National Lime Association (NLA)
Document Control Number: EPA-HQ-OAR-2008-0508-0520.1
Comment Excerpt Number: 30
Comment: The formulae set forth in 40 C.F.R. §98.33(e)(2) regarding how CEMS are used to
calculate C02 emissions from the combustion of biomass or biomass-derived fuel is
inappropriate for sources, such as lime plants that have process emissions. The proposed
formula assumes that if one was to subtract the volume of C02 from fossil fuel combustion from
the total volume of C02, then the remaining C02 would be biogenic. In the case of the lime
industry, the difference between total and combustion emissions would be comprised of biogenic
and process emissions. NLA proposes that the following equation be added to 40 C.F.R.
§98.33(e)(2) to account for sources with process emissions: Total C02 tons - Fossil Fuel C02
tons - Process C02 tons = Biogenic Fuel C02 tons.
Response: EPA acknowledges the concerns and refers the commenter to §98.33(e)(2)(iv) where
it is stated that if a CEMS is being used to measure the combined combustion and process
emissions from a unit that is subject to another subpart of Part 98, then also subtract C02 process
emissions from total C02 emissions to determine biogenic C02 emission.
Commenter Name: Laurie Burt
Commenter Affiliation: Massachusetts Department of Environmental Protection
Document Control Number: EPA-HQ-OAR-2008-0508-0453.1
Comment Excerpt Number: 36
Comment: 98.36(c)(1) EPA allows for grouping of small units. Massachusetts suggests that
EPA specify that sources must use the same tier calculation methodology for a set of grouped
units for a particular type of fuel combusted.
Response: EPA agrees with the comment, and has added language to §98.36(c)(1), clarifying
that aggregated units must use the same tier for any common fuel(s) that they combust.
Commenter Name: Leslie Bellas
Commenter Affiliation: National Lime Association (NLA)
Document Control Number: EPA-HQ-OAR-2008-0508-0520.1
Comment Excerpt Number: 27
Comment: The formulae set forth in 40 C.F.R. §§98.33(a)(2)(iii) and 98.33(c) regarding the
methods for calculating emissions from the combustion of municipal solid waste ("MSW") do
283
-------
not apply to lime plants. The formulae assume MSW is used to produce steam, but lime plants
do not typically produce steam from burning MSW. NLA proposes the following formulae to
calculate emissions from "non-steam" producing facilities: Eq. C-2b would be C02 = 1 x 10"3
*(EF)*(Fuel)p*(HHV)p. Eq. C-lOb would be CH4 or N20 = 1 x 10"3 *(EF)*(Fuel)p*(HHV)p.
(Fuel)p and (HHV)P would use the same definition as Eq. C-2a and C-lOa.
Response: EPA has revised the rule so that Tier 1 may be used for a unit burning municipal
solid waste that does not produce steam, provided that Tier 4 is not required. A default C02
emission factor and heat content for municipal solid waste has been added to Table C-l for this
purpose. Also in the final rule, default factors for municipal solid waste are provided in the
revised Table C-2, therefore reporting of CH4 and N20 emissions is required.
Commenter Name: Linda Farrington
Commenter Affiliation: Eli Lilly and Company (Lilly)
Document Control Number: EPA-HQ-OAR-2008-0508-0680.1
Comment Excerpt Number: 26
Comment: Upon review of the Preamble, proposed rule §98.33(b), and the Subpart C Fact
Sheet, Lilly noticed several inconsistencies that make it very difficult to determine when the Tier
4 emission calculation methodology is required and when it is optional. Lilly believes the
decision tree in the Subpart C Fact Sheet can be a very useful tool, provided it is consistent with
the language in the rule itself. Lilly offers the following suggestions for improving the language
in §98.33(b)(5). a. The final rule should not require C02 CEMS (Tier 4) on a stationary
combustion source merely because another type of CEMS (e.g., TOC, NOx, CO) already exists.
Lilly believes the use of fuel flow measurement and fossil fuel emission factors provide emission
estimates of sufficient accuracy for a reporting rule. The use of Tier 4 should not be required,
but included as a voluntary emission methodology for units that may have existing C02 CEMS.
At a minimum, the Tier 4 methodology should only be required for very large solid fuel
combustion sources (e.g. > 250 mmBTU/hr). b. An applicability table, similar to the one
included in the Preamble, should be incorporated into the final rule. c. The criteria listed in
§98.33(b)(5)(ii) and (iii) should include the words "AND" or "OR" as appropriate to clearly
convey the Agency's intent with respect to multiple applicability criteria. Is Tier 4 required only
if a unit meets all of the listed criteria? Or is Tier 4 required whenever a unit meets any one of
the criteria listed?
Response: EPA acknowledges the commenter's concerns regarding Tier 4 applicability. EPA
has revised the rule to clarify that all six criteria specified in subparagraphs (A) through (F) must
be met before Tier 4 is required. However, EPA disagrees with suggestions that Tier 4 should
only be required if the installed CEMS includes a CO2 monitor. The Tier 4 CEMS requirement
is limited to larger solid fossil fuel units with an existing pollutant CEMS or volumetric flow rate
monitor. EPA is requiring the use of CEMS due to the complexity of monitoring solid fuel
consumption and the heterogeneous nature of the solid fuels. Many of these fossil-fuel fired
units with a pollutant CEMS have an existing diluent monitor (O2 or CO2) that can be used to
determine CO2 emissions. EPA's estimates of monitoring costs are averages for a representative
facility and may not represent the actual cost in individual circumstances.
284
-------
Commenter Name: Keith A. Nagel
Commenter Affiliation: ArcelorMittal USA and Severstal North America
Document Control Number: EPA-HQ-OAR-2008-0508-0496.1
Comment Excerpt Number: 26
Comment: Section 98.33(b)(5) requires clarification. Specifically, this section should be
amended to clearly provide that all six criteria set forth in subsections (A) - (F) must be met to
trigger obligatory Tier 4 monitoring. Although this section was apparently meant to establish a
six-part test for triggering Tier 4 monitoring, as currently drafted, the six requirements are stated
independently. The Preamble is also unclear on this point. While most of the relevant Preamble
text apparently assumes that sources must meet all six criteria to trigger Tier 4 monitoring, it also
contains the unqualified statement that "[t]he Tier 4 method, and the use of CEMS (with any
required monitor upgrades), is required for solid fossil fuel-fired units with a maximum heat
input capacity of greater than 250 mmBtu/hr. ..." 74 Fed. Reg. at 16483. EPA should clarify
§98.33(b)(5) by inserting semicolons between each lettered requirement (instead of periods) and
by adding the word "and" after §98.33(b)(5)(E). The Preamble to the final rule should also
expressly acknowledge this clarification and confirm that all six requirements must be met
before any obligation for Tier 4 monitoring accrues.
Response: EPA acknowledges the commenter's concerns regarding Tier 4 applicability. EPA
has revised the final rule to clarify that all six criteria must be met before Tier 4 is required.
Commenter Name: Leslie Bellas
Commenter Affiliation: National Lime Association (NLA)
Document Control Number: EPA-HQ-OAR-2008-0508-0520.1
Comment Excerpt Number: 25
Comment: To the extent that sources are required to install CEMS, they should have sufficient
time to install and certify the equipment. The requirement in 40 C.F.R. §98.33(b)(6)(ii) to install
and certify CEMS by January 1, 2011 may not be achievable given the need to select, deliver,
engineer, and install and certify the equipment. Installation of CEMS may also be delayed due to
the potential for increased demand for equipment and stack testing consultants created by this
nationwide GHG reporting rule. Revise 40 C.F.R. §98.33(b)(6)(ii) to require installation and
certification of CEMS by January 1, 2012.
Response: The final rule requires data collection for calendar year 2010, but has been changed
since proposal to allow the use of best available monitoring methods for the first part of 2010.
EPA acknowledges the concerns of the commenters and has clarified the rule for those units that
must upgrade their existing CEMS to meet Tier 4 requirements. If all the monitors needed have
not been installed and certified by January 1, 2010, they may use either Tier 2 or 3 in 2010.
285
-------
Commenter Name: Keith Adams
Commenter Affiliation: Air Products and Chemicals, Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-1142.1
Comment Excerpt Number: 24
Comment: The proposed rule offers an equation for calculating the contribution of C02
emissions from flue gas desulfurization sorbents, equation C-l 1, which does not appear to be
dimensionally (units) correct. Specifically, the "R" term in the equation appears to be incorrectly
defined. Insure the definitions of terms for equation C-l 1 are dimensionally correct.
Response: EPA has corrected this error in the final rule. The R term has been redefined as
"1.00, the calcium-to-sulfur stoichiometric ratio."
Commenter Name: Leslie Bellas
Commenter Affiliation: National Lime Association (NLA)
Document Control Number: EPA-HQ-OAR-2008-0508-0520.1
Comment Excerpt Number: 23
Comment: The method to calculate hourly emissions proposed in 40 C.F.R. §98.33(a)(4)(v),
Equations C-6 and C-7, and 40 C.F.R. §98.33(e)(2)(i), Equation C-12, appears to be inconsistent
with Part 75, and may understate emissions during partial hours of operation. The rule requires
sources to calculate the mass and volume of C02 emitted each hour by multiplying the C02
emission rates and hourly flow rates by the fraction of the hour that the source was in operation.
Because the downtime will already be accounted for in the "hourly average emission rate," or
"hourly average C02 concentration," there is no need to multiply the hourly average by operating
time for that hour. The "Example of EPA's Proposed Tier 4 C02 Emissions Calculation
Method" demonstrates that the proposed calculation method understates the emissions for any
partial hours of operating time. [See Attachment 7 of DCN: EPA-HQ-OAR-2008-0508-0520.1
for example of Tier 4 calculation] Revise 40 C.F.R. §98.33(a)(4)(v), Equations C-6 and C-7, and
40 C.F.R. §98.33(e)(2)(i), Equation C-12 to delete the requirement to multiply C02 emission
rates and hourly flow rates by the fraction of the hour that the source was in operation. NLA
proposes that total emissions be calculated by summing the hourly averages during operating
times throughout the year to be consistent with Parts 60 and 75.
Response: EPA appreciates your support and thanks you for your comment. The discrepancy
has been reconciled in the final rule.
Commenter Name: Dan F. Hunter
Commenter Affiliation: ConocoPhillips Company
Document Control Number: EPA-HQ-OAR-2008-0508-0515.1
Comment Excerpt Number: 23
Comment: The regulatory language (98.33(b)(5))does not clearly communicate the criteria
requiring Tier 4 methodology. The Preamble discussion does a much better job clarifying the
286
-------
requirements. According to the Preamble, Tier 4 is required for: 1. Units with a maximum rated
heat input capacity of greater than 250 mmBtu/hr, or greater than 250 tons/day of MSW, AND 2.
The unit combusts solid fuel or MSW, AND 3. The unit has operated for more than 1,000 hours
in any calendar year since 2005, AND 4. The Unit has installed CEMS that are required by an
applicable federal or state regulation or the unit's operating permit. Add clarification to
§98.33(b)(5)(ii)(D) and (E) to indicate whether the "installed CEMS" are any type of CEMS (i.e.
criteria pollutant CEMS or C02 CEMS) or a specific type of CEMS (e.g. C02 CEMS).
ConocoPhillips recommends changing the regulatory language to clearly describe the conditions
requiring the use of Tier 4 methodology.
Response: EPA acknowledges the commenter's concerns regarding Tier 4 applicability. EPA
has revised the rule to clarify that all six criteria must be met before Tier 4 is required. EPA has
also clarified that "the installed CEMS include a gas monitor of any kind or a stack gas
volumetric flow rate monitor, or both..."
Commenter Name: Leslie Bellas
Commenter Affiliation: National Lime Association (NLA)
Document Control Number: EPA-HQ-OAR-2008-0508-0520.1
Comment Excerpt Number: 31
Comment: Tables C-l and C-2 in 40 C.F.R. §98.33 do not contain default values for landfill
gas. NLA proposes that landfill gas should be added to tables C-l and C-2 in 40 C.F.R. §98.33
so that a facility using landfill gas can use Tiers 1 or 2 for calculating emissions. The use of
landfill gas as fuel prevents the release of methane to the atmosphere, and should be encouraged.
Response: EPA has added landfill gas to Table C-l as "Biogas (Captured methane)."
Commenter Name: Traylor Champion
Commenter Affiliation: Georgia-Pacific, LLC (GP)
Document Control Number: EPA-HQ-OAR-2008-0508-0380.1
Comment Excerpt Number: 21
Comment: Tier 4 adjustment for biogenic fuels must be improved. If EPA ultimately decides
to retain current Tier 4 methodology as presented in the proposed rule, the adjustment required
for combination boilers firing both fossil and biofuels should be modified to allow the use of the
Tier 1 calculation methodology for biogenic CO2 emissions rather than using an annual F-factor
adjustment for the fossil fuel component. EPA has allowed the use of Tier 1 methodology for
calculation of CO2 from biomass and other biogenic fuels from all sizes of combustion units and
it seems logical that this same methodology should be used to determine the CO2 emissions from
combination boilers that fire solid fossil fuel and biogenic fuels. Reporters would then only have
to subtract the amount of biogenic CO2 from the amount of total CO2 determined by the CEMS
and flow meter to obtain that portion of emissions resulting from combustion of fossil fuels.
Estimation of emissions using a fossil fuel F-factor and amount of fossil fuel burned merely to
determine the amount of biogenic fuel seems unnecessarily complex when a straightforward
calculation of the biogenic fuel is available. In the Technical Support Document for the Pulp and
287
-------
Paper Sector (P&P TSD), EPA outlines a Tier 5 methodology to be used to determine biogenic
CO2 emissions when a CEMS is in place on a boiler co-firing biomass and fossil fuels.
However, this methodology is excluded from the rule. EPA should specifically identify and
allow for use of the Tier 5 method for combination boilers co-firing biomass and fossil fuels
within the rule language itself.
Response: In the Technical Support Document for Subpart AA Pulp and Paper Plants, EPA
requested comment on using a fuel-steam balance approach to calculate CO2 emissions from
biogenic fuels. EPA has received numerous comments endorsing this approach, particularly with
the use of biogenic fuels.
While EPA has allowed the use of Equation C-l (Tier 1) to calculate biogenic CO2 emissions
where the biomass consists of wood, wood waste, or other biomass-derived solid fuels (see Table
C-l), and the mass of biogenic fuel combusted can be accurately quantified, and the use of Tier 2
methods for certain gaseous and liquid biofuels, EPA does not believe that these methods are
appropriate for all situations where biogenic fuels are combusted. Because of the variability of
certain types of biofuels, EPA believes that it may be more appropriate to quantify biogenic
emissions from combination boilers using fossil fuel F-factors and the amount of fossil fuel
burned. EPA believes that the method provided in §98.33(e) is sufficient for calculating
biogenic emissions from combination boilers, and that it is not necessary to include the Tier 5
methods from the Pulp and Paper TSD. However, EPA has added some flexibility to §98.33(e):
the use of ASTM Methods D7459-08 and D6866-06a to determine biogenic CO2 emissions has
been expanded to include the combustion of other biogenic fuels besides municipal solid waste.
The commenter should also consult §98.33(e)(6) and Equation C-l5 for an additional option
specifically targeted to the pulp and paper industry.
Commenter Name: Traylor Champion
Commenter Affiliation: Georgia-Pacific, LLC (GP)
Document Control Number: EPA-HQ-OAR-2008-0508-0380.1
Comment Excerpt Number: 20
Comment: Tier 2 requirement of monthly HHV and Tier 3 requirement of monthly carbon
content testing is unnecessary. The monthly measured HHV requirement of the Tier 2
calculation methodology and the monthly measured carbon content requirement of Tier 3 are
unnecessary and costly. As noted above, over the years industry has developed a large body of
data on HHV and emission factors for common fossil fuels, and additional testing of HHV and
carbon contents will not improve that database further. If default emission factors and HHVs are
given in Tables C-l or C-2, reporters should be able to use these data for the entire facility
regardless of the size and type of the individual combustion unit. Where these data are not given
in Tables C-l or C-2, reporters should be allowed to develop a "facility-specific default" value
for the particular parameter for use in calculating emissions. Monthly measurements are
excessive, costly, and unnecessary.
Response: The mandatory monthly fuel sampling and analysis requirements for traditional
fossil fuels have been relaxed for Tiers 2 and 3. EPA agrees with the commenters that for a
homogeneous fuel such as pipeline natural gas, monthly sampling is not necessary. For other
fuels such as oil and coal, which are delivered in shipments or lots, requiring monthly sampling
288
-------
may be impractical; new fuel lots or deliveries may not be received on a monthly basis.
Therefore, §98.34 has been revised to require that natural gas be sampled semiannually. For fuel
oil and coal, a representative sampling is required for each fuel lot, i.e., for each shipment or
delivery. For other liquid fuels and biogas, quarterly sampling is required. For other solid fuels,
excluding municipal solid waste, weekly composite sampling with monthly analysis is required.
For other gaseous fuels, the daily sampling requirement has been retained, but only for facilities
with existing equipment in place that is capable of providing the data. Otherwise, weekly
sampling is required, which may be postponed in favor of monthly sampling until 2011 if new
equipment must be purchased or if existing equipment must be upgraded to meet the weekly
sampling and analysis requirements.
The final rule clarifies that fuel sampling and analysis data provided by the supplier may be used
in the emission calculations, and that fuel billing meters may be used to quantify fuel
consumption. To simplify the emission calculations in Tiers 2 and 3, averaging of HHV and
carbon content data is permitted if these data are obtained at least at the minimum frequency
specified in §98.34. If the results of fuel sampling are received monthly or more frequently, the
weighted annual average high heat value shall be calculated using Equation C-2b. If the results
of fuel sampling are received less frequently than monthly, then the annual average HHV shall
be calculated using the arithmetic average HHV for all valid samples for the year. However,
regardless of the sampling frequency, the owner or operator must use the results of all available
valid fuel analyses in the emissions calculations.
Commenter Name: Angela Burckhalter
Commenter Affiliation: Oklahoma Independent Petroleum Association (OIPA)
Document Control Number: EPA-HQ-OAR-2008-0508-0386.1
Comment Excerpt Number: 20
Comment: In the proposed rule, under Subpart C, it is confusing as to which Tier calculation
method a reporter should use. In the Preamble, EPA provides Table C-l that clearly outlines
which method is to be used based on the fuel being used and the combustion unit size. We
recommend that this Preamble Table be included in the rule to clearly outline what calculation
method is to be used.
Response: EPA acknowledges the commenter's concerns, and has substantially revised
§98.33(b) in the final rule, relaxing tier and calculation method applicability. Though EPA has
not incorporated a table such as Table C-l from the Preamble into the final rule, the Agency
believes that the revised language makes it clear which Tier calculation method(s) a reporter may
use. The revised rule also adds considerable flexibility, allowing more reporters to use the lower
tiers.
289
-------
Commenter Name: Niki Wuestenberg
Commenter Affiliation: Republic Services, Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-0557.1
Comment Excerpt Number: 15
Comment: Republic request clarification on EPA's requirement of using the Tier 4 calculation
under s. 98.33(b)(5)(ii). Currently this section would require the use of Tier 4 calculation of a
unit if any of the 6 subheadings meet the requirements. This is concerning because it will impact
all landfill gas projects in the U.S. Specifically landfill gas to energy projects would be impacted
under the subheading (C) of this section if a unit has operated for more than 1,000 hours in any
calendar year since 2005 and would therefore be required to perform a Tier 4 calculation. This
would require installing continuous emissions monitoring equipment on all the stacks of each
emission unit which is currently not required under existing permits for these facilities. We
believe existing regulations under the NSPS JJJJ which require performance testing on stationary
electrical generation engines at an interval of every 8760 hours or 3 years of operation is
sufficient testing. Further these emissions are from a biogenic source which we believe should
not be included as stated previously. The ability for these sources to install the necessary
equipment by 2011 will be difficult and an unnecessary burden.
Response: EPA acknowledges the commenters' concerns regarding Tier 4 applicability, and has
revised the rule to clarify that all six criteria must be met before Tier 4 is required. The
commenter is also referred to §98.33(b) which allows for the use of Tier 1 methodology for a
unit of any size, provided that the fuel is exclusively solid, gaseous, or liquid biomass fuels listed
in Table C-l
The final rule requires data collection for calendar year 2010, but has been changed since
proposal to allow use of best available monitoring methods for the first part of 2010.
Commenter Name: Steven D. Meyers
Commenter Affiliation: General Electric Company (GE)
Document Control Number: EPA-HQ-OAR-2008-0508-0532.1
Comment Excerpt Number: 15
Comment: GE has found confusing regulatory language at Section 98.33(b)(5)(ii) that lists the
circumstances under which the Tier 4 calculation methodology (CEMS) must be used at fuel
combustion sources, which are listed in sub-paragraphs A - F. The proposal does not indicate
whether these sub-paragraphs apply together or separately. Because absurd results would occur
if each paragraph represented an independent circumstance for which CEMS would be required,
and because the word "or" does not appear, GE assumes that EPA intends CEMS to be required
only if all of the circumstances are present. For example, if each sub-paragraph indicated an
independent requirement for CEMS, a CEMS would apply to any fuel combustion unit of any
size if it operated for more than 1,000 hours per year. Including Table C-l in the finally
promulgated rule would help but clearness in the language is paramount.
Response: EPA acknowledges the commenter's concerns regarding Tier 4 applicability. EPA
has revised the rule to clarify that all six criteria must be met before Tier 4 is required.
290
-------
Commenter Name: Michael E. Van Brunt
Commenter Affiliation: Covanta Energy Corporation
Document Control Number: EPA-HQ-OAR-2008-0508-0548.1
Comment Excerpt Number: 14
Comment: In §98.33(b)(6)(ii), the Proposed Rule allows Tier 3 methods to be used until 2011
for those facilities that will need to add CO2 and/or flow CEMS in order to comply with the
regulation. The Tier 3 methodology requires monthly direct measurements of fuel carbon
content, which would require extremely large samples in order to be representative for MSW.
The Tier 2 methodology, already accepted for smaller MSW units, should be allowable in the
interim. Furthermore, given the expected date of release of the final regulation, we propose that
interim reporting be allowed up to the 2012 inventory year.
Response: The final rule requires data collection for calendar year 2010, but has been changed
since proposal to allow use of best available monitoring methods for the first part of 2010. EPA
acknowledges the concerns of the commenters, and has clarified the rule for those units that must
upgrade their existing CEMS to meet Tier 4 requirements. If all the monitors needed have not
been installed and certified by January 1, 2010, they may use either Tier 2 or 3 in 2010.
Commenter Name: Lloyd Stone
Commenter Affiliation: Westlake Chemical Corporation
Document Control Number: EPA-HQ-OAR-2008-0508-0442.1
Comment Excerpt Number: 12
Comment: 98.34(c) and (d): Affected sources should have the ability to use a gas
chromatograph to calculate the carbon content and molecular weights just as it is allowed in
§98.244(b)(3).
Response: EPA agrees with the comment and has added the option to determine HHV, carbon
content, and molecular weight of gaseous fuels using chromatographic analysis. See §98.34 of
the final rule.
Commenter Name: Kerry Kelly
Commenter Affiliation: Waste Management (WM)
Document Control Number: EPA-HQ-OAR-2008-0508-0376.1
Comment Excerpt Number: 40
Comment: 98.33(e)(3) MSW Combustion - The calculations for MSW combustion focus on
biogenic CO2 which is not considered a GHG gas by IPCC or in any GHG reporting convention
as explained above on our Section VI. Non-biogenic CO2 or Anthropogenic only is included in
total CC^e emissions. Since only non-biogenic CO2 is included in CC^e total, Section
98.33(e)(5) should be revised to include calculation of non-biogenic CO2 emissions derived from
ASTM D7459-08 and D6866-06a methods. Non-biogenic fraction is 1- biogenic fraction as
291
-------
reported with ASTM D6866 results. If biogenic or biomass fraction is 0.30 then non-biogenic
fraction in 1- 0.30 or 0.70. Note also the biogenic fraction of 0.30 used in the example is
incorrect. The national biogenic C02 average fraction for MSW combustion is approximately 60
- 70% (or 0.60 - 0.70).
Response: See the response to comment EPA-HQ-OAR-2008-0508-0690.1 excerpt 1
corresponding to Section II. of the Preamble, and the response to comment EPA-HQ-OAR-2008-
0508-0631.1 excerpt 71 corresponding to Subpart C for additional explanation of the reporting of
biogenic C02 emissions.
EPA has not revised the calculation method for biogenic/non-biogenic fractions. The end result
is the same in either case.
Commenter Name: Rechelle Hollowaty
Commenter Affiliation: Tyson Foods, Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-0379.1
Comment Excerpt Number: 11
Comment: As with annual emission inventories or air construction and operating permits, most
emissions rates submitted are based off of AP-42 or FIRE emissions factors derived either
fuel/unit specific or process specific. The emission factors for GHG pollutants currently come
from the same locations as criteria pollutant emissions factors. The derived emissions factors
have been used as a means of determining state emission fees as well as allowing facilities to
obtain PSD permits. If these derived factors have been good enough to sustain the environment
and in many cases used as a means to continue to improve the environment then the GHG
emission factors should sustain the reporting requirements as well. Over time as facilities are
required to further show compliance through potential permitting, stack testing can be requested
and better data developed. EPA has no basis to consider that the existing emission factors are
not worthy of use at this time.
Response: For consistency in reporting to this rule, EPA requires the use of the tier methods for
calculating CO2 based on unit size and fuel type combusted. The default emission factors
provided by EPA have been developed for the national greenhouse gas inventory and other
greenhouse gas programs. EPA believes that its approach is consistent with the objective of this
program to collect consistent greenhouse gas data from all affected reporters.
Commenter Name: Gary Moore
Commenter Affiliation: Pensacola Plant of Ascend Performance Materials LLC
Document Control Number: EPA-HQ-OAR-2008-0508-0366.1
Comment Excerpt Number: 7
Comment: Should the Agency determine that site specific emission factors are required to be
determined for any fuels not listed in Table C-3, more specific guidance must be provided rather
than "subject to the approval of the Administrator, develop site-specific CH4 and N2O emission
factors, based on the results of source testing." Stack testing is expensive and some older boilers
292
-------
may not have stack sampling facilities installed making it potentially difficult for what the
Agency acknowledges as relatively small emissions on a CC^e basis. Guidance on what the
Administrator would be looking for and methodologies to employ when having to deal with co-
firing of fuels due to technical (such as off gases being introduced into a boiler or other
combustion device that do not independently supporting combustion) or permitting issues.
Response: In response to the comment, EPA has revised the default emission factors needed to
calculate CH4 and N2O emissions, adding many of the emission factors suggested by
commenters. EPA has also clarified in the final rule that only CH4 and N20 emissions from
combustion of those fuels listed in Table C-2 (formerly C-3) of Subpart C are required to be
reported. Further, reporting of CH4 and N20 emissions is not required for fuels that are used
exclusively for unit startup or ignition.
Commenter Name: Paul Dubenetzky
Commenter Affiliation: KERAMIDA Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-0419.1
Comment Excerpt Number: 6
Comment: Reconcile the difference in the CO2 emission factor for #2 fuel oil combustion of
73.1 kg CCVmmBtu listed in 40 CFR 98, Subpart C, Table C-l (74 FR 16640) with TCR's
emission factor of 73.15 kg C02/mmBtu as found in the TCR's General Reporting Protocol v. 1.1
Table 12.1 U.S. Default Factors for Calculating CO2 Emissions from Fossil Fuel Combustion:
(http://www.thecli.rn. ateregi stry. org/d. ownloads/GRP. pdf).
Response: Tables C-l and C-2 provide emission factors. In determining factors, EPA has used
the general approach of assigning emission factors based on higher heating values of the fuels.
EPA has taken default emission factors from the U.S. inventory or the IPCC, and refers the
commenter back to TCR for an explanation of the source of data provided in that program.
Commenter Name: Gary Moore
Commenter Affiliation: Pensacola Plant of Ascend Performance Materials LLC
Document Control Number: EPA-HQ-OAR-2008-0508-0366.1
Comment Excerpt Number: 5
Comment: Should off gas burned in control devices and residue removed in burnout furnaces
be determined to be fuels under the rule, the proposed rule needs to clarify emission factors for
CH4, and N2O. Currently in §98.33(c)(4) reads: "If, for a particular type of fuel, default CH4
and N2O emission factors are not provided in Table C-4 of this subpart, the owner or operator
may, subject to the approval of the Administrator, develop site-specific CH4 and N2O emission
factors, based on the results of source testing." The use of the word "may" in the proposed rule
introduces some ambiguity as to the intent of this paragraph. In the Preamble to the rule on page
16485 it states: "As described previously, EPA is allowing simplified emissions calculation
methods for CH4 and N2O. The annual CH4 and N2O emissions would be estimated using EPA-
provided default emission factors and annual heat input values." "A CEMS methodology was
not selected for measuring N2O primarily because the cost impacts of requiring the installation
293
-------
of CEMS is high in comparison to the relatively low amount of N20 emissions (even on a C02e
basis) that would be emitted from stationary combustion equipment." The amount of "other"
types of fuels combusted on a national level is likely to be small relative to the amount of listed
fuels and with the Agency acknowledging that for stationary combustion CH4 and N20
emissions are small relative to C02 emissions does this mean that the Agency makes reporting
the CH4 and N2O emissions optional? If emissions are required to be reported, the Agency
could propose the use of emission factors from the fuel closest to the "other" fuel being
combusted to estimate the CH4 and N2O emissions.
Response: EPA has clarified in the final rule that only CH4 and N2O emissions from
combustion of those fuels with default factors listed in Table C-2 (formerly C-3) of Subpart C
are required to be reported. Further, reporting of CH4 and N2O emissions is not required for
fuels that are used exclusively for unit startup or ignition.
Commenter Name: Paul Dubenetzky
Commenter Affiliation: KERAMIDA Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-0419.1
Comment Excerpt Number: 5
Comment: With respect to General Stationary Fuel Combustion, KERAMIDA suggests that the
U.S. EPA: 1. Maintain the rule's general approach of assigning emission factors to fuels based
on their heat value or carbon content and not based on the type of equipment the fuel is
combusted (40 CFR 98, Subpart C, Table C-l, 74 FR 16639).
Response: In response to the comment, EPA appreciates the consideration given to the general
approach of assigning emission factors based on higher heating values of the fuels. EPA has
maintained this approach and these emission factors appear in Table C-l and C-2.
Commenter Name: Laurie Zelnio
Commenter Affiliation: Deere & Company
Document Control Number: EPA-HQ-OAR-2008-0508-0355.1
Comment Excerpt Number: 3
Comment: Deere submitted a question to the EPA regarding the requirement to use a CEMS to
calculate carbon dioxide (CO2) emissions from stationary sources. We received a response to
our inquiry that a facility must use CEMS to calculate CO2 only if it meets all of the criteria in
either 40 CFR §98.33(b)(5)(ii) or (iii). It is unclear whether the criteria in sections
§98.33(b)(5)(ii) and (iii) are inclusive or exclusive of each other. There is no "and" or "or" after
the conditions to determine the intent of the rule. For example, if a facility has a combustion unit
less than 250 mmBtu/hr that combusts solid fuel and operates more than 1,000 hours a year but is
not required to have CEMs equipment, is it required to use Tier 4 calculation methodology?
Deere suggests the following revisions to address this question: (1) §98.33(b)(5)(ii) Shall be
used for a unit if all of the conditions specified in paragraphs (b)(5)(ii)(A) through (F) are met.
(2) §98.33(b)(5)(iii) ...if the unit meets all of the conditions specified in paragraphs (b)(5)(iii)(A)
through (C).
294
-------
Response: EPA acknowledges the commenter's concerns regarding Tier 4 applicability. EPA
has revised the rule to clarify that all six criteria must be met before Tier 4 is required.
Commenter Name: Allen Kacenjar
Commenter Affiliation: Squire Sanders
Document Control Number: EPA-HQ-OAR-2008-0508-0492.1
Comment Excerpt Number: 3
Comment: The language of §98.33(b)(5) should be clarified to confirm that all six criteria must
be met to trigger obligatory Tier 4 monitoring. Although this section was apparently meant to
establish a six-part test for triggering mandatory Tier 4 monitoring, the six identified
requirements are stated independently. The Preamble is also unclear on this point. While most
of the relevant Preamble text apparently assumes that sources must meet all six criteria to trigger
Tier 4 monitoring, it also contains the unqualified statement that "[t]he Tier 4 method, and the
use of CEMS (with any required monitor upgrades), is required for solid fossil fuel-fired units
with a maximum heat input capacity of greater than 250 mmBtu/hr. . . ." 74 Fed. Reg. at 16483.
EPA should clarify §98.33(b)(5) by inserting semicolons between each lettered requirement
(instead of periods) and by adding the word "and" after §98.33(b)(5)(E). It should also expressly
confirm in the Preamble to the final rule that all six requirements must be met before any Tier 4
monitoring obligation accrues.
Response: EPA acknowledges the commenters' concerns regarding Tier 4 applicability. EPA
has revised the rule to clarify that all six criteria must be met before Tier 4 is required.
Commenter Name: Louis Kollias
Commenter Affiliation: Metropolitan Water Reclamation District of Greater Chicago (District)
Document Control Number: EPA-HQ-OAR-2008-0508-0311
Comment Excerpt Number: 2
Comment: It is unclear why the US EPA is only using the HHV for the combusted fuels. The
World Resource Institute's (WRI) Greenhouse Gas Protocol is the most widely used international
accounting tool for government and business leaders to understand, quantify, and manage GHG
emissions. In their calculations of stationary combustion sources, they use a similar approach to
the US EPA; however, they consider an average of the lower heat value (LHV) and HHV. The
US EPA's approach would therefore provide higher energy use calculations than the WRI's
approach. The reason for only using the HHV in the US EPA-proposed ruling needs to be
addressed.
Response: EPA believes that use of the HHV for fuel heat content is consistent with existing
federal and state requirements for measuring and reporting emissions from stationary fuel
combustion (SO2, NOx, particulate matter) and the Inventory of U.S. Emissions and Sinks.
Averaging HHV and LHV as suggested by the commenter would add additional requirements
and complexity.
295
-------
Commenter Name: R. Siegel
Commenter Affiliation: None
Document Control Number: EPA-HQ-OAR-2008-0508-0151
Comment Excerpt Number: 1
Comment: For the different tiers of reporting, please change it to maximum hourly fuel input
during the year, instead of installed nameplate. Some facilities have significantly more installed
capacity than can physically be used at once, much of this is for redundancy.
Response: See the Premable, Section II. E., for a summary of comments and responses on
thresholds. The Agency refers the commenter to the definition of "maximum rated heat input
capacity" in §98.6 for further clarification.
Commenter Name: See Table 4
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0455.1
Comment Excerpt Number: 12
Comment: The equations provided in Tier Three of proposed §98.33 for calculating annual
C02 mass emissions for liquid and gas-fired combustion sources — Equations C-4 and C-5 —
would only allow for fuel to be measured on a volume basis. This presumption, that liquid and
gaseous fuel quantities are only measured on a volume basis, is false. Fuel flow meters may
directly measure the volume or mass of the fuel combusted. Therefore, the Class of'85 believes
the Agency should expand its annual CO2 mass emissions formulas for liquid and gaseous fuels
to account for fuel quantities measured using either type of fuel flow meter.
Response: EPA appreciates your comment and has added language to allow mass flow
measurements for liquid fuels.
Commenter Name: Gary Moore
Commenter Affiliation: Pensacola Plant of Ascend Performance Materials LLC
Document Control Number: EPA-HQ-OAR-2008-0508-0366.1
Comment Excerpt Number: 11
Comment: Our reading of the requirement to use Tier 4 calculation methods for stationary
combustion devices indicates that CEMS units are required for large units burning solid fuels
meeting all of the requirements on §98.33(b)(5)(ii). Large units burning liquid or gaseous fuels
would be allowed to use Tier 3 methods even if they met some of the requirements in
§98.33(b)(5)(ii). This interpretation is consistent with both the Preamble and Technical support
document. The rule language is difficult to interpret on this and we request that the rule
language be clarified to confirm this.
Response: EPA acknowledges the commenter's concerns regarding Tier 4 applicability. EPA
has revised the rule to clarify that all six criteria specified in subparagraphs (A) through (F) must
296
-------
be met before Tier 4 is required. Large units burning liquid or gaseous fuels are not required to
use Tier 4.
Commenter Name: Leslie Bellas
Commenter Affiliation: National Lime Association (NLA)
Document Control Number: EPA-HQ-OAR-2008-0508-0520.1
Comment Excerpt Number: 52
Comment: 40 C.F.R. §§98.33(b)(5)(ii)(A)-(F) sets forth six conditions for use of the Tier 4
methodology by units with a maximum rated heat input capacity of greater than 250 mmBtu/hr.
To clearly indicate that all six conditions must be met before requiring use of the Tier 4 emission
calculation methodology, each condition in 40 C.F.R. §§98.33(b)(5)(ii)(A) - (F) should end with
a semi-colon and that after the semi-colon in 40 C.F.R. §98.33(b)(5)(ii)(E), the word "and"
should be added.
Response: EPA acknowledges the commenter's concerns regarding Tier 4 applicability. EPA
has revised the rule to clarify that all six criteria must be met before Tier 4 is required.
Commenter Name: Laurie Burt
Commenter Affiliation: Massachusetts Department of Environmental Protection
Document Control Number: EPA-HQ-OAR-2008-0508-0453.1
Comment Excerpt Number: 35
Comment: 98.33(b)(5)(ii) lists when a source must use Tier 4 calculation method in subsections
(A) through (F). Massachusetts asks EPA to clarify if they meant that this requirement applies to
sources that meet all the requirements of (A) through (F), or any of the requirements of (A)
through (F).
Response: EPA acknowledges the commenter's concerns regarding Tier 4 applicability. EPA
has revised the rule to clarify that all six criteria must be met before Tier 4 is required.
Commenter Name: Laurie Burt
Commenter Affiliation: Massachusetts Department of Environmental Protection
Document Control Number: EPA-HQ-OAR-2008-0508-0453.1
Comment Excerpt Number: 34
Comment: 98.33(a)(4)(i) references use of certain monitors "except as otherwise provided in
paragraph (a)(l)(iv)(D)." There is no paragraph (a)(l)(iv)(D) in section 98.33.
Response: EPA has corrected this error. The paragraph referenced in the comment
(§98.33(a)(4)(i) in the final rule) now refers to section §98.33(a)(4)(iv).
297
-------
Commenter Name: Traylor Champion
Commenter Affiliation: Georgia-Pacific, LLC (GP)
Document Control Number: EPA-HQ-OAR-2008-0508-0380.1
Comment Excerpt Number: 31
Comment: EPA should include a back calculation methodology to determine the amount of
biomass combusted. EPA has proposed that biomass (wood, bark, etc.) being burned in a
combustion device be done by Tier 1 methodology. This basically requires measurement of the
amount of biomass being combusted, adjusting this amount to 12% moisture content (as
currently specified in Table C-l) and then multiplying this result by the default HHV and
emission factor listed in Table C-l. Most mill operations do not directly measure wood burned
but rely on back calculation of the amount of wood combusted from steam generation rates and
the heat design rate of the combustion device - a practice well-grounded in solid engineering
principles and recognized by regional climate change initiatives such as the Western Climate
Initiative (WCI) as well as Green-e, the nation's leading independent certification and
verification program for renewable energy credits, which GP certifies at two mills - Port
Hudson, LA and Toledo, OR. The methodology is also commonly used to determine Btu input
for emission stack test reports in lieu of the F-factor methodology. During a May 28, 2009
meeting between representatives from EPA and Koch Industries Inc, GP provided a white paper
detailing the calculation methodology employed at our facilities to determine the amount of
biomass combusted from steam production data. [See DCN: EPA-HQ-OAR-2008-0508-0380.1
for paper attachment], EPA's Technical Support Document for the Pulp and Paper Sector (P&P
TSD) provides extensive detail on use of a back-calculation method to determine the quantity of
biomass fuels fired from steam production data. GP agrees with EPA's statement in the P&P
TSD that, ".. .given the variations in biomass fuels fired in a given boiler over time and the fact
that biomass is co-fired with fossil fuels, obtaining site-specific HHV and biomass CO2
emissions factors would be very difficult." As EPA acknowledges, the majority of biomass fired
at pulp and paper mills is generated on-site; therefore, purchasing records are not available to
determine the quantity of biomass consumed, nor are belt scales in use at some, but certainly not
all, mills an accurate method for determining the amount of biomass fired due to varying
moisture contents of the biomass. EPA details in the P&P TSD an alternate method for
determining the total amount of biomass fired in a boiler by back-calculating the mass of
biomass from annual steam production data, information on the other fuels combusted in a
boiler, and the efficiency of biomass-to-energy conversion. However, EPA does not
acknowledge this method in the Preamble or the rule and does not specifically allow for its use
for biomass fuels. EPA should specifically allow a back calculation methodology for biomass
such as the WCI method, EPA's method provided in the P&P TSD, and/or the method provided
in the attached white paper as an option to using the Tier 1 methodology. EPA should list a
default CO2 emission factor for solid biomass fuels in Table C-2.
Response: Since default CO2 emission factors are provided for several types of solid biomass
fuels, including wood and wood residuals, agricultural byproducts, peat, and solid byproducts, in
Table C-l, EPA does not believe that it is necessary to add an additional default factor. EPA has
also extended the use of steam production and combustion unit efficiency to calculate CO2
emissions to other solid fuels in addition to municipal solid waste. These parameters may be
used to quantify the amount of biomass combusted in a unit.
298
-------
Commenter Name: Traylor Champion
Commenter Affiliation: Georgia-Pacific, LLC (GP)
Document Control Number: EPA-HQ-OAR-2008-0508-0380.1
Comment Excerpt Number: 30
Comment: In light of EPA's parallel efforts to define "solid waste" for purposes of the
Commercial and Industrial Solid Waste Incinerator (CISWI) and Boiler MACT rulemakings
currently on remand, EPA should be sensitive to the possible inadvertent characterization of
wood and other biomass-based materials as "waste" rather than "fuels." Accordingly, GP
requests that EPA delete the reference to "wood waste" in Table C-l since wood used as a fuel is
not a waste, but rather a valuable commodity. EPA should replace this reference with the term
"wood residuals."
Response: In response to the comment, EPA has replaced the language "wood waste" to read
"wood residuals" in the Subpart C tables.
Commenter Name: Traylor Champion
Commenter Affiliation: Georgia-Pacific, LLC (GP)
Document Control Number: EPA-HQ-OAR-2008-0508-0380.1
Comment Excerpt Number: 29
Comment: Impregnated sawdust is currently listed as a distinct fuel in Table C-2, which does
not provide default HHVs. However, impregnated sawdust is actually a residual biomass from
the manufacture of wood products such as plywood, oriented strand board and fiberboard. These
materials fit into the proposed definition of biomass: Biomass means non-fossilized and
biodegradable organic material originating from plants, animals and micro-organisms, including
products, by-products, residues and waste from agriculture, forestry and related industries... The
entry of impregnated sawdust should be eliminated from Table C-2 simply because it is another
form of biomass as listed in Table C-l.
Response: EPA recognizes that Impregnated Saw Dust falls under residual biomass, and has
changed the rule language and tables in §98.38 to reflect this.
Commenter Name: Angela Burckhalter
Commenter Affiliation: Oklahoma Independent Petroleum Association (OIPA)
Document Control Number: EPA-HQ-OAR-2008-0508-0386.1
Comment Excerpt Number: 25
Comment: Under Tier 1, EPA proposes that fuel consumption would be based on company
records. If no fuel flow meters are installed, we assume this would include a company's best
estimate.
Response: EPA acknowledges the commenter's concerns, and has defined the term "company
records" in §98.6 of the final rule. EPA believes that the revised definition provides appropriate
guidance as to what records a facility may use to determine fuel consumption.
299
-------
Commenter Name: Jerry Call
Commenter Affiliation: American Foundry Society (AFS)
Document Control Number: EPA-HQ-OAR-2008-0508-0356.2
Comment Excerpt Number: 22
Comment: In section 98.33(c)(4) of the proposed regulation, it appears the paragraph reference
should be Table C-3 in lieu of the missing Table C-4.
Response: In the final rule, the proposed language of §98.33(c)(4) has been deleted, and there is
no longer a reference to Table C-4.
Commenter Name: See Table 7
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0412.1
Comment Excerpt Number: 21
Comment: Overall, GPA supports Subpart C as proposed. In particular, GPA supports the
proposed rule's allowance for using "company records" rather than direct fuel measurement for
Tier 1 and 2 sources. Midstream sources like GPA members would generally use Tier 1 or 2
calculation methodologies, which allow for calculating C02 emissions based on default or
measured fuel heating value, default CO2 emission factors, and fuel quantity from company
records.
Response: EPA appreciates your comments and has changed the final rule to allow the use of
company records in Tier 1, 2, and 3 calculations. A definition of "company records," as it
pertains to quantifying fuel consumption in Tiers 1, 2, and 3, has been added to §98.6.
Commenter Name: Gary Moore
Commenter Affiliation: Pensacola Plant of Ascend Performance Materials LLC
Document Control Number: EPA-HQ-OAR-2008-0508-0366.1
Comment Excerpt Number: 6
Comment: Chemical manufacturing plants may be permitted to burn non-hazardous liquid
materials in boilers as fuels. For example, these fuels could be distillation column bottom
residues. The residue would not have a default emission factor for CH4 and N2O emission
calculations. The use of the word "may" in the proposed rule introduces some ambiguity as to
the intent of paragraph §98.33(c)(4). The amount of these types of "other" fuels combusted on a
national level is likely to be small relative to the amount of listed fuels and the emissions of CH4
and N2O are small on a CC^e basis. Is the reporting the CH4 and N2O emissions optional? If
emissions are required to be reported, the Agency could propose the use of emission factors from
the fuel closest to the "other" fuel being combusted to estimate the CH4 and N2O emissions. In
this example, the emission factors chosen would be those for Residual Fuel Oil.
300
-------
Response: EPA acknowledges the commenter's concerns, and has addressed them in the final
rule. Section 98.33(c) of the final rule excludes from calculations any CH4 and N20 emissions
from fuels that are not listed in Table C-2 (formerly C-3). Also, EPA has dropped the provisions
that allow facilities burning other fuels to develop site-specific emission factors.
Commenter Name: Paul Dubenetzky
Commenter Affiliation: KERAMIDA Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-0419.1
Comment Excerpt Number: 11
Comment: The U.S. EPA proposes CO2 emission factors for the combustion of oil generally
considered diesel oil in both 40 CFR, Subpart MM, Suppliers of Petroleum Products, Table MM-
1, 74 FR 16719 and Table MM-3, 74 FR 16720 and in 40 CFR 98, Subpart C, General Stationary
Fuel Combustion, Table C-l. 40 CFR 98, Subpart MM provides specifically for #2 fuel oil and
for 100% methyl ester. Methyl ester is motor fuel-grade diesel oil that is derived from plant or
animal fat. 40 CFR 98, Subpart C does not provide specific C02 emission factors for #2 fuel oil
or for 100% methyl ester. Instead, 40 CFR 98, Subpart C provides less specifically for Distillate
Fuel Oil (#1, 2, 3, 4) and for Other Oil ( > 401 deg. F). The following two points demonstrate
the inconsistencies between the CO2 emission factors for diesel fuel oil found in 40 CFR 98,
Subpart MM compared to Subpart C: 1. The 40 CFR 98, Subpart MM, Table MM-1 C02
emission factor for # 2 fuel oil is 0.43 metric tons of CO2 per barrel of oil. Using the default HI-
IV of 0.139 mmBtu/gal found in 40 CFR, Subpart C, Table C-l and the 42 gallons per barrel
conversion factor provided in 40 CFR 98 Subpart A, Table A-2 that equates to 430 kilograms per
barrel, 10.238 kilograms per gallon, and 73.655 kilograms per mmBtu. The 40 CFR 98, Subpart
C, Table C-l CO2 emission factor for combusting Distillate Fuel Oil(#l, 2, 3, & 4) is 73.10
kilograms per mmBtu. 2. The 40 CFR 98, Subpart MM, Table MM-3 CO2 emission factor for
100%) methyl ester is 0.40 metric tons of CO2 per barrel of oil. Using the default factors found
in 40 CFR, Subpart C, Table C-l for Other Oil ( > 401 deg. F) and the conversion factors
provided by 40 CFR 98 Subpart A, Table A-2 that equates to 400 kilograms per barrel, 9.5238
kilograms per gallon, and 68.52 kilograms per mmBtu. The 40 CFR 98, Subpart C, Table C-l
CO2 emission factor for Other Oil ( > 401 deg. F) is 73.10 kilograms per mmBtu. The U.S. EPA
should reconcile these discrepancies while addressing our previously stated comments regarding
the significant figures used in calculating GHG emissions and the significant figures used when
reporting GHG emissions.
Response: EPA acknowledges the concerns of the commenter, and created better consistency
between the default values provided in Table C-l and the information presented in Subpart MM.
301
-------
Commenter Name: Lloyd Stone
Commenter Affiliation: Westlake Chemical Corporation
Document Control Number: EPA-HQ-OAR-2008-0508-0442.1
Comment Excerpt Number: 11
Comment: 98.33(b)(5)(ii): This requirement is not consistent with "Table C-l" in the Preamble
98.33(b)(5)(ii) appears to require all units operating for 1000 hours or more annually since 2005
to use Tier 4.
Response: EPA acknowledges the concerns regarding Tier 4 applicability. EPA has revised the
rule to clarify that all six criteria must be met before Tier 4 is required.
Commenter Name: Gary Moore
Commenter Affiliation: Pensacola Plant of Ascend Performance Materials LLC
Document Control Number: EPA-HQ-OAR-2008-0508-0366.1
Comment Excerpt Number: 10
Comment: Fence line natural gas GC analyses performed and supplied to customers by the
pipeline company should be allowed to meet the sampling and analysis HHV, carbon and
molecular weight analysis requirements of the rule. Ascend Performance Materials believes that
values supplied by the vendor should be acceptable rather than requiring duplicative testing and
the associated costs. This additional testing provides no additional value or accuracy to the
calculations.
Response: The final rule clarifies that fuel sampling and analysis data provided by the supplier
may be used in the emission calculations, and that fuel billing meters may be used to quantify
fuel consumption. To simplify the emission calculations in Tiers 2 and 3, averaging of HHV and
carbon content data is permitted if these data are obtained at least at the minimum frequency
specified in §98.34. If the results of fuel sampling are received monthly or more frequently, the
weighted annual average high heat value shall be calculated using Equation C-2b. If the results
of fuel sampling are received less frequently than monthly, then the annual average HHV shall
be calculated using the arithmetic average HHV for all valid samples for the year. However,
regardless of the sampling frequency, the owner or operator must use the results of all available
valid fuel analyses in the emissions calculations.
Commenter Name: Lloyd Stone
Commenter Affiliation: Westlake Chemical Corporation
Document Control Number: EPA-HQ-OAR-2008-0508-0442.1
Comment Excerpt Number: 10
Comment: Should there be the word "and" between §98.33(b)(l)(i) and (ii)?
Response: EPA has considerably revised §98.33(b). The commenter's concern relates to
sections that have been substantially edited and/or deleted, and is thus no longer relevant.
302
-------
Commenter Name: See Table 2
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0509.1
Comment Excerpt Number: 10
Comment: A good example is in the Tier 1-4 methodologies for calculating C02 emissions
from fuel combustion. To begin with, EPA creates confusion by failing to include conjunctions
when listing a series of items. For example, proposed 40 C.F.R. §98.33(b)(5)(ii) requires the use
of the Tier 4 calculation methodology if (A) - (F). But must only one of the (A) - (F) criteria be
met, or all of them? (Presumably the latter, but EPA needs to make it clear.) Additional
ambiguity is created by EPA's failure to state directly what stack monitoring devices would be
required to be installed and maintained by different types of sources. Thus, one could infer from
the description of the Tier 4 CO2 emission calculation methodology in proposed 40 C.F.R.
§98.33(a)(4), for example, when read together with the applicability provisions of section
98.33(b)(5) and (6), that a source with a heat input above 250 MMBtu/hr. that burns (at least
some??) solid fuel and already is required to have a stack gas monitor or flow monitor (and to
meet certain quality assurance testing for that monitor) must install equipment to continuously
monitor C02 stack gas concentration by no later than January 1, 2011. But that certainly is not
clearly stated, and one could also read the proposed regulations to suggest that facilities without
a C02 monitor (or without an 02 monitor if their only stack emissions are from fuel combustion)
are supposed to use the Tier 3 calculation methodology.
Response: EPA acknowledges the commenter's concerns regarding Tier 4 applicability. EPA
has revised the rule to clarify that all six criteria must be met before Tier 4 is required. However,
EPA disagrees with suggestions that Tier 4 should only be required if the installed CEMS
include a CO2 monitor. The Tier 4 CEMS requirement is limited to larger solid fossil fuel units
with an existing pollutant CEMS and a certified gas monitor of any kind or a stack gas
volumetric flow rate monitor. EPA is requiring the use of CEMS due to the complexity of
monitoring solid fuel consumption and the heterogeneous nature of the solid fuels. Many of
these fossil-fuel fired units with a pollutant CEMS have an existing diluent monitor (O2 or CO2)
that can be used to determine CO2 emissions. EPA's estimates of monitoring costs are averages
for a representative facility and may not represent the actual cost in individual circumstances.
Commenter Name: Lloyd Stone
Commenter Affiliation: Westlake Chemical Corporation
Document Control Number: EPA-HQ-OAR-2008-0508-0442.1
Comment Excerpt Number: 9
Comment: 98.33(a)(3)(ii): How is liquid fuel that is used as a secondary fuel considered, when
not burned in any given month? Is the monthly analysis of carbon content still required?
98.33(a)(3)(iii): Is the monthly analysis of carbon content and molecular weight still required for
a gaseous fuel that is used as a secondary fuel considered, when not burned in any given month?
Response: EPA has changed §98.34 to clarify and simplify fuel sampling requirements, revising
the sampling frequency requirements. In the final rule, natural gas must be sampled
semiannually, while fuel oil and coal must be sampled with each fuel lot. Other liquid fuels and
303
-------
biogas must be sampled once per calendar quarter, and other solid fuels besides municipal solid
waste must be sampled weekly to form a composite sample which is analyzed monthly. Where
different types of fuel are blended prior to combustion, EPA has added an option to either use a
weighted HHV value in the emission calculations based on the relative proportions of each fuel
in the blend, or take a representative sample of the blended fuel and analyze it for HHV. EPA
believes that these revised requirements provide an appropriate balance between reducing the
burden on reporters and obtaining accurate data.
Commenter Name: Kerry Kelly
Commenter Affiliation: Waste Management (WM)
Document Control Number: EPA-HQ-OAR-2008-0508-0376.1
Comment Excerpt Number: 8
Comment: Section 98.33(b)(5)(ii) outlines the conditions under which a reporter must use the
Tier4 calculation methodology to estimate a unit's emissions. As drafted, it lists a series of
conditions, (A) through (F) with no conjunctions between conditions. We assume the Agency
intends that all conditions must be met for the Tier 4 method to apply. Otherwise, the
application of just one condition (C) - The unit has operated for more than 1,000 hours in any
calendar year since 2005, would require the vast majority of stationary combustion units to use
Tier 4. We do not believe the EPA intended such a ludicrous result. We urge the EPA to insert
the word "and" between each of the conditions to clarify that all conditions must be met before a
unit is subject to Tier 4. Further, per our comments above concerning application of Tier 4 to
municipal solid waste combustion, we urge the Agency to delete the second half of condition (A)
referring to units that combust MSW and have a maximum rated input capacity greater than 250
tons per day of MSW.
Response: EPA acknowledges the commenters' concerns regarding Tier 4 applicability. EPA
has revised the rule to clarify that all six criteria specified in §98.33 must be met before Tier 4 is
required. EPA appreciates your comment and has increased the 250 ton MSW/day threshold to
500 ton MSW/day.
Commenter Name: Kerry Kelly
Commenter Affiliation: Waste Management (WM)
Document Control Number: EPA-HQ-OAR-2008-0508-0376.1
Comment Excerpt Number: 39
Comment: In Tier 2 Equation C-2b. The "B" ratio is incorrect and should be revised consistent
with the Western Climate Initiative calculation on which it was based. Revised ratio should be:
Ratio of boilers maximum design rated heat input capacity to its design rated steam output
capacity (mmBtu/lb steam). Same comment for equation C-lOb for N2O and CH4 calculations.
Response: EPA appreciates the comment but believes that the ratio is satisfactory as written in
Equation C-2c. The Agency directs the commenter to the definition of "maximum rated heat
input capacity" in §98.6 for further clarification on this matter.
304
-------
Commenter Name: Traylor Champion
Commenter Affiliation: Georgia-Pacific, LLC (GP)
Document Control Number: EPA-HQ-OAR-2008-0508-0380.1
Comment Excerpt Number: 23
Comment: GP (and, we assume other companies with facilities that use a significant amount of
fuel of any type) tracks the amount of fuel purchased very closely since it is, in most cases, a
significant part of the overall energy cost. Standard accounting practices require accurate
accounting for all fuel purchases and usage. In view of this fact, EPA has chosen the correct
option of allowing facilities to use these records to calculate GHG emissions rather than
requiring the installation and calibration of new flow meters or weighing system for solid fuels.
EPA has proposed requiring facilities that report under the Tier 3 methodology for gas and liquid
fuels to install and calibrate flow measurement devices [§98.33(a)(3) FR 16632],
Notwithstanding our preferred approach of using the Tier 1 methodology on fuels coming across
the fenceline, as explained above, given that maintaining accurate and complete company
records for these fuels is such a high priority for accurate cost accounting, EPA should allow
company records to be used for Tier 3 reporting rather than installation and calibration of
independent flow devices. Unit level data provides no additional value in terms of facility
emissions.
Response: EPA appreciates your comments and has changed the final rule to allow the use of
company records in Tier 1, 2, and 3 calculations. A definition of "company records," as it
pertains to quantifying fuel consumption in Tiers 1, 2, and 3, has been added to §98.6.
Commenter Name: Ron Downey
Commenter Affiliation: LWB Refractories
Document Control Number: EPA-HQ-OAR-2008-0508-0719.1
Comment Excerpt Number: 22
Comment: The method to calculate hourly emissions proposed in 40 C.F.R. 98.33(a)(4)(v) and
40 C.F.R. 98.33(e)(2)(i), Equation C-12, appears to be inconsistent with Part 75, and may
understate emissions during partial hours of operation. The rule requires sources to calculate the
mass and volume of CO2 emitted each hour by multiplying the CO2 emission rates and hourly
flow rates by the fraction of the hour that the source was in operation. Because the downtime is
already be accounted for in the hourly average emission rate, there is no need to multiply the
hourly average by operating time for that hour. EPA should revise provision to delete the
requirement to multiply CO2 emission rates and hourly flow rates by the fraction of the hour that
the source was in operation. LWB proposes that total combustion emissions be calculated by
summing the hourly averages during operation times throughout the year to be consistent with
Parts 60 and 75.
Response: EPA appreciates your support and thanks you for your comment. The discrepancy
has been reconciled in the final rule.
305
-------
Commenter Name: Lorraine Krupa Gershman
Commenter Affiliation: American Chemistry Council (ACC)
Document Control Number: EPA-HQ-OAR-2008-0508-0423.2
Comment Excerpt Number: 51
Comment: In §98.33(a)(4)(i), EPA refers in this section to paragraph (a)(l)(iv)(D) of this
section; however, this reference does not appear to exist in the proposed rule and EPA needs to
correct this reference.
Response: EPA has corrected this error. The paragraph referenced in the comment
(§98.33(a)(4)(i) in the final rule) now refers to section §98.33(a)(4)(iv).
Commenter Name: Thomas Diamond
Commenter Affiliation: Semiconductor Industry Association (SIA)
Document Control Number: EPA-HQ-OAR-2008-0508-0498.1
Comment Excerpt Number: 35
Comment: SIA provided a redline version of proposed rule that reflects SIA's proposed
alternatives. [SeeDCN: EPA-HQ-OAR-2008-0508-0498.1]
Response: In regard to electronics manufacturing, Subpart I, EPA is not going final with that
source category at this time. Please see Section III. I. of the Preamble and the separate comment
response document.
Commenter Name: Lauren E. Freeman
Commenter Affiliation: Hunton & Williams LLP
Document Control Number: EPA-HQ-OAR-2008-0508-0493.1
Comment Excerpt Number: 35
Comment: With respect to the proposed emission factors, UARG notes that the value for CH4
in Table C-3 is significantly higher than the equivalent units under AP-42 (roughly 35 ppm
versus 2.7 ppm). In addition, although the N2O values in Table C-3 are closer to the AP-42
values for that gas, AP-42 also differs from Table C-3 in that it provides different values for
wall-fired boilers than for tangentially-fired boilers. A "Note" at the bottom of Table C-3 states
that, "for coal combustion," units that fall within the IPCC "Energy Industry" category may
"employ a value of 1 g of CH4/MMBtu." That value is much closer to the AP-42 value for CH4.
UARG does not understand why this alternative CH4 value for coal combustion is hidden in a
note at the bottom of the table. Nor is it clear in the rule where one would look to determine
whether a unit is within the cited IPCC category. [Footnote: UARG assumes EPA is referring to
the 2006 IPCC Guidelines for National Greenhouse Gas Inventories, Volume 2, but that is far
from clear.] UARG requests that EPA clarify in the table (rather than merely in a note) which
units may use the alternative CH4 value in Table C-3, and that the Agency allow sources to use
the more specific AP-42 values for N2O where they are applicable.
306
-------
Response: EPA listed fuel types and respective default emission factors for CH4 and N20 in
Subpart C are sufficient for reporting. For the purposes of the rule, which is data collection for
policy development, we would prefer consistent use of default CH4 and N20 emission factors.
In this case, we provide the values we would like reporters to use, and for verification purposes,
would prefer consistent use of these factors. Based on comments, additional factors have been
added to Table C-2 (formerly C-3), and other factors may be brought into future programs, but
for this rulemaking, given the very small comparative amounts of CH4 and N20 emitted relative
to C02, we have chosen to use the listed default factors. EPA is using mostly IPCC values
because the AP-42 non-C02 factors have not been reviewed in depth recently.
Commenter Name: Ron Downey
Commenter Affiliation: LWB Refractories
Document Control Number: EPA-HQ-OAR-2008-0508-0719.1
Comment Excerpt Number: 32
Comment: 40 C.F.R. 98.33(b) indicates that units combusting multiple fuel types (e.g., burning
coal and natural gas in the same kiln) could be required to use two different emission calculation
methodologies (tiers) in order to calculate stationary fuel combustion. We request confirmation
that it is permissible to use multiple tiers for each fuel type combusted by a single unit. 40
C.F.R. 98.33(b)(5)(ii)(A) - (F) sets forth conditions for use of the Tier 4 methodology. LWB
interprets this provision to require that sources meet all six conditions in order for Tier 4 to
apply. LWB proposes that each condition in 40 C.F.R. 98.33(b)(5)(ii)(A) - (F) end with a semi-
colon and that after the semi-colon in 40 C.F.R. 98.33(b)(5)(ii)(E), the word "and" be added to
clearly indicate that all six conditions must be met before requiring use of the Tier 4 emission
calculation methodology.
Response: EPA acknowledges the commenters' concerns regarding Tier 4 applicability. EPA
has revised the rule to clarify that all six criteria must be met before Tier 4 is required. If Tier 4
is required then all the C02 emissions are quantified from all fuel types using Tier 4.
§98.33(a)(6).
Commenter Name: Ron Downey
Commenter Affiliation: LWB Refractories
Document Control Number: EPA-HQ-OAR-2008-0508-0719.1
Comment Excerpt Number: 31
Comment: 40 CFR Part 98.33(a)(4)(iv) permits the use of an O2 monitor to meet the CEMS
monitoring requirement for Tier 4. However, 40 C.F.R. Part 75 permits O2 measurements to
serve as a surrogate for CO2 if the effluent gas stream monitored by the CEMS consists solely of
combustion products and if only fuels listed in Table 1 are combusted. As written, the Proposed
Rule does not clearly indicate whether a facility with an O2 monitor would be required to use a
CEMS. In the case of lime, an O2 monitor could not be used to determine their CO2 emissions
due to the presence of process related emissions. The Proposed Rule does not impose any limits
on the use of O2 data as a surrogate for CO2. See 40 CFR Part 98.33(a)(4)(iv). Part 60 and 75
allow O2 measurements to serve as a surrogate for CO2 because Part 75 only addresses CO2
307
-------
from fuel combustion. Similarly, the Western Climate Initiative's reporting rule allows the use
of O2 measurements as a surrogate for CO2 in limited situations. LWB would like to know the
basis for EPA's conclusion that 02 measurements are always an appropriate surrogate for
determining CO2 emissions from a lime kiln. 40 CFR Part 98.33(a)(4)(iv) should be clarified to
state that sources not allowed to use 02 data as a surrogate for C02 would not be subject to Tier
4 solely on the basis of having an O2 monitor. In addition, this provision should be made
consistent with the Western Climate Initiative's Final Draft of Essential Requirements of
Mandatory Reporting and Part 75, by identifying the limited situations in which O2
measurements can be used as a surrogate for C02.
Response: EPA has revised the final rule to provide clarity concerning gas monitors and Tier 4
requirements. Tier 4 shall be used only if the unit meets six conditions, one of which is "the
installed CEMS include a gas monitor of any kind or a stack gas volumetric flow rate monitor, or
both ..." Further, EPA allows an oxygen (O2) concentration monitor to be used in lieu of a CO2
concentration monitor to determine the hourly C02 concentrations in accordance with Equation
F-14a or F-14b (as applicable) in Appendix F to Part 75, if the effluent gas stream monitored by
the CEMS consists solely of combustion products (i.e., no process C02 emissions are mixed
with the combustion products).
Commenter Name: Lauren E. Freeman
Commenter Affiliation: Hunton & Williams LLP
Document Control Number: EPA-HQ-OAR-2008-0508-0493.1
Comment Excerpt Number: 30
Comment: UARG notes that some confusion has been caused by EPA's failure to specify in the
proposed rule whether all, or only one, of the criteria in proposed §98.33(a)(4)(A) - (F) triggers
Tier 4. To avoid confusion, UARG suggests that EPA add an "and" at the end of subsection (E).
Response: EPA acknowledges the commenters' concerns regarding Tier 4 applicability. EPA
has revised the rule to clarify that all six criteria must be met before Tier 4 is required.
Commenter Name: Lauren E. Freeman
Commenter Affiliation: Hunton & Williams LLP
Document Control Number: EPA-HQ-OAR-2008-0508-0493.1
Comment Excerpt Number: 29
Comment: Tier 2, also applicable to units with a maximum rated heat input capacity of 250
mmBtu/hr or less, uses fuel-specific default CO2 emission factors, a measured HHV, and
monthly fuel consumption from company records to calculate annual CO2. Tier 2 can be used as
long as the applicable CO2 default value is provided in either Table C-l or C-2 (alternative
fuels). Proposed §§98.33(a)(2) and (b)(3). According to the Preamble, and Equation C-2a, fuel
is measured monthly. 74 Fed.Reg. at 16,484, 16,632. Proposed §98.34(c)(2), however, specifies
weekly sampling to develop a composite for monthly analysis of coal, and other solid fuels.
EPA should clarify its description and equation to reflect the more specific provisions in
§98.34(c). Tier 3, applicable to any unit for which Tier 4 is not elected or required, uses
308
-------
measured fuel carbon, molecular weight (for gases), and the quantity of fuel combusted.
Proposed §§98.33(a)(3) and (b)(4). For liquid and gaseous fuel, the volume is measured with
fuel flow meters (including gas billing meters) or, for oil, tank drop measurements. Coal
consumption is measured with company records. Proposed §§98.33(a)(3). Carbon content is
measured monthly for natural gas, biogas, and liquid fuels, monthly for coal and other solid fuel
(based on a weekly composite), and daily for other gaseous fuel (e.g., refinery gas or process
gas). Proposed §98.34(d)(3). EPA assumes that daily measurements would be made with in-line
gas chromatographs that are already in place for process purposes. 74 Fed. Reg. 16484. All oil
and gas flow meters (except for gas billing meters) must be calibrated prior to the first reporting
year using either a test method listed in §98.7 or "the calibration procedures specified by the flow
meter manufacturer," and must be recalibrated either annually or "at the minimum frequency
specified by the manufacturer." Proposed §98.34(d)(1). For both Tier 2 and Tier 3
methodologies, only those sampling and analysis methods incorporated under proposed §98.7
can be used. Proposed §98.34(c) and (d). To ensure that this list is complete and that the
methods provided are up to date, UARG requests that EPA also allow use of any applicable
method that is listed under 40 C.F.R. §75.6.
Response: The final rule clarifies that fuel sampling and analysis data provided by the supplier
may be used in the emission calculations, and that fuel billing meters may be used to quantify
fuel consumption. To simplify the emission calculations in Tiers 2 and 3, averaging of HHV and
carbon content data is permitted if these data are obtained at least at the minimum frequency
specified in §98.34. If the results of fuel sampling are received monthly or more frequently, the
weighted annual average high heat value shall be calculated using Equation C-2b. If the results
of fuel sampling are received less frequently than monthly, then the annual average HHV shall
be calculated using the arithmetic average HHV for all valid samples for the year. However,
regardless of the sampling frequency, the owner or operator must use the results of all available
valid fuel analyses in the emissions calculations.
EPA has incorporated by reference all methods deemed appropriate into Part 98, and therefore
does not believe it is necessary to allow the use of methods listed under 40 C.F.R §75.6.
Commenter Name: See Table 5
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0480.1
Comment Excerpt Number: 40
Comment: Table C-3 of the Proposed Rule includes default CH4 and N2O emission factors for
natural gas and §98.33(c) indicates that default values in Table C-3 should be used to calculate
emissions. As an alternative, operator-defined emission factors should be accepted if the basis
for the factors is documented and technically defensible (e.g., reference methods or reasonable
standards for measurement; engine vendor provided test data). Typically, estimates based on
source-specific emission factors would be more appropriate than an estimate based on a generic
emission factor and the operator should have the opportunity to justify use of operator defined
emission factors for methane or N2O. In some cases, operators may already be estimating GHG
emissions using more appropriate source-specific emission factor methods and should not have
to default to generic emission factors that may not be accurate for a particular source type.
309
-------
Response: EPA believes the listed fuel types and respective default emission factors for CH4
and N2O listed in Subpart C are sufficient for reporting. For the purposes of the rule, which is
data collection for policy development, we would prefer consistent use of default CH4 and N20
emission factors. For this rulemaking, given the very small comparative amounts of CH4 and
N20 emitted relative to C02, we have chosen to use the listed default factors. Also, additional
factors have been added to Table C-2 (formerly C-3), and other factors may be brought into
future programs.
Commenter Name: Ron Downey
Commenter Affiliation: LWB Refractories
Document Control Number: EPA-HQ-OAR-2008-0508-0719.1
Comment Excerpt Number: 23
Comment: 40 C.F.R. 98.33(e)(2)(i), Equation C-12 refers to measuring the "hourly C02
concentration" and the "hourly stack gas volumetric flow rate." This Equation should be revised
to replace "hourly CO2 concentration" with "hourly average CO2 concentration" and "hourly
stack gas volumetric flow rate" with "hourly average stack gas volumetric flow rate" because the
source will determine the hourly average CO2 concentration and flow rate based on multiple
samples that must be collected in accordance with Part 60 and 75 requirements.
Response: EPA thanks you for your comment. The discrepancy has been reconciled in the final
rule.
Commenter Name: Fiji George
Commenter Affiliation: El Paso Corporation
Document Control Number: EPA-HQ-OAR-2008-0508-0398.1
Comment Excerpt Number: 41
Comment: The term "measurement of HHV" or similar phrases are used in §98.33 with respect
to Tier 2 calculation of CO2 emissions from combustion sources. In addition method ASTM
D1826-94 Standard Test Method for Calorific (Heating) Value of Gases in Natural Gas Range by
Continuous Recording Calorimeter, is incorporated by reference in §98.7. This could be
interpreted to mean that measured HHV for natural gas must be obtained using the referenced
ASTM method. In fact, our FERC Gas Tariff requires that we determine the HHV of the gas
using an in-line gas chromatograph or a chromatograph analysis of a sample or composite
sample. The constituents of the analyzed gas are separated into columns, and a mole percentage
of each component is determined. Each component's specific heating value is multiplied by
mole percentage and subsequently is summed into the HHV value. Therefore, the HHV value
that we will provide to our customers or which is specific to the gas that fuels our own
combustion sources is 'a calculated off of a gas composition' and is not considered 'measured'
value. El Paso recommends that the term "measured HHV" be replaced by "measured or
calculated HHV" when referring to Tier 2 emissions from combustion of pipeline quality natural
gas and that the standards be expanded to include the following industry standards: 1. Spot or
Composite Sample: Related Industry Standard API 14.1 & GPA 2166. 2. Online
Chromatograph: Related Industry Standard API 14.1. 3. Lab Chromatograph: Related Industry
310
-------
Standard GPA 2198, GPA 2286. 4. Heating Value Calculation: Related Industry Standard API
14.1, GPA 2145, GPA 2172, AGA 5, AGA 8.
Response: In the final rule, the HHV may be calculated using chromatographic analysis
together with standard heating values of the fuel constituents. EPA has added language in
§98.33 clarifying that either the owner or operator or the fuel supplier may be responsible for the
sampling and analysis for HHV. Section 98.34 further clarifies that the fuel sampling may be
performed by the owner or operator, the fuel supplier, or an independent laboratory. EPA has
also added flexibility to the use of the four Tiers, and has reduced the frequency of required
sampling for many fuels, including natural gas. To simplify the emission calculations in Tiers 2
and 3, averaging of HHV and carbon content data is permitted if these data are obtained at least
at the minimum frequency specified in §98.34. If the results of fuel sampling are received
monthly or more frequently, the weighted annual average high heat value shall be calculated
using Equation C-2b. If the results of fuel sampling are received less frequently than monthly,
then the annual average HHV shall be calculated using the arithmetic average HHV for all valid
samples for the year. EPA has included similar equations for units combusting solid and liquid
fuels using Tier 3. However, for gaseous fuels using Tier 3, EPA has decided to require facilities
to use average carbon content determinations and fuel consumption for each measurement period
(as specified in §98.34(b)(3)). EPA has added language to §98.33(c)(2) clarifying that Equation
C-9a uses total fuel consumption during the reporting year and annual average HHV
determinations.
Commenter Name: Robert Rouse
Commenter Affiliation: The Dow Chemical Company
Document Control Number: EPA-HQ-OAR-2008-0508-0533.1
Comment Excerpt Number: 21
Comment: Comments on the Tier 1-4 Methods are Provided Below: In 98.33(a)(3)(iii), the
proposed Tier 3 methodology for a gaseous fuel requires the use of Equation C-5, which contains
the term MVC. MVC is defined as the molar volume conversion factor and is stated to be equal
to 849.5 scf per kg-mole at standard conditions for this equation and also throughout the rule.
However, in 98.6, Definitions, EPA defines the term "Standard Conditions or Standard
Temperature and Pressure" as meaning 60 degrees F and 14.7 psia. Using a temperature of 60°
F, molar volume is calculated to be (10.73)(520)/(14.7) = 379.6 scf/lb-mole x 2.2 = 835 scf/kg-
mole. Thus, there appears to be a discrepancy between the standard conditions in the definitions
and the standard conditions for the conversion factor in Equation C-5. It appears EPA may have
used a temperature of 68 °F to obtain a molar volume of 849.5 scf/kg-mole. Thus, the molar
volume that is required to be used doesn't match with a standard temperature of 60° F. EPA
could either revise the molar volume to closer to 835 scf/kgmole or revise the definition of
Standard Conditions to reflect a temperature of 68° F. Section 98.33(a)(4)(i) - EPA refers in this
section to paragraph (a)(l)(iv)(D) of this section. However, this reference does not appear to
exist in the proposed rule and EPA needs to correct this reference.
Response: EPA has corrected this error. The paragraph referenced in the comment
(§98.33(a)(4)(i) in the final rule) now refers to §98.33(a)(4)(iv).
311
-------
EPA has revised the definition of "Standard conditions or standard temperature and pressure
(STP)" in §98.6 to mean "68 degrees Fahrenheit and 14.7 pounds per square inch absolute."
Given this revised definition, EPA believes that the value for MVC provided in Equation C-5 is
correct.
Commenter Name: Ron Downey
Commenter Affiliation: LWB Refractories
Document Control Number: EPA-HQ-OAR-2008-0508-0719.1
Comment Excerpt Number: 20
Comment: The requirement in 40 C.F.R. 98.33(b)(6)(ii) to install and certify CEMS by January
1, 2011 may not be achievable given the need to select, deliver, engineer, and install and certify
the equipment. Installation of CEMS may be delayed due to the potential for increased demand
for equipment and stack testing consultants. EPA should revise 40 C.F.R. 98.33(b)(6)(ii) to
require installation and certification of CEMS by January 1, 2012.
Response: The final rule requires data collection for calendar year 2010, but has been changed
since proposal to allow use of best available monitoring methods for the first part of 2010. EPA
acknowledges the concerns of the commenters, and has clarified the rule for those units that must
upgrade their existing CEMS to meet Tier 4 requirements. If all the monitors needed have not
been installed and certified by January 1, 2010, they may use either Tier 2 or 3 in 2010.
Commenter Name: Kyle Pitsor
Commenter Affiliation: National Electrical Manufacturers Association (NEMA)
Document Control Number: EPA-HQ-OAR-2008-0508-0621.1
Comment Excerpt Number: 20
Comment: The NEMA Carbon/Manufactured Graphite EHS Committee's understanding from
§98.33(b)(4) is that the Tier 3 calculation method "may be used" (i.e., at the facility's discretion)
for a unit of any size and for any type of fuel, except when Tier 4 is required by the rule.
However, this is confused by the apparent indication in Table C-l and discussions in the
Preamble that Tier 3 is "required" for gaseous and liquid fossil fuel use when the combustion
unit size exceeds 250 mmBtu/hr. The NEMA Carbon/Manufactured Graphite EHS Committee
wanted to bring this apparent discrepancy to EPA's attention, and for the reasons explained
below, express our opinion that use of the Tier 1 and Tier 2 methods should be allowed by EPA
for estimating GHGs from combustion of gaseous and liquid fossil fuels available from
commercial sources, regardless of the size of the combustion unit(s). We are not familiar with
gaseous and liquid fuels that may be obtained from private wells, so are not offering an opinion
as to whether emissions from those fuel sources warrant use of the more complex Tier 3
calculation method.
Response: In response to comments, EPA has substantially revised §98.33(b), describing which
tier a reporter is to use. EPA has also expanded the use of the Tier 2 Calculation Methodology
for CO2 emissions to include units greater than 250 mmBtu/hr that combust only pipeline natural
gas and/or distillate oil.
312
-------
Commenter Name: Ronald H. Strube
Commenter Affiliation: Veolia ES Solid Waste
Document Control Number: EPA-HQ-OAR-2008-0508-0690.1
Comment Excerpt Number: 19
Comment: We request clarification of §98.33(b)(5)(ii). We believe that EPA's intent is to
require the use of the Tier 4 calculation only if a unit meets the requirements of all 6
subheadings, otherwise the Tier 4 calculation is not required. We are concerned that if it is
required for a single subheading, for instance (C): the unit has operated for more than 1,000
hours in any calendar year since 2005, this will include every landfill gas to energy project in the
U.S. Furthermore, this requires the installation of continuous monitoring equipment on the
stacks of each emission unit, a requirement that currently exceeds the vast majority of operating
air permits. The requirement to install this equipment by 2011 is unduly burdensome.
Response: See the Preamble section, "GHG Emissions Calculation and Monitoring, Calculating
C02 Emissions from Combustion" for a discussion of Tier 4.
EPA acknowledges the commenter's concerns regarding Tier 4 applicability. EPA has revised
the rule to clarify that all six criteria must be met before Tier 4 is required. The final rule
requires data collection for calendar year 2010, but has been changed since proposal to allow use
of best available monitoring methods for the first part of 2010.
Commenter Name: See Table 3
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0433.2
Comment Excerpt Number: 19
Comment: NPRA finds that the CEMs requirements proposed by EPA as Tier 4 monitoring in
40 CFR 98 Subpart C (proposed) for combustion sources burning solid fuels and municipal solid
waste (MSW) appear technically sound with respect to many such combustion sources, within
the limits of CEMs accuracy. However, unlike the Preamble, the proposed rule text in
§98.33(b)(5)(ii) is not clear in specifying that Tier 4 is required only for solid fuel-fired or
MSW-fired combustion sources. The rule text should be clarified to state that Tier 4 (CEMs)
monitoring is mandatory only if all of the conditions in §98.33(b)(5)(ii) (A) through (F) are met.
This would provide consistency between the Preamble and the final regulation and ensure that
facilities and enforcement personnel are clear on when a Tier 4 monitoring approach is required.
Response: EPA acknowledges the commenter's concerns regarding Tier 4 applicability. EPA
has revised the rule to clarify that all six criteria specified in subparagraphs (A) through (F) must
be met before Tier 4 is required.
313
-------
Commenter Name: Ron Downey
Commenter Affiliation: LWB Refractories
Document Control Number: EPA-HQ-OAR-2008-0508-0719.1
Comment Excerpt Number: 19
Comment: The proposed definition of "continuous emissions monitoring system" (CEMS) in
40 C.F.R. 98.6 includes those systems that have a gas extraction system or only a flow monitor.
The definition of CEMS is significant because facilities with CEMS are required to use the Tier
4 calculation methodology. The Proposed Rule's definition of CEMS is overbroad in that it
could be interpreted to include those facilities that only have a flow monitor or an in-situ
monitor. Sources with in-situ monitors could be required to send the monitor back to the
manufacturer for equipment upgrades and calibrations to upgrade to a monitor so that it is
capable of measuring CO2 emissions, which could take months based on previous experience.
This would result in the facility being out of compliance with other Clean Air Act monitoring
requirements (e.g., Title V). Sources with only a flow monitor could be required to install full
monitoring systems in order to measure C02. This definition of CEMS should be revised to
differentiate between monitors that can readily be upgraded to measure CO2 and those that
cannot. LWB proposes that the definition of CEMS in 40 C.F.R. 98.6 be revised as follows:
"Continuous emission monitoring system or CEMS means the total equipment required to
sample, analyze, measure, and provide, by means of reading recorded at least once every 15
minutes, a permanent record of gas concentrations, and pollutant emissions rates from stationary
sources that have a gas extraction system." LWB's proposed definition is consistent with EPA's
intent to require sources to make use of existing equipment and not impose substantial
operational burdens by the need to add an entire gas extraction system.
Response: EPA disagrees with the commenter's suggestion, and intends for Tier 4 to apply to
sources where installed CEMS include a gas monitor of any kind, or a stack gas volumetric flow
monitor, or both, provided that the source meets all of the other conditions specified in the rule.
The Tier 4 CEMS requirement is limited to larger solid fossil fuel units with an existing pollutant
CEMS and which include a certified gas monitor of any kind or a stack gas volumetric flow rate
monitor. EPA is requiring the use of CEMS due to the complexity of monitoring solid fuel
consumption and the heterogeneous nature of the solid fuels. Many of these fossil-fuel fired
units with a pollutant CEMS have an existing diluent monitor (O2 or CO2) that can be used to
determine CO2 emissions.
Commenter Name: Kyle Pitsor
Commenter Affiliation: National Electrical Manufacturers Association (NEMA)
Document Control Number: EPA-HQ-OAR-2008-0508-0621.1
Comment Excerpt Number: 19
Comment: The citation on page 16634 under §98.33(b)(5)(ii)(c) appears to require any
combustion unit that has operated for more than 1,000 hours in any calendar year since 2005 to
use the Tier 4 Calculation Method, and therefore would require the installation and operation of
CEMS even if this monitoring equipment is not currently installed. (Since there is no "and"
provided in the list of criteria, the NEMA Carbon/Manufactured Graphite EHS Committee has
therefore interpreted the requirement to apply to any one listed criterion "or" another.) Firstly,
314
-------
each facility may be unable to establish the annual hours of operation of each stationary fuel
combustion unit since 2005, as it was not a past legal requirement to maintain such
documentation of operations. There is no convincing reason or known legal precedent to go
back to historical operations records several years before a reporting rule becomes effective.
Even if this operational documentation is available at a facility, this language is totally
unfounded and unnecessary for the same arguments as above, i.e., sufficiently accurate and
consistent fuel usage data can be collected and GHG emissions estimated using standard
recognized protocols without this additional burden on the regulated community. The number of
hours of operation would have negligible impact on the accuracy or consistency of using any of
the other recognized GHG emission estimation methods, using readily available fuel usage data
and default emission factors available for all the common fuels. Secondly, according to Table
C-l in the Preamble, this criterion only applies to combustion units burning > 250 mmBtu/hour
solid fossil fuels or > 250 tons/day municipal solid waste (MSW). Liquid and gaseous fossil
fuels, in particular, natural gas, are amongst the cleanest burning and homogenous fuels
available, so that this 1,000 hour per year operation time criteria should not apply to them. On
page 11 of EPA's Technical Supporting Document (TSD) for the proposed rule, dated Jan 30,
2009, Section 3.2.1 Tier 4 Methodology also indicates that CEMS are being required for large
solid fuel units and MSW units, where there is uncertainty in heating value and carbon content.
Default emission factors are available and sufficiently accurate for gaseous and liquid fossil
fuels, so Tier 1 or Tier 2 (if monthly high heating value information is available) should be
acceptable. The §98.33(b)(5)(ii)(c) language in the Final Rule should be written to be clearer
and consistent with Table C-l. This language, unless clarified, could conceivably make a large
number of covered facilities unnecessarily install and operate CEMS. In summary, the NEMA
Carbon/Manufactured Graphite EHS Committee believes that EPA should not require CEMS at
any reporting facilities, regardless of quantities or types of fuels combusted each year, that are
not currently required to have them under other existing air permitting or other regulatory
programs, as there is insufficient justification for EPA to make the monitoring or recordkeeping
requirements for GHGs more onerous than existing programs for regulated priority pollutants or
hazardous air pollutants. This is especially true for purchased gaseous and liquid fossil fuels,
which are largely homogenous and for which credible alternative emissions estimation protocols
based on metered fuel usage already exist. Similarly, a requirement to install CEM on units for
which limited or no other regulatory requirements exist due to "grandfather" status under state air
permitting programs appears to be unjustified.
Response: EPA acknowledges the commenter's concerns regarding Tier 4 applicability. EPA
has revised the rule to clarify that all six criteria specified in must be met before Tier 4 is
required.
Commenter Name: Lauren E. Freeman
Commenter Affiliation: Hunton & Williams LLP
Document Control Number: EPA-HQ-OAR-2008-0508-0493.1
Comment Excerpt Number: 27
Comment: UARG also notes that its acceptance of a requirement for ARP units to rely on their
Part 75 cumulative CO2 mass emissions estimates is limited to this rulemaking, and might not
extend to rules regulating emissions of CO2. CO2 mass emissions data reported under Part 75
are affected by a rule requiring so-called "bias" adjustment of volumetric flow monitor data
315
-------
based on the results of a statistical analysis of relative accuracy test audit ("RATA") data
comparing the flow monitor's response to data from an EPA reference method. See, e.g., Part
75, Appendix A, §7.6. If the RATA data are determined to be "biased" based on a one-tailed
test, all hourly volumetric flow monitor data from the time of that RATA forward are adjusted
"upward" by a calculated bias adjustment factor — called a "BAF" — until the next RATA and
bias test are conducted. UARG has opposed this requirement from the start of the ARP. In
UARG's view, the test, which is based on data from a single stack test, does not represent true
"bias." The test also does not allow for adjustment of data downward if the test indicates that the
so-called "bias" in the data is positive. Adjustment of volumetric flow monitoring data in this
manner can result in a significant difference in the reported, versus the measured, CO2 mass
emissions. When EPA has relied upon Part 75 data in other regulatory programs, like the NSPS,
EPA has always made clear that sources are to use the unadjusted data, which is also recorded.
See, e.g., 40 C.F.R §§60.48Da(j)(2), (k)(ii), 60.49Da(c)(2) and (d). However, because Part 75
does not require calculation of hourly CO2 mass emissions in its "unadjusted" form (only
unadjusted hourly volumetric flow data are reported), using unadjusted data for the purposes of
this rule would require additional calculations and software changes for ARP units. ARP units
could not rely on their reported cumulative values. As a result, UARG is not seeking an
alternative to report unadjusted data at this time, but may do so in a future rulemaking if the data
are to be used for regulatory purposes.
Response: Under this rulemaking, EPA is not revising Part 75 reporting requirements. See the
Preamble, Section III. C., the Subpart D comment response document volume, and the response
to comment EPA-HQ-OAR-2008-0508-0956.1 excerpt 20 for the rationale for using substitute
data reported under Part 75.
Commenter Name: See Table 3
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0433.2
Comment Excerpt Number: 58
Comment: In Section 98.33(c)(2)(i) for General Stationary Fuel Combustion Sources, clarify
the language to insure that HHV can be determined by the owner/operator. As currently written,
it can be interpreted to only allow HHV as being measured or provided by the "entity supplying
the fuel". In Table C-l, the CO2 factors are based on HHV, and the text should state this
explicitly. Also, the source of the emission factors is not referenced.
Response: EPA has added language in §98.33 clarifying that either the owner or operator or the
fuel supplier may be responsible for the sampling and analysis for HHV. Section 98.34 further
clarifies that the fuel sampling may be performed by the owner or operator, the fuel supplier, or
an independent laboratory. EPA has also added flexibility to the use of the four tiers, and has
reduced the frequency of required sampling for many fuels, including natural gas. To simplify
the emission calculations in Tiers 2 and 3, averaging of HHV and carbon content data is
permitted if these data are obtained at least at the minimum frequency specified in §98.34. If the
results of fuel sampling are received monthly or more frequently, the weighted annual average
high heat value shall be calculated using Equation C-2b. If the results of fuel sampling are
received less frequently than monthly, then the annual average HHV shall be calculated using the
arithmetic average HHV for all valid samples for the year. EPA has included similar equations
316
-------
for units combusting solid and liquid fuels using Tier 3. However, for gaseous fuels using Tier
3, EPA has decided to require facilities to use average carbon content determinations and fuel
consumption for each measurement period (as specified in §98.34).
EPA believes that the note below Table C-l in §98.38 sufficiently states that the C02 emission
factors are based on HHV. The Agency refers the commenter to Appendix C of the Technical
Support Document for Stationary Fuel Combustion Emissions (EPA-HQ-OAR-2008-0508-0004)
for the source of the emission factors.
Commenter Name: See Table 6
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0679.1
Comment Excerpt Number: 106
Comment: §98.33(d), Equation C-l 1. This equation appears to be missing a term - a
conversion "moles acid gas removed/mole sorbent." The units of the equation as presented do
not currently result in metric tons C02 emitted.
Response: EPA has corrected this error in the final rule. The R term has been redefined as
"1.00, the calcium-to-sulfur stoichiometric ratio."
Commenter Name: See Table 6
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0679.1
Comment Excerpt Number: 105
Comment: Pg 16635, §98.33(c)(4) - Section 98.33(c)(4) refers to Table C-4 when referencing
CH4 and N20 emission factors but there is no Table C-4. The reference should be revised to
Table C-3.
Response: In the final rule, the original language in §98.33(c)(4) has been deleted.
Commenter Name: See Table 6
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0679.1
Comment Excerpt Number: 104
Comment: §98.33(b)(5)(ii) and (iii) - EPA should revise paragraphs §98.33(b)(5)(ii) and (iii) to
emphasize that the Tier 4 calculation methodology must be used for units that combust solid
fuels or MSW and that meet the requirements in the subparagraphs. As stated in the Preamble on
page 16483 "The most stringent emissions calculation methods would apply to large stationary
combustion units that are fired with solid fuels and that have existing CEMS equipment." Thus,
if a combustion unit does not burn solid fuel or MSW, it is optional for the owner or operator to
317
-------
use Tier 4 (CEMS) according to §98.33(b)(5)(i). API suggests revising §98.33(b)(5)(ii) and (iii)
to read as follows: (5) The Tier 4 Calculation Methodology: (I) May be used for a unit of any
size, combusting any type of fuel, (ii) Shall be used for a unit if: (A) The unit has a maximum
rated heat input capacity greater than 250 MMBtu/hr, or if the unit combusts municipal solid
waste and has a maximum rated input capacity greater than 250 tons per day of MSW, and (B)
The unit combusts solid fossil fuel or MSW, either as a primary or secondary fuel, and (C) The
unit has operated for more than 1,000 hours in any calendar year since 2005, or (D) The unit
meets the criteria in (B) and (C) directly above, and (E) The unit has installed CEMS that are
required either by an applicable Federal or State regulation or the unit's operating permit, and (F)
The installed CEMS include a gas monitor of any kind, a stack gas volumetric rate monitor, or
both and the monitors have been certified in accordance with the requirements of Part 75 of this
chapter, Part 60 of this chapter, of an applicable State continuous monitoring program, and (G)
The installed gas and/or stack gas volumetric flow rate monitors are required, by an applicable
Federal or State regulation of the unit's operating permit, to undergo periodic quality assurance
testing in accordance with Appendix B to Part 75 of this chapter, Appendix F to Part 60 of this
chapter, or an applicable State continuous monitoring program, (iii) Shall be used for a unit with
a maximum rated heat input capacity of 250 MMBtu/hr or less and for a unit that combusts
municipal solid waste with a maximum rated input capacity of 250 tons of MS W per day or less,
if the unit: (A) Has both a stack gas volumetric flow rate monitor and a C02 concentration
monitor, and (B) The unit meets the other conditions specified in paragraphs (b)(5)(ii)(B) of this
section, and (C) The C02 and stack gas volumetric flow rate monitors meet the conditions
specified in paragraphs (b)(5)(ii)(D) through (b)(5)(ii)(F) of this section.
Response: EPA acknowledges the commenter's concerns regarding Tier 4 applicability. EPA
has revised the rule to clarify that all six criteria must be met before Tier 4 is required.
Commenter Name: See Table 6
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0679.1
Comment Excerpt Number: 102
Comment: §98.33(a)(4)(iii), Equation C-7. The units for the variable CO2 (calculated using
Equation C6) should be changed from (tons/hr) to (metric tons/hr). This change is consistent
with the stated units for the variable CO2 as defined in Equation C-6.
Response: EPA has corrected this error in the final rule.
Commenter Name: See Table 6
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0679.1
Comment Excerpt Number: 101
Comment: §98.33(a)(4)(ii), Equation C-6. The units for the conversion factor 5.18 x 10"7
should be changed from (tons/scf-% CO2) to (metric tons/scf-% CO2). This change is consistent
318
-------
with the conversion of the original constant [5.7 x 10"7 (tons/scf-% C02), as presented in 40 CFR
§75, Appendix F] to metric units for the proposed rule.
Response: EPA has corrected the unit label for the conversion factor. It now reads
(metric tons/scf/% C02). EPA believes that the value of the conversion factor provided in
Equation C-6 is accurate, given these revised units.
Commenter Name: Karen St. John
Commenter Affiliation: BP America Inc. (BP)
Document Control Number: EPA-HQ-OAR-2008-0508-0631.1
Comment Excerpt Number: 65
Comment: EPA lays out a four tiered monitoring system based on fuel type and unit size.
There is a conflict between language in the Preamble of the proposed rule and the text shown in
Subpart C of the rule. The Preamble states that continuous emission monitoring systems
(CEMS) are only required for combustion devices fired by solid fuels, or otherwise required by
existing rules or permits. However, the rule language regarding selection of the "Tier" level
(Section 98.33(b)(5)), as currently written, would require CEMS for any combustion unit that has
a maximum rated heat input greater than 250,000 Btu/hr. or that ran for more than 1,000 hours in
any year since 2005. EPA should eliminate the conflict by modifying the language in the rule to
match the Preamble and to emphasize Tier 4 calculation methodology must only be used for
units that combust solid fuels or MSW and that meet the requirements in the subparagraphs.
Section 98.33(b)(5)(i) through (iii) should be replaced with the following text: (5) The Tier 4
Calculation Methodology: (i) May be used for a unit of any size, combusting any type of fuel,
(ii) Shall be used for a unit if: (A) The unit has a maximum rated heat input capacity greater than
250 mmBtu/hr, or if the unit combusts municipal solid waste and has a maximum rated input
capacity greater than 250 tons per day of MSW, and (B) The unit combusts solid fossil fuel or
MSW, either as a primary or secondary fuel, and (C) The unit has operated for more than 1,000
hours in any calendar year since 2005, or (D) The unit meets the criteria in (B) and (C) directly
above, and (E) The unit has installed CEMS that are required either by an applicable Federal or
State regulation or the unit's operating permit, and (F) The installed CEMS include a gas monitor
of any kind, a stack gas volumetric flow rate monitor, or both and the monitors have been
certified in accordance with the requirements of part 75 of this chapter, part 60 of this chapter, or
an applicable State continuous monitoring program, and (G) The installed gas and/or stack gas
volumetric flow rate monitors are required, by an applicable Federal or State regulation or the
unit's operating permit, to undergo periodic quality assurance testing in accordance with
appendix B to part 75 of this chapter, appendix F to part 60 of this chapter, or an applicable State
continuous monitoring program, (iii) Shall be used for a unit with a maximum rated heat input
capacity of 250 mmBtu/hr or less and for a unit that combusts municipal solid waste with a
maximum rated input capacity of 250 tons of MSW per day or less, if the unit: (A) Has both a
stack gas volumetric flow rate monitor and a CO2 concentration monitor, and (B) The unit meets
the other conditions specified in paragraphs (b)(5)(ii)(B) and (C) of this section, and (C) The
CO2 and stack gas volumetric flow rate monitors meet the conditions specified in paragraphs
(b)(5)(ii)(D) through (b)(5)(ii)(F) of this section. Based on the EPA discussion in the Preamble
to the proposed rule, BP is concerned that it is EPA's position that any CEM can be converted to
a CO2 CEM. The difficulty of converting an existing CEM to CO2 is a function of a number of
issues including existing metering and capacity. For this reason, clarification should be added to
319
-------
Section 98.33(b)(5)(ii)(E) and (F) to indicate the "installed CEMS" are referring to existing C02
CEMS and not any type (i.e., criteria pollutant) of CEM.
Response: See the response to comment EPA-HQ-OAR-2008-0508-0455.1 excerpt 7 and the
response to comment EPA-HQ-OAR-2008-0508-0580 excerpt 10 for EPA's rationale and
approach to the use of CEMS.
EPA acknowledges the commenter's concerns regarding Tier 4 applicability. EPA has revised
the rule to clarify that all six criteria specified in subparagraphs (A) through (F) must be met
before Tier 4 is required. However, EPA disagrees with suggestions that Tier 4 should only be
required if the installed CEMS include a C02 monitor. The Tier 4 CEMS requirement is limited
to larger solid fossil fuel units with an existing pollutant CEMS or volumetric flow rate monitor.
EPA is requiring the use of CEMS due to the complexity of monitoring solid fuel consumption
and the heterogeneous nature of the solid fuels. Many of these fossil-fuel fired units with a
pollutant CEMS have an existing diluent monitor (02 or C02) that can be used to determine C02
emissions. EPA's estimates of monitoring costs are averages for a representative facility and
may not represent the actual cost in individual circumstances.
EPA acknowledges the commenter's concerns, and in the final rule has added language to clarify
that all three conditions in §98.33 must be met before requiring the use of Tier 4.
Commenter Name: See Table 3
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0433.2
Comment Excerpt Number: 64
Comment: The units of measure for the emission factors in Tables C-l and C-3 should be in
tonne/yr rather than kg/yr. Based on this, are the numerical values listed for these emission
factors in Tables C-l and C-3 correct since the units of measure are not consistent with the
equations used in Subpart Y? The units of measure should be in tonnes/yr.
Response: EPA disagrees with the commenter, and believes the emission factors in the Subpart
C tables are correct as written. The equations used in Subparts C and Y take emission factors in
kg/mmBtu except where other default values are provided, and these are the units of the factors
in the tables.
Commenter Name: Fiji George
Commenter Affiliation: El Paso Corporation
Document Control Number: EPA-HQ-OAR-2008-0508-0398.1
Comment Excerpt Number: 39
Comment: Sections 98.33(a)(2)(i) and 98.33(a)(3)(iii), specifically equations C-2a and C-5,
require that C02 emissions be calculated using monthly fuel consumption and gas characteristic
obtained on a monthly basis for Tier 2 and Tier 3, respectively. El Paso recommends, for units
that use highly homogeneous fuels such as pipeline quality natural gas, the relevant equations be
320
-------
modified to allow using annual fuel volumes and annual average gas characteristics. Appendix
IV provides a sample calculation of CO2 emissions for natural gas fired units at an El Paso
facility. [SeeDCN: EPA-HQ-2008-0508-0398.1] The emissions are calculated based on actual
fuel consumption and actual gas properties using each methodology and then compared. As
demonstrated by this example, the change in emissions resulting from methodology change is
negligible considering fuel meter accuracy. However, this simplification will greatly reduce the
cost of setting up the reporting systems. None of the states or voluntary programs to which El
Paso is reporting emissions of criteria pollutants requires that the reporting data be based on
monthly operating data. Therefore, most likely reporters using Tier 2 or Tier 3 for GHG
reporting in accordance with this proposed regulation will not be able to build on the systems
already in place but will have to develop new systems which are time and resource consuming
(with very little benefit). The proposed simplification would reduce the time of setting up the
reporting system about 6 times (two basic calculations instead of thirteen) without considerable
impact on the quality of the reported emissions. In addition, the emissions of CH4 and N2O are
required to be calculated based on annual fuel consumption. The above described change will
allow using the same fuel basis for all pollutants resulting in even greater streamlining of the
calculations.
Response: The mandatory monthly fuel sampling and analysis requirements for traditional
fossil fuels have been dropped from Tiers 2 and 3. EPA agrees with the commenters that for a
homogeneous fuel such as pipeline natural gas, monthly sampling is not necessary. For other
fuels such as oil and coal, which are delivered in shipments or lots, requiring monthly sampling
may be impractical; new fuel lots or deliveries may not be received on a monthly basis.
Therefore, §98.34 has been revised to require that natural gas be sampled semiannually. For fuel
oil and coal, a representative sampling is required for each fuel lot, i.e., for each shipment or
delivery. For other liquid fuels and biogas, quarterly sampling is required. For other solid fuels,
excluding municipal solid waste, weekly composite sampling with monthly analysis is required.
For other gaseous fuels, the daily sampling requirement has been retained, but only for facilities
with existing equipment in place that is capable of providing the data. Otherwise, weekly
sampling is required, which may be postponed in favor of monthly sampling until 2011 if new
equipment must be purchased or if existing equipment must be upgraded to meet the weekly
sampling and analysis requirements.
The final rule clarifies that fuel sampling and analysis data provided by the supplier may be used
in the emission calculations, and that fuel billing meters may be used to quantify fuel
consumption. To simplify the emission calculations in Tiers 2 and 3, averaging of HHV and
carbon content data is permitted if these data are obtained at least at the minimum frequency
specified in §98.34. If the results of fuel sampling are received monthly or more frequently, the
weighted annual average high heat value shall be calculated using Equation C-2b. If the results
of fuel sampling are received less frequently than monthly, then the annual average HHV shall
be calculated using the arithmetic average HHV for all valid samples for the year. However,
regardless of the sampling frequency, the owner or operator must use the results of all available
valid fuel analyses in the emissions calculations.
321
-------
Commenter Name: See Table 3
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0433.2
Comment Excerpt Number: 62
Comment: At §98.33(a)(4)(i), the proposal cites "paragraph (a)(l)(iv)(D) of this section." No
such paragraph exists in the proposed rule. We request clarification or correction of this citation.
Clarification on the Tiers for methodology in Subpart C is needed. Each of the conditions listed
under Tier 4 (5)(ii) states that Tier 4 methodology "shall be used if, and then lists conditions
labeled A,B,C,D,E,F. These conditions do not have punctuation, including "and"s or "or"s.
NPRA proposes that they should be labeled "and" not "or" to show that all conditions must be
met to be required to comply with the Tier 4 methodology. Currently the rule language is
labeled neither. It is only implied to be "and".
Response: EPA acknowledges the commenter's concerns regarding Tier 4 applicability. EPA
has revised §98.33(b) of the final rule to clarify that all six criteria specified in subparagraphs
(A) through (F) must be met before Tier 4 is required. In addition, the paragraph referenced in
the comment (§98.33(a)(4)(i) in the final rule) now refers to §98.33(a)(4)(iv).
Commenter Name: Marc J. Meteyer
Commenter Affiliation: Compressed Gas Association (CGA)
Document Control Number: EPA-HQ-OAR-2008-0508-0981.1
Comment Excerpt Number: 18
Comment: The proposed rule defines the applicability of the alternate calculation method
"tiers" based on combustion unit size and availability of data, with a general trend to require
more rigorous calculation methods (e.g. increasing from Tier 1 to Tiers 2, 3, and 4) for higher
operating capacity units and facilities that currently employ certain process or emission
measurements. This push for more rigorous calculation methods is made without regard for a)
the underlying accuracy of the calculation method, b) the quality and completeness of existing
process or emission measurement, or the cost of the necessary measurement equipment or
practice. The result is a rule that often requires a costly, laborious measurement/calculation
method that does not improve the accuracy or completeness of the emission estimate. In many
instances, less rigorous calculation methods (e.g. "lower" Tiers) will yield comparable (or better)
accuracy emission estimates, with higher reliability and at lower cost. There is an implied
assumption that directly measured emissions will yield a better emission estimate. This
presumption is not true, as evidenced by an acceptable level of (in)accuracy tolerance under
CEMS certification/calibration procedures (> 5 - 7%) versus levels of fuel consumption metering
employed for invoice billing (typically < 2%). CGA Comment: EPA should be more flexible as
it relates to the applicability to the alternate combustion emission calculation methods. In
particular: Allow use of the Tier 1 method for units of any size (currently restricted to units
< 250 mmBTU/hr or less), particularly for standard fuels of commerce such as natural gas, LP
gas and fuel oils, where billing-quality consumption data is accurate and readily available and
the default HHV and CO2 emission factors are well known constants (as noted in the Preamble
for the proposed rule - natural gas carbon content is always within 1% of the default ratio).
Recognize that a source's current practices of occasionally characterizing fuels for HHV or
322
-------
carbon content does not necessarily constitute having data "available" consistent with the
compliance expectations of Tiers 2 and 3. Where Tiers 2 or 3 would be required, existing fuel
characterization may not be according to the specified analytical methods or at the required
frequency. Do not require Tier 2 or 3 where data fully meeting the defined compliance
expectation is not currently being obtained. Do not require the use of the Tier 4 method where
alternative fuel consumption data is available; allow optional use of the Tier 4 method at the
source's discretion. This may be a suitable calculation method where a source uses multiple
fuels and/or non-commercial fuels or where existing CEMS systems include CO2 measurement
or can be modified at lower cost than alternative fuel consumption and/or characterization
devices/practices. In any case, let the regulated source determine which method is most cost
effective for their particular situation. This option is available in California's GHG mandatory
reporting program.
Response: See the Preamble, Section II. L., on General Monitoring Requirements for the overall
rationale for methodologies required under this rule, and the response to comment EPA-HQ-
OAR-2008-0508-0909.1 excerpt 4 and EPA-HQ-OAR-2008-0508-0580 excerpt 10 for the
rationale for methodologies required under Subpart C.
EPA acknowledges the commenter's concerns, and has substantially revised §98.33(b) in the
final rule, relaxing tier and calculation method applicability. EPA believes that the revised
language makes it clear which tier calculation method(s) a reporter may use. The revised rule
also adds considerable flexibility, allowing more reporters to use the lower tiers.
EPA has significantly expanded the use of Tier 1 and Tier 2 Calculation Methodologies. The
monthly fuel sampling and analysis requirements for Tiers 2 and 3 have been considerably
revised. Natural gas fired units are to be sampled semiannually. For fuel oil and coal, a
representative sampling is required for each fuel lot, i.e., for each shipment or delivery. For
other liquid fuels and biogas, quarterly sampling is required. For other solid fuels, excluding
municipal solid waste, weekly composite sampling with monthly analysis is required. For other
gaseous fuels, the daily sampling requirement has been retained, but only for facilities with
existing equipment in place that is capable of providing the data. Otherwise, weekly sampling is
required.
The final rule clarifies that fuel sampling and analysis data provided by the supplier may be used
in the emission calculations, and that fuel billing meters may be used to quantify fuel
consumption. To simplify the emission calculations in Tiers 2 and 3, averaging of HHV and
carbon content data is permitted if these data are obtained at least at the minimum frequency
specified in §98.34. If the results of fuel sampling are received monthly or more frequently, the
weighted annual average high heat value shall be calculated using Equation C-2b. If the results
of fuel sampling are received less frequently than monthly, then the annual average HHV shall
be calculated using the arithmetic average HHV for all valid samples for the year. However,
regardless of the sampling frequency, the owner or operator must use the results of all available
valid fuel analyses in the emissions calculations.
The Tier 4 CEMS requirement is limited to larger solid fossil fuel units with an existing pollutant
CEMS or volumetric flow rate monitor. EPA is requiring the use of CEMS due to the
complexity of monitoring solid fuel consumption and the heterogeneous nature of the solid fuels.
Many of these fossil-fuel fired units with a pollutant CEMS have an existing diluent monitor (O2
or CO2) that can be used to determine CO2 emissions.
323
-------
Commenter Name: Ron Downey
Commenter Affiliation: LWB Refractories
Document Control Number: EPA-HQ-OAR-2008-0508-0719.1
Comment Excerpt Number: 51
Comment: In Equation C-6 (40 C.F.R. 98.33), C02 = 5.18 x 10(-7) * CCo2 * Q needs to be
clarified. This formula is similar to the formula listed in Appendix F of Part 75, except that the
conversion factor in Part 75 is 5.7 x 10(-7). NLA requests clarification on why a different
conversion factor was used in the Proposed Rule. Similarly, the unit label for Cco2 is not
correct. It is shown as tons/scf - % C02, which is not mathematically correct. It should be
corrected to show (tons/scf)/% CO2 as shown in Appendix F of Part 75. Finally, this Equation
should be clarified so that the % C02 concentration (term CCo2) is not entered into the formula
as a decimal fraction. For example, if the % CO2 is 25% ,then 25 should be used in the formula,
not 0.25. This is because the conversion factor is in units of (tons/scf)/% CO. This is misleading
as most calculations using a percent call for the decimal fraction representation.
Response: EPA has corrected the unit label for the conversion factor. It now reads
(metric tons/scf/% C02). EPA believes that the value of the conversion factor provided in
Equation C-6 is accurate, given these revised units.
Commenter Name: Gregory A. Wilkins
Commenter Affiliation: Marathon Oil Corporation
Document Control Number: EPA-HQ-OAR-2008-0508-0712.1
Comment Excerpt Number: 50
Comment: EPA should be sure that in the final rule, that activity information and the time
period for factor information are compatible. For example, a monthly sample should be
multiplied by a monthly flow measurement, or the average of 12 monthly samples for factor data
(carbon content) should be multiplied by the annual flow data. EPA needs to provide
instructions on how reconciling the different time periods for activity data (flow) and factor data
(sampling) should take place.
Response: EPA has substantially revised §98.33(a). The Tier 2 and Tier 3 methods now contain
additional language clarifying how reporters are to reconcile the frequency of sample analysis
with the period for which fuel flow data is taken. For example, if, under Tier 2, a unit
determines the HHV of its fuel more than once a month, and has fuel consumption records for
each month, the unit should average the multiple HHV determinations arithmetically to arrive at
a single value for use in the calculation of emissions for that month. Similar specifications are
provided for HHV determined less frequently than monthly and for Tier 3 calculations.
324
-------
Commenter Name: Ron Downey
Commenter Affiliation: LWB Refractories
Document Control Number: EPA-HQ-OAR-2008-0508-0719.1
Comment Excerpt Number: 50
Comment: 40 C.F.R. 98.33(c)(4) refers to Table C-4, but no such table appears in the Proposed
Rule.
Response: In the final rule, the proposed §98.33(c)(4) language has been deleted.
Commenter Name: Ron Downey
Commenter Affiliation: LWB Refractories
Document Control Number: EPA-HQ-OAR-2008-0508-0719.1
Comment Excerpt Number: 49
Comment: 40 C.F.R. 98.33(a)(l)(4)(i) refers to "(a)(l)(iv)(D) of this section," but NLA was
unable to locate this provision. Did EPA intend to refer to 40 C.F.R. 98.33(a)(4)(i)?
Response: EPA has corrected this error. The paragraph referenced in the comment
(§98.33(a)(4)(i) in the final rule) now refers to §98.33(a)(4)(iv).
Commenter Name: See Table 5
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0480.1
Comment Excerpt Number: 43
Comment: In many cases, natural gas sector sources will have monthly high heating value
(HHV) data and will thus fall under the Tier 2 calculation approach based on measured rather
than default HHV. Similarly, Tier 3 requires monthly or more frequent fuel carbon content data.
For natural gas transmission, there is typically little month-to-month or day-to-day variability in
measured HHV or carbon content, but data tracking and report calculations will be more
burdensome if emissions need to be calculated for each source for time scales shorter than
annually. For sources with monthly (or more frequent) HHV or fuel carbon content
measurement and little variation in the gas quality for those measurements, operators should
have the option to complete the calculation annually based on the average of the twelve monthly
(or more frequent) HHV or fuel carbon content measurements. This will reduce reporting
burden without impacting report quality. For fuels such as pipeline quality natural gas that are
relatively homogeneous over extended time periods, average annual HHV or carbon content
should be allowed for calculating combustion emissions under Subpart C. If needed, a maximum
relative variability could be specified for this approach. INGAA recommends a target of 10% or
less variation in the measured HHV or carbon content relative to the annual average. In this
case, operators should be allowed to calculate combustion emissions based on the annual average
HHV or carbon content and annual fuel use. EPA should address this in §98.33 by clarifying
that the annual average can be used for fuel volume and HHV in Equation C-2a for Tier 2 and
325
-------
for fuel volume and carbon content in Equation C-5 for Tier 3 gaseous fuels. A similar
clarification should be added for Equation C-lOa regarding the use of annual average HHV and
annual fuel use for calculating annual combustion emissions of methane and nitrous oxide.
Response: EPA has added language in §98.33 clarifying that either the owner or operator or the
fuel supplier may be responsible for the sampling and analysis for HHV. Section 98.34(a)
further clarifies that the fuel sampling may be performed by the owner or operator, the fuel
supplier, or an independent laboratory. EPA has also added flexibility to the use of the four tiers,
and has reduced the frequency of required sampling for many fuels, including natural gas. To
simplify the emission calculations in Tiers 2 and 3, averaging of HHV and carbon content data is
permitted if these data are obtained at least at the minimum frequency specified in §98.34. If the
results of fuel sampling are received monthly or more frequently, the weighted annual average
high heat value shall be calculated using Equation C-2b. If the results of fuel sampling are
received less frequently than monthly, then the annual average HHV shall be calculated using the
arithmetic average HHV for all valid samples for the year. However, regardless of the sampling
frequency, the owner or operator must use the results of all available valid fuel analyses in the
emissions calculations. EPA has included similar equations for units combusting solid and liquid
fuels using Tier 3. However, for gaseous fuels using Tier 3, EPA has decided to require facilities
to use average carbon content determinations and fuel consumption for each measurement period
(as specified in §98.34).
Commenter Name: Marc J. Meteyer
Commenter Affiliation: Compressed Gas Association (CGA)
Document Control Number: EPA-HQ-OAR-2008-0508-0981.1
Comment Excerpt Number: 43
Comment: CGA Comment: EPA should be more flexible as it relates to the applicability to the
alternate combustion emission calculation methods. In particular: 1. Allow use of the Tier 1
method for units of any size (currently restricted to units < 250 mmBTU/hr or less), particularly
for standard fuels of commerce such as natural gas, LP gas and fuel oils, where billing-quality
consumption data is accurate and readily available and the default HHV and CO2 emission
factors are well known constants (as noted in the Preamble for the proposed rule - natural gas
carbon content is always within 1% of the default ratio). 2. Recognize that a source's current
practices of occasionally characterizing fuels for HHV or carbon content does not necessarily
constitute having data "available" consistent with the compliance expectations of Tiers 2 and 3.
Where Tiers 2 or 3 would be required, existing fuel characterization may not be according to the
specified analytical methods or at the required frequency. Do not require Tier 2 or 3 where data
fully meeting the defined compliance expectation is not currently being obtained. 3. Do not
require the use of the Tier 4 method where alternative fuel consumption data is available. Allow
optional use of the Tier 4 method where, at the source's discretion. This may be a suitable
calculation method where a source uses multiple fuels and/or noncommercial fuels or where
existing CEMS systems include CO2 measurement or can be modified at lower cost than
alternative fuel consumption and/or characterization devices/practices. In any case, let the
regulated source determine which method is most cost effective for their particular situation. 4.
Clarify the requirement to employ the Tier 4 calculation method. Resolve the apparent
discrepancy between the intent to limit Tier 4 to only Solid Fossil Fuel fired combustion units,
per Table C-l of the Preamble, with the actual imposition of Tier 4 described under
326
-------
§98.33(b)(5)(ii). Clarify that in order for Tier 4 to be required under §98.33(b)(5)(ii), all the
conditions under §98.33(b)(5)(ii)(A), (B), (C), and (D) must be met. Specifically, conditions
(A), (B), (C), and (D) should be separated by the word "and" - absent that, an implied "or"
would force this calculation method on many other combustion units for which it was not
intended. Further, do not require the use of the Tier 4 method where alternative fuel
consumption data is available. Tier 1, 2, and 3 offer viable alternatives for many combustion
sources that will yield comparable (and in many cases more) accurate emission estimates. Allow
optional use of the Tier 4 method where, at the source's discretion. This may be a suitable
calculation method where a source uses multiple fuels and/or non-commercial fuels or where
existing CEMS systems include CO2 measurement or can be modified at lower cost than
alternative fuel consumption and/or characterization devices/practices. In any case, let the
regulated source determine which method is most cost effective for their particular situation.
Response: See the Preamble, Section II. L., on General Monitoring Requirements for the overall
rationale for methodologies required under this rule, and the response to comment EPA-HQ-
OAR-2008-0508-0909.1 excerpt 4 and EPA-HQ-OAR-2008-0508-0580 excerpt 10 for the
rationale for methodologies required under Subpart C.
EPA acknowledges the commenter's concerns, and has substantially revised §98.33(b) in the
final rule, relaxing tier and calculation method applicability. EPA believes that the revised
language makes it clear which tier calculation method(s) a reporter may use. The revised rule
also adds considerable flexibility, allowing more reporters to use the lower tiers.
EPA has significantly expanded the use of Tier 1 and Tier 2 Calculation Methodologies. The
monthly fuel sampling and analysis requirements for Tiers 2 and 3 have been considerably
revised. Natural gas fired units are to be sampled semiannually. For fuel oil and coal, a
representative sampling is required for each fuel lot, i.e., for each shipment or delivery. For
other liquid fuels and biogas, quarterly sampling is required. For other solid fuels, excluding
municipal solid waste, weekly composite sampling with monthly analysis is required. For other
gaseous fuels, the daily sampling requirement has been retained, but only for facilities with
existing equipment in place that is capable of providing the data. Otherwise, weekly sampling is
required.
The final rule clarifies that fuel sampling and analysis data provided by the supplier may be used
in the emission calculations, and that fuel billing meters may be used to quantify fuel
consumption. To simplify the emission calculations in Tiers 2 and 3, averaging of HHV and
carbon content data is permitted if these data are obtained at least at the minimum frequency
specified in §98.34. If the results of fuel sampling are received monthly or more frequently, the
weighted annual average high heat value shall be calculated using Equation C-2b. If the results
of fuel sampling are received less frequently than monthly, then the annual average HHV shall
be calculated using the arithmetic average HHV for all valid samples for the year. However,
regardless of the sampling frequency, the owner or operator must use the results of all available
valid fuel analyses in the emissions calculations.
The Tier 4 CEMS requirement is limited to larger solid fossil fuel units with an existing pollutant
CEMS or volumetric flow rate monitor. EPA is requiring the use of CEMS due to the
complexity of monitoring solid fuel consumption and the heterogeneous nature of the solid fuels.
Many of these fossil-fuel fired units with a pollutant CEMS have an existing diluent monitor (O2
or CO2) that can be used to determine CO2 emissions.
327
-------
Commenter Name: Fiji George
Commenter Affiliation: El Paso Corporation
Document Control Number: EPA-HQ-OAR-2008-0508-0398.1
Comment Excerpt Number: 42
Comment: Section 98.33(c)(4) limits the use of alternative emission factors for natural gas
because default factors are published in Table C-3. El Paso requests extending the flexibility and
basis of N20 and CH4 emission factors to sources beyond Table C-3 and allowing emission
factors from other GHG estimation guidelines. As demonstrated by the EPA emission inventory,
the combined N20 and CH4 emissions in terms of C02e are less than one percent of the total
GHG emissions from stationary combustion. Flexibility in selection of N20 and CH4 emission
factors will allow facilities to meet multiple reporting obligations to states and/or voluntary
registries that may require different or equipment/control technology-specific factors for these
pollutants. For example, the State of New Mexico employs Intergovernmental Panel on Climate
Change (IPCC) based emission factors to report N20 and CH4 from stationary combustion
sources.
Response: EPA believes that default factors for listed fuel types in Subpart C are sufficient for
reporting. EPA has clarified the rule to state that any emissions from unit startup or ignition, as
well as from those fuels not listed in Table C-2 (formerly C-3), can be excluded from
calculations of CH4 and N20.
Commenter Name: Karen St. John
Commenter Affiliation: BP America Inc. (BP)
Document Control Number: EPA-HQ-OAR-2008-0508-0631.1
Comment Excerpt Number: 63
Comment: Section 98.38, Table C-3: CH4 and N20 factors should be provided for the
following fuel types currently listed in §98.3 8, Table C-l: Ethane; Biogas; Isobutane; n-Butane;
Natural Gasoline; Other Oil (> 401 def. F); Pentanes Plus; Petrochemical Feedstocks; Special
Naphtha; and Unfinished Oils.
Response: In response to the comment, EPA has revised the default emission factors needed to
calculate CH4 and N20 emissions, adding some of the emission factors suggested by
commenters. EPA has clarified in the final rule that only CH4 and N20 emissions from
combustion of those fuels listed in Table C-2 (formerly C-3) of Subpart C are required to be
reported. Further, reporting of CH4 and N20 emissions is not required for fuels that are used
exclusively for unit startup or ignition.
328
-------
Commenter Name: Lorraine Krupa Gershman
Commenter Affiliation: American Chemistry Council (ACC)
Document Control Number: EPA-HQ-OAR-2008-0508-0423.2
Comment Excerpt Number: 80
Comment: There appears to be a typographical error in Table C-3. The word 'Tites' is possibly
a misspelling of the word: 'Tires.'
Response: EPA has corrected this error in the final rule.
Commenter Name: Sam Chamberlain
Commenter Affiliation: Murphy Oil Corporation
Document Control Number: EPA-HQ-OAR-2008-0508-0625
Comment Excerpt Number: 24
Comment: EPA states in Sec. 98.33 Calculating GHG emissions: "(4) The Tier 3 Calculation
Methodology may be used for a unit of any size, combusting any type of fuel, except when the
use of Tier 4 is required or elected, as provided in paragraph (b)(5) of this section. (5) The Tier 4
Calculation Methodology: (i) May be used for a unit of any size, combusting any type of fuel,
(ii) Shall be used for a unit if: (A) The unit has a maximum rated heat input capacity greater than
250 mmBtu/hr, or if the unit combusts municipal solid waste and has a maximum rated input
capacity greater than 250 tons per day of MSW. (B) The unit combusts solid fossil fuel or
MSW, either as a primary or secondary fuel. (C) The unit has operated for more than 1,000
hours in any calendar year since 2005. (D) The unit has installed CEMS that are required either
by an applicable Federal or State regulation or the unit's operating permit. (E) The installed
CEMS include a gas monitor of any kind, a stack gas volumetric flow rate monitor, or both and
the monitors have been certified in accordance with the requirements of part 75 of this chapter,
part 60 of this chapter, or an applicable State continuous monitoring program. The Tier 4
Calculation Methodology (5)(ii) implies that Tier 4 methodology shall be used for any unit that
is: 1. greater than 250 MMBtu/hr, or 2. Combust solid fuel or MSW, or 3. Operated more than
1,000 hours in any calendar year since 2005, or 4. Unit has installed CEMS that are required by
Federal or State Regulation or operating permit, or 5. The installed CEMS include a gas monitor
of any kind, a stack gas volumetric flow rate monitor, or both and the monitors have been
certified in accordance with the requirements of part 75 of this chapter, part 60 of this chapter, or
an applicable State continuous monitoring program. This will automatically place every unit that
has operated more than 1000 hours in a year regardless of size or fuel source will have to use
Tier 4 Methodology. Also, that any unit that has a CEMS of any size will have to use Tier 4
Methodology. This is so broad that it will likely cause every source in the US to fall under Tier
4. Murphy recommends that the language be changed to the following: (4) The Tier 3
Calculation Methodology may be used for a unit of any size, combusting any type of fuel, except
when the use of Tier 4 is required or elected, as provided in paragraph (b)(5) of this section. (5)
The Tier 4 Calculation Methodology: (i) May be used for a unit of any size, combusting any
type of fuel, (ii) Shall be used for a unit if: (A) The unit has a maximum rated heat input
capacity greater than 250 mmBtu/hr, or if the unit combusts municipal solid waste and has a
maximum rated input capacity greater than 250 tons per day of MSW, or (B) The unit combusts
solid fossil fuel or MSW, either as a primary or secondary fuel and the unit has operated for
329
-------
more than 1,000 hours in any calendar year since 2005, or (C) The unit has installed C02 CEMS
that are required either by an applicable Federal or State regulation or the unit's operating permit
and a stack gas volumetric flow rate monitor and the monitors have been certified in accordance
with the requirements of part 75 of this chapter, part 60 of this chapter, or an applicable State
continuous monitoring program.
Response: EPA acknowledges the commenter's concerns regarding Tier 4 applicability. EPA
has revised the rule to clarify that all six criteria must be met before Tier 4 is required. However,
EPA disagrees with suggestions that Tier 4 should only be required if the installed CEMS
include a CO2 monitor. The Tier 4 CEMS requirement is limited to larger solid fossil fuel units
with an existing pollutant CEMS or volumetric flow rate monitor. EPA is requiring the use of
CEMS due to the complexity of monitoring solid fuel consumption and the heterogeneous nature
of the solid fuels. Many of these fossil-fuel fired units with a pollutant CEMS have an existing
diluent monitor (O2 or CO2) that can be used to determine CO2 emissions.
Commenter Name: Kyle Pitsor
Commenter Affiliation: National Electrical Manufacturers Association (NEMA)
Document Control Number: EPA-HQ-OAR-2008-0508-0621.1
Comment Excerpt Number: 24
Comment: On page 16480 of the Preamble, although EPA notes that C02 emission generated
by fuel combustion far exceeds the CH4 and N2O emissions (< 1% of total), EPA nevertheless
has proposed that facilities must also estimate and report emissions of these two lesser GHGs.
While the NEMA Carbon/Manufactured Graphite EHS Committee agrees that all combustion
GHGs should be accounted for in the national GHG database for accuracy, it supports the use of
a combined CO2/CH4/N2O emission factor used by some of the internationally recognized GHG
emissions estimating protocols. This would simplify the calculation methods and reduce the
burden on reporting facilities, without significantly compromising the accuracy of the emissions
data.
Response: See the Preamble, Section II. C., and the response to comment EPA-HQ-OAR-2008-
0508-0561.1 excerpt 2 for information on the rationale for reporting for CH4 and N2O.
See the response to comment EPA-HQ-OAR-2008-0508-0686.1 excerpt 25 for the rationale for
reporting these gases separately.
EPA believes that using fuel-based default emission factors to report these gases separately
provides an appropriate balance between easing the reporting burden on facilities and collecting
useful data on GHG emissions.
330
-------
Commenter Name: Robert Rouse
Commenter Affiliation: The Dow Chemical Company
Document Control Number: EPA-HQ-OAR-2008-0508-0533.1
Comment Excerpt Number: 23
Comment: Dow Suggests Revisions to 98.33(c)(4) Regarding the Calculation of CH4 and N20
Emission Factors. Dow notes that 98.33(c)(4) refers to Table C-4; however, there is no Table C-
4. The correct reference appears to be Table C-3. In addition, Dow comments that the proposed
process of conducting emission testing to determine site-specific CH4 and N2O emission factors
via source testing will be an unwarranted cost to determine a very small emission factor. Either
EPA should exclude these emissions from the reporting requirements or allow the
owner/operator to estimate these emissions based on other factors and engineering estimations
when the fuel combusted is not specifically listed in Table C-3.
Response: In the final rule, the proposed language in §98.33(c)(4) has been deleted.
EPA acknowledges the concerns of the commenter. However, EPA has decided to retain in the
final rule the requirement to report CH4 and N20 from stationary combustion sources. EPA
believes that the use of fuel-specific emission factors for these pollutants strikes an appropriate
balance between minimizing the burden on reporters and obtaining valuable GHG emission data.
EPA has, however, revised the final rule to exclude CH4 and N2O emissions from fuels for
which the rule does not provide emission factors, and has deleted the provision allowing the
owner or operator of a facility to develop site-specific emission factors for such fuels. EPA
believes that this change will reduce the reporting burden on facilities.
Commenter Name: Patrick J. Nugent
Commenter Affiliation: Texas Pipeline Association (TPA)
Document Control Number: EPA-HQ-OAR-2008-0508-0460.1
Comment Excerpt Number: 23
Comment: Proposed §98.33(b)(5)(ii) should be written more precisely. Proposed
§98.33(b)(5)(ii) lists all of the requirements that must be met in order for Tier 4 to apply. The
requirements listed in (A) - (F) of proposed §98.33(b)(5)(ii) should make clear that all of those
requirements must be met for Tier 4 to be required. TPA suggests that the word "and" be placed
between (E) and (F) in order to make this clear.
Response: EPA acknowledges the commenter's concerns regarding Tier 4 applicability. EPA
has revised the rule to clarify that all six criteria must be met before Tier 4 is required.
331
-------
Commenter Name: Kyle Pitsor
Commenter Affiliation: National Electrical Manufacturers Association (NEMA)
Document Control Number: EPA-HQ-OAR-2008-0508-0621.1
Comment Excerpt Number: 23
Comment: If a facility opts to combine all its combustion units that are supplied by a common
gaseous or liquid fossil fuel supply piping configuration, which is equipped with a calibrated fuel
flow meter, for the purpose of simplifying its emissions calculations, the NEMA
Carbon/Manufactured Graphite EHS Committee understands the facility can do this regardless of
the total number of units or regardless of the total maximum rated heat input capacity of the
individual units or of the entire group. The NEMA Carbon/Manufactured Graphite EHS
Committee agrees this is an acceptable option. However, since EPA is not restricting the total
maximum rated heat input capacity of the combined units, the NEMA Carbon/Manufactured
Graphite EHS Committee believes that the facility should not be required to use the Tier 3
method to calculate CO2 emissions for any combustion unit > 250 mmBtu/hr. and that this
requirement should also not apply to these aggregated combustion units, where any one or more
of the units, or the total group of units exceeds this maximum rated heat input capacity. This
would potentially negate much of the main reason for aggregating multiple units, which is to
simplify the GHG emission calculations, if the facility would now have to use the more complex
calculation method for the entire group, requiring either daily or monthly measurements and
calculations. For the same reason already mentioned above, a fact to which EPA readily admits
in the Preamble, commercially-available gaseous and liquid fuels are typically homogenous so
there should be an insignificant variability in the carbon content. That fact coupled with the
expected accuracy of the typical supplier billing meter on common fuel supply piping, indicates
there would be no significant benefit to requiring the more onerous Tier 3 calculation method to
estimate GHG emissions for an aggregated group of units even if the total (or any of the
individual unit) maximum heat input capacity exceeds 250 mmBTU/hr. On page 16484 of the
Preamble under the discussion of Tier 1, EPA states it "considered" allowing the use of default
emission factors, default HHVs and company records to quantity annual fuel consumption for all
stationary combustion units, regardless of size or the type of fuel combusted, but "decided to
limit the use of this type of calculation methodology to smaller combustion units". However,
EPA provides absolutely no justification for this decision, which unnecessarily complicates the
emissions estimation procedures. Given the additional burden on reporting facilities, and the
arguments provided above, the NEMA Carbon/Manufactured Graphite EHS Committee requests
that EPA allow this simplified and generally accepted Tier 1 estimation procedure in the final
rule for all stationary combustion units regardless of size or the type of fuel combusted, at a
minimum to quantify annual consumption for commercially-available gaseous and liquid fuels
that have established default emission factors and HHVs.
Response: The final rule significantly expands the use of the Tier 1 and Tier 2 Calculation
Methodologies. The 250 mmBtu/hr restriction on the use of Tier 2 has been lifted for units that
combust natural gas and distillate oil, in view of the homogeneous nature and low variability in
the characteristics of these fuels. The monthly fuel sampling and analysis requirements for Tiers
2 and 3 have been considerably revised. Natural gas fired units are to be sampled semiannually.
For fuel oil and coal, a representative sampling is required for each fuel lot, i.e., for each
shipment or delivery. For other liquid fuels and biogas, quarterly sampling is required. For
other solid fuels, excluding municipal solid waste, weekly composite sampling with monthly
analysis is required. For other gaseous fuels, the daily sampling requirement has been retained,
332
-------
but only for facilities with existing equipment in place that is capable of providing the data.
Otherwise, weekly sampling is required.
For units that use Tiers 1, 2, and 3 to calculate CO2 mass emissions, the cumulative 250
mmBtu/hr heat input capacity limit on the aggregation of units into a group has been dropped.
Rather, the 250 mmBtu/hr restriction applies only to the individual units in the group. Therefore,
for reporting purposes, individual units with maximum rated heat input capacities of 250
mmBtu/hr or less may be aggregated without limit into a single group, provided that the Tier 4
methodology is not required for any of the units, and all units in the group use the same tier for
any common fuel(s) that they combust. Units with maximum rated heat inputs greater than 250
mmBtu/hr using Tiers 1, 2, and 3 must report as individual units, unless they burn the same type
of fuel provided by a common pipe or supply line; in that case, the owner or operator may opt to
use the common pipe reporting provisions in §98.36(c)(3).
Commenter Name: Sean M, O'Keefe
Commenter Affiliation: Hawaiian Commercial and Sugar Company (HC&S)
Document Control Number: EPA-HQ-OAR-2008-0508-1138.1
Comment Excerpt Number: 8
Comment: In the proposed rule, EPA has selected Option 2 (combination of direct
measurement and facility-specific calculations) as the general monitoring approach. Our
comments above notwithstanding, if this option is adopted in the final rule, then the language of
the rule needs to be revised to clarify when the use of CEMS for monitoring carbon dioxide
emissions is mandatory and when it is optional. Specifically, the proposed §98.33(b)(5) specifies
when the Tier 4 calculation methodology (i.e., calculating emissions from all fuels combusted in
a unit by using data from CEMS) may be used by general stationary fuel combustion sources and
when it shall be used. The current language is not clear regarding whether the Tier 4
methodology must be used when all of the conditions listed in §§98.33(b)(5)(ii)(A) through (F)
are met or when any one of the conditions is met; the language should be modified to make clear
that all of the conditions must be met (e.g., by adding the word "and" prior to
§98.33(b)(5)(ii)(F)). Similarly, the proposed §98.33(b)(5)(iii) should state that use of the Tier 4
methodology is mandatory only if all of the conditions listed in §§98.33(b)(5)(iii)(A) through (C)
are met (again, the word "and" could be added prior to §98.33(b)(5)(iii)(C)).
Response: EPA acknowledges the commenter's concerns regarding Tier 4 applicability. EPA
has revised the rule to clarify that all six criteria must be met before Tier 4 is required.
Commenter Name: Edgar O. Morris
Commenter Affiliation: Mosaic Fertilizer Company LLC
Document Control Number: EPA-HQ-OAR-2008-0508-0687.1
Comment Excerpt Number: 6
Comment: The proposal prescribes a specific methodology for calculating GHG emissions that
warrants clarification regarding the requirements for continuous emissions monitoring systems
("CEMS"). See proposed 40 C.F.R. §98.33. As EPA explained in the Preamble to the proposal,
333
-------
these methodologies are identified as "Tiers" 1 through 4, where each "Tier" involves increasing
complexity, detail and cost, and applies to larger and more complicated sources with larger
emissions for which a generic calculation would be more difficult (due to the type of fuel) and
where more investment is warranted. See proposed 40 C.F.R. §98.33(a)(1) through (4); see also
74 Fed. Reg. at 16,483 - 16484. Tier 4 is the most prescriptive and potentially burdensome
methodology. Compliance with Tier 4, rather than Tier 3, is in many instances substantial, since
Tier 4, requires, among other things, "a C02 concentration monitor and a stack gas volumetric
flow rate monitor." See proposed 40 C.F.R. §98.33(a)(4)(i). Tier 4 requirements apply to units
satisfying a number of criteria, including that the unit "has installed CEMS that are required
either by an applicable Federal or State regulation or the unit's operating permit", see proposed
40 C.F.R. §98.33(b)(5)(ii)(D), and that "The installed CEMS include a gas monitor of any kind, a
stack gas volumetric flow rate monitor, or both". See proposed 40 C.F.R. §98.33(b)(5)(ii)(E).
The NPRM defines CEMS broadly to include "the total equipment required to sample, analyze,
measure and provide, by means of readings recorded at least once every 15 minutes, a permanent
record of gas concentrations, pollutant emission rates, or gas volumetric flow rates from
stationary sources." See proposed 40 C.F.R. §98.6. Accordingly, Tier 4 requirements may apply
broadly to units with pre-existing CEMS. The proposed rule language is unclear as to whether a
unit must satisfy all of the criteria listed under the proposed Sections 98.33(b)(5)(ii) or (iii) (by
use of the word "and"), or whether Tier 4 requirements apply to units satisfying any one of these
requirements (by use of the word "or"). Table C-l of the Preamble indicates that the Tier 4
methodology is primarily used for large units combusting solid fuels and/or municipal solid
wastes. See 74 Fed. Reg. at 16,481. The Preamble discussion also seems to indicate that all of
the requirements of Sections 98.33(b)(5)(ii) or (iii) (depending on whether the unit has a
maximum rated heat capacity of 250 mmBtu/hr or more) must apply before Tier 4 monitoring is
required. See 74 Fed. Reg. at 16,483. Mosaic proposes that EPA add the conjunctive word
"and" at the end of subpart (E), and semi-colons in place of periods after each subpart (A)
through (E) in Section 98.33(b)(5)(ii); and similarly add the word "and" at the end of subpart (B),
and semi-colons in place of periods in subparts (A) and (B) in Section 98.33(b)(5)(iii).
Response: EPA acknowledges the commenter's concerns regarding Tier 4 applicability. EPA
has the rule to clarify that all six criteria must be met before Tier 4 is required.
See the response to comment EPA-HQ-OAR-2008-0508-0455.1 excerpt 7 and the response to
comment EPA-HQ-OAR-2008-0508-0580 excerpt 10 for EPA's rationale and approach to the
use of CEMS.
Many of these fossil-fuel fired units with a pollutant CEMS have an existing diluent monitor (O2
or CO2) that can be used to determine CO2 emissions. EPA's estimates of monitoring costs are
averages for a representative facility and may not represent the actual cost in individual
circumstances.
334
-------
Commenter Name: Marc J. Meteyer
Commenter Affiliation: Compressed Gas Association (CGA)
Document Control Number: EPA-HQ-OAR-2008-0508-0981.1
Comment Excerpt Number: 19
Comment: The proposed rule imposes the Tier 4 calculation methodology on sources meeting
the conditions specified under §98.33(b)(5)(ii). As worded, it appears any one of the (A), (B),
(C), or (D) conditions would result in the Tier 4 method being required. This does not match the
intent expressed in the Preamble to the proposed rule, and summarized in Preamble table C-l. In
particular, Table C-l appears to indicate that Tier 4 is required only for Solid Fossil Fuel fired
units > 250 mmBTU/hr (meeting other criteria, as well) and that Gaseous Fossil Fuel fired and
Liquid Fossil Fuel fired combustion units are required to use no more rigorous than Tier 3
methods. The current language of §98.33(b)(5)(ii) would imply any of the conditions described
in §98.33(b)(5)(ii)(A), (B), (C) or (D) trigger the Tier 4 method requirement. We believe the
agency's intent is that all of the conditions described in §98.33(b)(5)(ii)(A), (B), (C) and (D) are
necessary in order to trigger the Tier 4 method requirement. In addition, §98.33(b)(5)(ii)(E)
imposes the Tier 4 method if the source has any existing CEMS system. Depending on the type
of gas monitoring system a source may have (extractive vs. in-situ; wet vs. dry, etc.) the addition
of a CO2 CEMS can be a very costly modification. Modifications could include, assuming it is
even technically feasible, the addition of stack sampling ports, addition of extractive sampling
systems, sample conditioning systems, calibration gas systems and modification to data
acquisition and reporting systems and software. Based on CGA member company experience
these modifications can impose $40,000 to $250,000 of capital costs, as well as ongoing
maintenance and operating costs for such units. As stated above, these costs may be imposed on
the false premise that direct emission measurement via CEMS is an inherently more accurate
than alternative calculation methods (e.g. Tiers 1, 2, or 3). CGA Comment: Clarify the
requirement to employ the Tier 4 calculation method. Resolve the apparent discrepancy between
the intent to limit Tier 4 to only Solid Fossil Fuel fired combustion units, per Table C-l of the
Preamble, with the actual imposition of Tier 4 described under §98.33(b)(5)(ii). Clarify that in
order for Tier 4 to be required under §98.33(b)(5)(ii), all the conditions under
§98.33(b)(5)(ii)(A), (B), (C), and (D) must be met. Specifically, conditions (A), (B), (C), and
(D) should be separated by the word "and" - absent that, an implied "or" would force this
calculation method on many other combustion units for which it was not intended. Further, do
not require the use of the Tier 4 method where alternative fuel consumption data is available.
Tier 1, 2, and 3 offer viable alternatives for many combustion sources that will yield comparable
(and in many cases more) accurate emission estimates. Allow optional use of the Tier 4 method
where, at the source's discretion. This may be a suitable calculation method where a source uses
multiple fuels and/or non-commercial fuels or where existing CEMS systems include CO2
measurement or can be modified at lower cost than alternative fuel consumption and/or
characterization devices/practices. In any case, let the regulated source determine which method
is most cost effective for their particular situation.
Response: EPA acknowledges the commenter's concerns regarding Tier 4 applicability. EPA
has revised the rule to clarify that all six criteria must be met before Tier 4 is required. The Tier
4 CEMS requirement is limited to larger solid fossil fuel units with an existing pollutant CEMS
or volumetric flow rate monitor.
335
-------
See the response to comment EPA-HQ-OAR-2008-0508-0455.1 excerpt 7 and the response to
comment EPA-HQ-OAR-2008-0508-0580 excerpt 10 for EPA's rationale and approach to the
use of CEMS.
Many of these fossil-fuel fired units with a pollutant CEMS have an existing diluent monitor (02
or CO2) that can be used to determine CO2 emissions. EPA's estimates of monitoring costs are
averages for a representative facility and may not represent the actual cost in individual
circumstances.
Commenter Name: John M. McManus
Commenter Affiliation: American Electric Power
Document Control Number: EPA-HQ-OAR-2008-0508-0725.1
Comment Excerpt Number: 5
Comment: The CH4 and N20 emission factors presented in Table C-3 of subpart C (Default
CH4 and N2O Emission Factors for Various Types of Fuel) are not consistent with EPA's AP-42
emission factors that are historically used for regulatory reporting. In particular, CH4 emission
rates in Table C-3 are significantly higher (although a footnote to Table C-3 may address this).
AEP requests that EPA clearly authorize the use of the existing AP-42 emission factors for
purposes of GHG reporting from EGUs, or provide a reasoned explanation of the basis for any
alternative emission factors required by the rules.
Response: EPA believes the fuel types and respective default emission factors listed in Subpart
C are sufficient for reporting. For the purposes of the rule, which is data collection for policy
development, we would prefer consistent use of default CH4 and N2O emission factors. In this
case, we provide the values we would like reporters to use in Subpart C, and for verification
purposes, would prefer consistent use of these factors. Additional factors have been added as a
result of comments. EPA is using mostly IPCC values in Table C-3 because we are aware that
the AP-42 non-CC>2 factors haven't been reviewed in-depth recently.
Commenter Name: Sarah B. King
Commenter Affiliation: DuPont Company
Document Control Number: EPA-HQ-OAR-2008-0508-0604.1
Comment Excerpt Number: 26
Comment: According to the formulas provided in §98.33(c), only a fraction of a percent of the
greenhouse gas emissions from combustion would be CH4 or N2O. Therefore, EPA should not
require calculation and reporting of these emissions because their contribution to the total is
insignificant.
Response: See the Preamble, Section II. C., and the response to comment EPA-HQ-OAR-2008-
0508-0561.1 excerpt 2 for information on the rationale for reporting for CH4 and N2O.
EPA believes that the use of fuel-specific emission factors for these pollutants strikes an
appropriate balance between minimizing the burden on reporters and obtaining valuable GHG
336
-------
emission data. EPA has, however, revised the final rule to exclude CH4 and N20 emissions
from fuels for which the rule does not provide emission factors, and has deleted the provision
allowing the owner or operator of a facility to develop site-specific emission factors for such
fuels. EPA believes that this change will reduce the reporting burden on facilities.
Commenter Name: Lorraine Krupa Gershman
Commenter Affiliation: American Chemistry Council (ACC)
Document Control Number: EPA-HQ-OAR-2008-0508-0423.2
Comment Excerpt Number: 79
Comment: It is difficult to match the "fuel types" listed in Table C-3 to the "fuel types" listed in
Tables C-l and C- 2. This results because there are "fuel types" in Tables C-l and C-2 that do
not readily appear to have a counterpart "fuel type" in Table C-3. Examples are "coke,"
"ethane," "petrochemical feedstocks," "unfinished oils," "plastics" and "solvents" among others.
Does this imply that reporting entities do not need to report Table C-3 emissions from these fuel
types? There are also "fuel types" in Table C-3 that do not appear to have a counterpart "fuel
type" in Tables C-l and C-2. Examples are "digester gas," "landfill gas," "natural gas liquids"
and "refinery gas."
Response: EPA acknowledges the concerns of the commenters. The tables in Subpart C have
been substantially revised in the final rule. Table C-l has been expanded to include all fuels for
which CO2 emissions must be calculated and reported for facilities using the Tier 1 and Tier 2
Calculation Methodologies. Table C-2 has been deleted, and a revised C-3 is now called C-2.
Table C-2 includes all fuels for which CH4 and N2O emissions must be calculated and reported.
Commenter Name: Lorraine Krupa Gershman
Commenter Affiliation: American Chemistry Council (ACC)
Document Control Number: EPA-HQ-OAR-2008-0508-0423.2
Comment Excerpt Number: 78
Comment: There is an entry for 'Landfill gas' in Table C-3 of Subpart C and that term is defined
in §98.6. However, there is no entry for 'Landfill gas' in either Tables C-l or C-2.
Response: EPA acknowledges the concerns of the commenters. The tables in Subpart C have
been substantially revised in the final rule. Table C-l now includes biogas (captured methane).
Commenter Name: Lorraine Krupa Gershman
Commenter Affiliation: American Chemistry Council (ACC)
Document Control Number: EPA-HQ-OAR-2008-0508-0423.2
Comment Excerpt Number: 58
Comment: In §98.33(c)(4), it is not clear what EPA would be approving. As written, it appears
that EPA would approve whether a company can develop its own site-specific emission factors
(EFs); however, if no EFs are provided for its site-specific or unit-specific fuels, the company
must calculate its own EFs. Thus, no EPA approval should be required. A more appropriate
337
-------
approach would be that EPA may audit a site's specific EFs for calculation validity.
Furthermore, source testing will be an unwarranted cost to determine a very small emission
factor. Either EPA should exclude these emissions from the reporting requirements or allow the
owner/operator to estimate these emissions based on other factors and engineering estimations
when the fuel combusted is not specifically listed in Table C-3.
Response: EPA has excluded fuels that are not listed with default CH4 and N20 factors in
Subpart C, from the calculations of CH4 and N2O emissions.
Commenter Name: Lorraine Krupa Gershman
Commenter Affiliation: American Chemistry Council (ACC)
Document Control Number: EPA-HQ-OAR-2008-0508-0423.2
Comment Excerpt Number: 57
Comment: Section 98.33(c)(4) refers to Table C-4; however, there is no Table C-4. The correct
reference appears to be Table C-3.
Response: In the final rule, the proposed language in §98.33(c)(4) has been deleted.
Commenter Name: Lorraine Krupa Gershman
Commenter Affiliation: American Chemistry Council (ACC)
Document Control Number: EPA-HQ-OAR-2008-0508-0423.2
Comment Excerpt Number: 55
Comment: The criteria for when Tier 4 is required are confusing as written and we cannot
determine whether it is only required for MSW or solid fuel, or if it applies to other large (~ 250
MMBtu/hr) combustion units with liquid or gaseous fuels. In addition, the other criteria for
MSW and solid fuels listed in Tier 4 are also confusing. We recommend that EPA clarify the
Tier 4 requirements as follows: (1) Incorporate Table C-l from page 16481 of the Federal
Register containing the Preamble into the actual final rule. (2) Include the following excerpt
from Page 16483 of the Preamble into the final rule, "The Tier 4 method, and the use of CEMS
(with any required monitored upgrades) is required for solid fossil fuel-fired units with a
maximum heat input capacity greater than 250 MMBtu/hr (and for units with a capacity greater
than 250 tons per day of MSW)." (3) In §98.33(b)(5)(ii), include the word 'and' at the end of
each item (A) through (F) to clarify that each one is required and that EPA did not mean 'or'
between these items. (4) In §98.33(b)(5)(iii), include the word 3and' at the end of each item (A)
through (C) to clarify that each one is required and that EPA did not mean 3or' between these
items. There may be additional ways to improve the clarity of the applicability of the Tier 4
measuring requirements in §98.33(b)(5). ACC encourages EPA to find additional ways to
improve the clarity of this alternative. It is important that facilities be able to interpret this part
easily due to the costliness of installing and operating the CEMS equipment.
Response: EPA acknowledges the commenter's concerns regarding Tier 4 applicability. The
Agency has revised §98.33of the final rule to clarify that all six criteria must be met before Tier
4 is required.
338
-------
Commenter Name: Leslie Bellas
Commenter Affiliation: National Lime Association (NLA)
Document Control Number: EPA-HQ-OAR-2008-0508-0520.1
Comment Excerpt Number: 54
Comment: 40 C.F.R. §§98.33(a)(1) and (2) Should be Consistent with the Preamble, which
Permits Tier 1 and Tier 2 Facilities to Use the High Heat Value Obtained from Fuel Supply
Vendors.
Response: The final rule clarifies that fuel sampling and analysis data provided by the supplier
may be used in the emission calculations, and that fuel billing meters may be used to quantify
fuel consumption. To simplify the emission calculations in Tiers 2 and 3, averaging of HHV and
carbon content data is permitted if these data are obtained at least at the minimum frequency
specified in §98.34, but less frequently than monthly (see Equation C-2b). However, regardless
of the sampling frequency, the owner or operator must use the results of all available valid fuel
analyses in the emissions calculations.
Commenter Name: Leslie Bellas
Commenter Affiliation: National Lime Association (NLA)
Document Control Number: EPA-HQ-OAR-2008-0508-0520.1
Comment Excerpt Number: 53
Comment: 40 C.F.R. §§98.33(b)(5)(iii)(A) - (C) sets forth conditions for use of the Tier 4
methodology by units with a maximum rated heat input capacity of 250 mmBtu/hr or less and for
units that combust municipal solid waste. To clearly indicate that all three conditions must be
met before requiring use of the Tier 4 emission calculation methodology, each condition in 40
C.F.R. §§98.33(b)(5)(iii)(A) - (C) should end with a semi-colon, and that after the semicolon in
40 C.F.R. §98.33(b)(5)(iii)(B), the word "and" should be added.
Response: EPA acknowledges the commenter's concerns regarding Tier 4 applicability. EPA
has revised the applicability in the final rule to clarify that all criteria must be met before Tier 4
is required.
Commenter Name: Lawrence W. Kavanagh
Commenter Affiliation: American Iron and Steel Institute (AISI)
Document Control Number: EPA-HQ-OAR-2008-0508-0695.1
Comment Excerpt Number: 6
Comment: With respect to potential applicability of Tier 4, which we understand to apply to
large, solid fuel-fired combustion units, §98.33(b)(5) requires clarification. That paragraph
should be amended to make clear that all six criteria set forth in subsections (A) - (F) must be
met to trigger Tier 4 monitoring obligations. This section was apparently drafted to establish a
339
-------
six-part test for Tier 4 requirements, but as drafted the six criteria are stated independently. This
understanding is further substantiated by language in the Preamble that makes clear that Tier 4
applies to solid fossil-fired units over 250 MMBTUH. EPA should clarify §98.33(b)(5) by
inserting semicolons instead of periods after subparagraphs (A) - (E) and adding the word "and"
after subparagraph (E).
Response: EPA acknowledges the commenter's concerns regarding Tier 4 applicability. EPA
has revised the rule to clarify that all six criteria specified in subparagraphs (A) through (F) must
be met before Tier 4 is required.
Commenter Name: Sean M, O'Keefe
Commenter Affiliation: Hawaiian Commercial and Sugar Company (HC&S)
Document Control Number: EPA-HQ-OAR-2008-0508-1138.1
Comment Excerpt Number: 10
Comment: Table C-l of the proposed rule provides default CO2 emission factors and high heat
values for various types of fuel, including "wood and wood waste (12% moisture) or other solid
biomass-derived fuels". These factors are to be used when estimating carbon dioxide emissions
using the Tier 2 or Tier 1 methods. The default high heat value specified for "other solid
biomass fuels" is not appropriate for sugarcane bagasse, the fiber remaining after sugarcane is
milled which is the primary fuel burned in sugar mill boilers. Although sugarcane fiber has a
range of heat values similar to those of other biomass fuels, such as wood, the moisture content
of bagasse as burned is typically in the range of 45 to 55 percent. As a result, a more appropriate
default high heat value for sugarcane bagasse (at 50% moisture content) would be approximately
8.3 MMBTU/short ton. At a typical carbon content of 49% (dry basis), an appropriate default
CO2 emission factor for sugarcane bagasse would be 98.39 kg CO2/MMBTU. These values
should be incorporated into Table C-l, since use of the existing default values for "other solid
biomass-derived fuels" would result in significant overestimation of GHG emissions per ton of
sugarcane bagasse combusted.
Response: EPA is allowing reporters to use the Tier 1 method when calculating CO2 emissions
from the combustion of biomass fuels, and provides default heating values and emission factors.
Reporters may elect to use a higher tier method at their choice, such as Tier 3 which requires
carbon content testing or the Tier 4 method which requires continuous monitoring of CO2
emissions by a CEMS.
Commenter Name: See Table 6
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0679.1
Comment Excerpt Number: 119
Comment: §98.38, Table C-3. Certain factors do not match those presented in the 2006 IPCC
Guidelines for National Greenhouse Gas Inventories, when converted to a HHV basis. Factors
should be revised as follows: a. Coal CH4 factor of 1.0 x 10"2 should be 1.0 x 10"3; b. Landfill
Gas CH4 factor of 9.0 x 10"4 should be 9.5 x 10"4; c. Landfill Gas N2O factor of 1.0 x 10"4 should
340
-------
be 9.5 x 10"5; d. Natural Gas and Refinery Gas CH4 factor of 9.0 x 10"4 should be 9.5 x 10"4; and
e. Natural Gas and Refinery Gas N2O factor of 1.0 x 10"4 should be 9.5 x 10"5.
Response: EPA believes the fuel types and respective emission factors listed in Subpart C are
sufficient for reporting. EPA has reviewed the HHV values, and finds that they are consistent
with Climate Leaders. Any values brought in from IPCC were converted in the same manner as
the Climate Leaders factors. EPA is using mostly IPCC values in Table C-2 because we are
aware that the AP-42 non-CC>2 factors haven't been reviewed in-depth recently.
Commenter Name: Kyle Pitsor
Commenter Affiliation: National Electrical Manufacturers Association (NEMA)
Document Control Number: EPA-HQ-OAR-2008-0508-0621.1
Comment Excerpt Number: 18
Comment: The Tier 4 Calculation Method under §98.33(4) is highly burdensome and the
required continuous emissions monitoring system (CEMS) is both expensive to install and
maintain. Therefore, this method should only be required of reporting facilities that are already
required to operate such emissions monitoring equipment under existing rules promulgated under
the CAA. The primary purposes of the Mandatory Greenhouse Gas Reporting Rule are to
establish a reasonably accurate GHG emissions baseline for the U.S. for use in future
rulemaking, and to establish standard procedures to ensure consistent GHG emissions data from
year to year for tracking purposes. Given the significant recordkeeping and maintenance burdens
associated with operating and maintaining CEMS, the higher level of accuracy afforded by these
monitoring systems is neither necessary nor justified by the intended purposes of this rule. If a
facility is not required to have CEMS under a Title V Permit for listed priority and hazardous air
pollutants, or other CAA programs, because other emissions monitoring and/or estimation
methods were deemed adequate, it makes little sense for such a facility to now have to install
CEMS to report GHG emissions, when there are adequate methods available to reasonably and
consistently estimate these emissions without adding excessive costs and the need for additional
resources to install, operate and maintain these monitoring devices.
Response: EPA thanks you for your comment. See the Preamble and separate comment
response document volume for the response on the general monitoring approach.
EPA acknowledges the commenter's concerns regarding Tier 4 applicability. EPA has revised
the rule to clarify that all six criteria must be met before Tier 4 is required. The Tier 4 CEMS
requirement is limited to larger solid fossil fuel units with an existing pollutant CEMS or
volumetric flow rate monitor.
See the response to comment EPA-HQ-OAR-2008-0508-0455.1 excerpt 7 and the response to
comment EPA-HQ-OAR-2008-0508-0580 excerpt 10 for EPA's rationale and approach to the
use of CEMS.
Many of these fossil-fuel fired units with a pollutant CEMS have an existing diluent monitor (O2
or CO2) that can be used to determine CO2 emissions. EPA's estimates of monitoring costs are
averages for a representative facility and may not represent the actual cost in individual
circumstances.
341
-------
Commenter Name: See Table 10
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0635
Comment Excerpt Number: 17
Comment: The reporting rule should more clearly require new facilities built with CEMS, or
existing facilities which acquire CEMS, to use those CEMS (upgraded if necessary) to monitor
GHG emissions. EPA should take advantage of facilities with CEMS, whenever they are built,
rather than limiting the CEMS requirement just to facilities using that technology on the rule's
effective date. EPA states in the Preamble that it intends to "require direct measurement of
emissions from units at facilities that already are required to collect and report data using CEMS
under other Federally enforceable programs."112 A few paragraphs later, it again writes that
"facilities that already use CEMS would still be required to use them."113 These sentences are
somewhat unclear: Does EPA intend to require GHG CEMS only of facilities that 'already are'
using CEMS for some purpose when the rule first goes into effect, or does it intend that new
facilities - either those whose emissions are below the reporting threshold in 2010, or which
simply have not been built - be required to use GHG CEMS if they have a CEMS at all? The
temporal baseline for the CEMS rule is not plainly specified. Unfortunately, this ambiguity is
not limited to the Preamble. The rule's text also does not state a clear baseline, although it favors
using CEMS whenever they are installed. The rule is clearly intended to apply to new sources -
it includes provisions specifying reporting dates "for new facilities that commence operation on
or after January 1, 2010" and for facilities which "become subject to this rule because of a
physical or operational change" after that datel 14 — but it does not include a clear directive to
these sources explaining whether and how they could trigger CEMS requirements. The core
CEMS provision, proposed 40 C.F.R. §98.33(b)(5)(ii), which is located within subpart C,
covering general stationary fuel combustion sources provides that CEMS "[sjhall be used for a
unit" if: A) The unit has a maximum rated heat input capacity greater than 250 mmBtu/hr, or if
the unit combusts municipal solid waste and has a maximum rated input capacity greater than
250 tons per day of MSW. (B) The unit combusts solid fossil fuel or MSW, either as a primary
or secondary fuel. (C) The unit has operated for more than 1,000 hours in any calendar year
since 2005. (D) The unit has installed CEMS that are required either by an applicable Federal or
State regulation or the unit's operating permit. (E) The installed CEMS include a gas monitor of
any kind, a stack gas volumetric flow rate monitor, or both and the monitors have been certified
in accordance with the requirements of part 75 of this chapter, part 60 of this chapter, or an
applicable State continuous monitoring program. (F) The installed gas and/or stack gas
volumetric flow rate monitors are required, by an applicable Federal or State regulation or the
unit's operating permit, to undergo periodic quality assurance testing in accordance with
appendix B to part 75 of this chapter, appendix F to part 60 of this chapter, or an applicable State
continuous monitoring program. Subparagraph (b)(5)(ii)(D) is the sticking point. Using a
CEMS is required if "[t]he unit has installed CEMS" but the paragraph does not say when the
installation must have occurred, or even if there is such a baseline. Although the provision
should be read to apply whenever a CEMS is installed, it is susceptible to a more limited
misreading. Encouragingly, some provisions that reference this basic requirement suggest that it
is intended to require GHG CEMS whenever a CEMS is required to be installed, as they tend to
refer to the requirement in the present tense. Ethanol plants operators, for instance, are required
to use CEMS for reporting "[i]f [they] operate and maintain a CEMS that measures total CO2
342
-------
consistent with the requirements in subpart C of this part." Ammonia facilities are likewise
required to use CEMS if they "meet the conditions" set out in proposed 40 C.F.R.
§98.33(b)(5)(ii). Such a requirement would make little sense if, without explicitly saying so, it
excluded CEMS installed after 2010. EPA should take steps to clarify that it does not intend this
odd result. Otherwise, it risks a situation where sources which are required to install some form
of CEMS after 2010 insist that they need not report GHG emissions using the CEMS, solely
because they have installed the equipment after the effective date. The best way to avoid this
outcome, and the only way consistent with the rule's emphasis on using direct measurement
whenever it is available, is to state firmly that the GHG CEMS requirement applies whenever a
covered facility is required to install a CEMS to monitor any pollutant, and not only if a CEMS
was in use prior to the effective date of the rule. EPA can best make this clarification by taking
two steps: (1) Revise the Preamble to clarify references to CEMS which are "already" in use to
state that GHG CEMS will be required whenever a covered source either is required to install a
CEMS of any kind, or does so on its own volition and (2) Revise the rule's text to insert the
words "at any time" in between "has" and "installed" in proposed 40 C.F.R. §98.33(b)(5)(ii)(D),
and make any other necessary conforming changes.
Response: EPA has revised the rule to clarify that all six requirements must be met in order for
Tier 4 to apply, but does not believe that any further language is necessary to clarify that Tier 4
will be required of any sources that meet all of the criteria in the future.
Commenter Name: Marc J. Meteyer
Commenter Affiliation: Compressed Gas Association (CGA)
Document Control Number: EPA-HQ-OAR-2008-0508-0981.1
Comment Excerpt Number: 17
Comment: The proposed rule refers to a section §98.33(a)(l)(iv)(D) while describing the data
needs for employing CO2 CEMS. There is no such §98.33(a)(l)(iv)(D). Perhaps the agency
meant to reference §98.33(e)(3)(ii)(D)?
Response: EPA has corrected this error. The paragraph referenced in the comment
(§98.33(a)(4)(i) in the final rule) now refers to §98.33(a)(4)(iv).
Commenter Name: Craig S. Campbell
Commenter Affiliation: Lafarge North America
Document Control Number: EPA-HQ-OAR-2008-0508-0674.1
Comment Excerpt Number: 13
Comment: If CO2 CEMs are used, proposed 40 CFR §98.33(e)(2) requires calculation of %
biogenic CO2 emissions using equations C-12, C-13, C-14. The annual biogenic CO2 mass
emissions are then to be determined by multiplying the % biogenic by the total annual CO2 mass
emissions as measured by the CEMs. This calculation of annual biogenic CO2 mass emissions
does not take into account that a portion of the total annual CO2 emissions measured by the CO2
CEMs will be calcination emissions. Therefore the resultant calculation of annual biogenic CO2
343
-------
emissions will be incorrect. Lafarge recommends that EPA review and revise the calculation
method provided in proposed 40 CFR §98.33(e)(2) to account for calcination emissions.
Response: EPA acknowledges the concerns, and its method now requires the subtraction of
both fossil fuel combustion C02 emissions and process C02 emissions to calculate biogenic
C02.
Commenter Name: Rhea Hale
Commenter Affiliation: American Forest & Paper Association (AF&PA)
Document Control Number: EPA-HQ-OAR-2008-0508-0909.1
Comment Excerpt Number: 12
Comment: Based on the following discussion, AF&PA requests that facilities be able to use the
WRI/WBCSD GHG Calculation Tool, and default parameters recommended therein, for
estimating methane emissions from industry landfills, rather than using the formulas and
parameters in the EPA rule. NCASI has assembled data and completed several studies that
improve estimates of methane emissions from pulp and paper mill landfills. These data and
studies are summarized in the attached NCASI Special Report No. 08-05. Pages 13 and 14 of
that report present descriptions of the methods used by NCASI (which are analogous to the IPCC
methods used by EPA in the national inventory) to estimate methane emissions from pulp and
paper mill landfills. [SeeDCN: EPA-HQ-OAR-2008-0508-0909.2 for attachment] The report
indicates that, in 2005, the methane emissions from all forest products facility landfills in the
U.S. were estimated to be 2.2 Tg C02 eq. per year. (See Table 2.10 in NCASI Special Report
No. 08-05.) Although the report does not show the emissions for pulp and paper mills separate
from wood products facilities, the pulp and paper mill portion of the 2.2 Tg C02 eq. per year was
1.2 Tg C02 eq. per year. NCASI Special Report No. 08-05 also estimated that total direct
emissions due to fuel combustion at U.S. pulp and paper mills was 57.7 Tg C02 eq. in 2004.
Accordingly, 1.2 Tg C02 eq from landfills comprise less than two percent of the industry's fuel
combustion-related emissions. NCASI compared CH4 emission estimates using methods in the
WRI/WBCSD GHG Protocol GHG Calculation Tool, the "bulk waste" method recommended by
the IPCC, and the method proposed by EPA in this rule for a hypothetical industry landfill
receiving 20,000 dry tonnes of wastewater treatment plant residuals (30% solids) annually from
1950 through 1999. EPA's proposed default values for k and Lo were used in the calculations
for illustrative purposes. The results were almost identical - all ranging within 15 tonnes of CH4
(215 tonnes C02 eq.) in 1999 - with the WRI/WBCSD GHG Protocol GHG Calculation Tool
methods yielding estimates approximately 0.33% higher than the other two methods. For
consistency purposes, we recommend that the industry be allowed to continue to calculate these
emissions using the WRI/WBCSD GHG Protocol GHG Calculation Tool. Two important
differences do exist however between the WRI/WBCSD GHG Protocol GHG Calculation Tool
and the method proposed by EPA. First, we believe that the default DOC weight fraction for
pulp and paper (0.2, "wet basis") listed in proposed Table HH-1 is too high. WWTP residuals
are the main organic-carbon containing material landfilled at pulp and paper industry landfills
(NCASI 1999). NCASI has developed limited total organic carbon data for a number of industry
WWTP residuals, and obtained values for WWTP residuals landfilled by different pulp and
paper mills. These data are summarized below. [See DCN: EPA-HQ-OAR-2008-0508-0909.1
for table showing each "residual", its "solids fraction", "TOC fraction dry basis", and "TOC
fraction wet basis"] The data presented in the table are distinct from but in close agreement with
344
-------
data published by Mabee and Roy (2003) indicating an average TOC fraction of 0.310 (dry
basis) for six WWTP residuals. Considering that TOC may overstate DOC, and that WWTP
residuals are commonly co-disposed with other materials containing little or no organic carbon
(e.g., ash), it is clear that a DOC of 0.2 on a wet basis is too high. The default value for Lo in the
WRI/WBCSD GHG Protocol GHG Calculation Tool is 100 m3 CH4/dry tonne. This is
equivalent to a default DOC of about 0.2 tonnes CH4/dry tonne of residuals or 0.06 tonnes
CH4/wet tonne assuming the residuals have 30% solids content. The proposed default value of
0.06/year for the methane generation rate constant, k, for pulp and paper mill landfills is also
probably too high. To our knowledge no scientific investigation of k for pulp and paper mill
landfills has ever been completed. However, anecdotal information suggests that the rate of gas
generation at such landfills is usually lower than at municipal solid waste (MSW) landfills.
EPA's default k for MSW landfills in AP-42 is 0.04/year. The default value in the WRI/WBCSD
GHG Protocol GHG Calculation Tool is 0.03/year. As noted earlier, AF&PA suggests that the
WRI/WBCSD GHG Protocol GHG Calculation Tool be allowed for use in calculating landfill
methane emissions. This tool, including the default values for Lo and k, has been peer reviewed
and its use is widespread within the industry. [Footnote: WRI and WBCSD organized the peer
review process which included evaluation by experts from the pulp and paper industry, the
American Petroleum Institute (API), and the Center for Energy Efficiency (CENEf) in Russia, in
addition to detailed review by WRI and WBCSD staff] The foregoing discussion supports use
of the default values for Lo and k in the tool, but site-specific values should be allowed if they
are known.
Response: In regard to industry landfills, Subpart HH, EPA is not going final with that source
category at this time. Please see Section III. II. of the Preamble and the separate comment
response document.
Commenter Name: Sarah B. King
Commenter Affiliation: DuPont Company
Document Control Number: EPA-HQ-OAR-2008-0508-0604.1
Comment Excerpt Number: 25
Comment: §98.33 - EPA has not provided a de minimis threshold below which the greenhouse
gas emissions from a stationary combustion source do not need to be calculated by a facility and
otherwise included in the greenhouse gas reporting program. EPA should add a de minimis
threshold to avoid the necessity of reporting on dozens or even hundreds of minor units, such as
comfort hot water heaters, gas furnaces for buildings, etc. It would be unnecessarily costly to
add flow measurement devices to these units to facilitate calculation. DuPont recommends that
EPA add a de minimis threshold in §98.31 or §98.32 to eliminate reporting of emissions from
equipment whose emissions fall under the threshold. To emphasize our concern with this
provision, we refer to our comments in Section II.G, above, recommending de minimis
exclusions. We also note that a site-wide fuel accounting provision would be sufficient to assure
that there is full GHG emissions accounting from stationary combustion units without reporting
on all the individual minor sources.
Response: See the Preamble, Section II. K., and the response to comment EPA-HQ-OAR-2008-
0508-0423.2 excerpt 40 for the response on de minimis reporting for small emission points.
345
-------
While EPA does not agree that there should be a de minimis emissions exclusion, EPA has
expanded the list of exempted source categories to include portable equipment, emergency
generators, and flares (though flares may be covered in other subparts). EPA has also removed
the cumulative 250 mmBtu/hr restriction on unit aggregation, and believes that the expanded
availability of this option will reduce the reporting burden on facilities. Please also refer to
§98.2(a)(1) - (3) for facility requirements.
Commenter Name: Renae Schmidt
Commenter Affiliation: CITGO Petroleum Corporation
Document Control Number: EPA-HQ-OAR-2008-0508-0726.1
Comment Excerpt Number: 10
Comment: The Tier 4 applicability triggers are confusing in the rule - see page 16634 of FR
(but is clearly stated in the Preamble - see page 16483 of FR). EPA should make sure that the
Tier 4 Calculation Methodology is properly applied per rule intent. CITGO recommends that
EPA insert Table C-l from the Preamble into the body of the rule. This table is clear and
unambiguous in determining when to apply the various combustion calculation tiers. Of
particular note is section 40 CFR 98.33(b)(5)ii (A) and (C) Paragraph 40 CFR 98.33(b)(5)ii (A)
reads: "The unit has a maximum rated heat input capacity greater than 250 mmBTUIhr, or if the
unit combusts municipal solid waste and has a maximum rated input capacity greater than 250
tons per day of MSW." This paragraph should read: "The unit has a maximum rated heat input
capacity greater than 250 mmBTUIhr of solid fuel, or if the unit combusts municipal solid waste
and has a maximum rated input capacity greater than 250 tons per day of MSW." Similarly,
paragraph 40 CFR 98.33(b)(5)ii (C) reads: "The unit has operated for more than 1,000 hours in
any calendar year since 2005." This paragraph should read: "And the unit has operated for more
than 1,000 hours in any calendar year since 2005."
Response: EPA acknowledges the commenter's concerns regarding Tier 4 applicability. EPA
has revised the rule to clarify that all six criteria must be met before Tier 4 is required.
Commenter Name: Ron Downey
Commenter Affiliation: LWB Refractories
Document Control Number: EPA-HQ-OAR-2008-0508-0719.1
Comment Excerpt Number: 26
Comment: 40 C.F.R. 98.33 does not specify whether solid fuel calculations for coal should use
throughputs for "dry" or "as received" fuel. 40 C.F.R. 98.33(a) should be revised to specify that
all fuel calculations should use dry solid fuel throughputs for consistency and more accurate
results.
Response: EPA believes that fuel high heating value calculations should be done on an as-
received basis, and that no additional language is necessary in the rule to clarify this.
346
-------
Commenter Name: Michael Garvin
Commenter Affiliation: Pharmaceutical Research and Manufacturers of America (PhRMA)
Document Control Number: EPA-HQ-OAR-2008-0508-0959.1
Comment Excerpt Number: 9
Comment: There will be significant difficulties in calculating and reporting GHG emissions
from thermal oxidizer units (TOUs), liquid waste incinerators (LWIs), and other incinerators
(e.g., pathological waste incinerators, medical/infectious waste incinerators and solid waste
incinerators). Calculating emissions from supplemental fuel combustion is a very
straightforward calculation; however, accounting for the carbon dioxide formation associated
with the combustion of organic solid, liquid, and/or vapor effluents will be very difficult. We
believe that every TOU/LWI/incinerator installation would be required to install a carbon
dioxide CEM system, with the corresponding operational, maintenance, recordkeeping, and
reporting requirements. This approach significantly increases the costs and resources required to
comply with the proposed rule, which is intended to collect GHG emissions data that will be
used to develop a future GHG regulatory scheme. In light of the costs and associated burdens
associated with quantifying the GHG emissions associated with the combustion of organic solid,
liquid, and/or vapor effluents, PhRMA respectfully requests that EPA not require GHG reporting
for combustion sources which are in place for environmental protection (i.e., TOUs and LWIs)
and smaller-scale solid waste incinerators (i.e., pathological, medical/infectious, and solid waste
incinerators). To accomplish this, PhRMA proposes the following language for Section
98.33(a)(1): "For thermal oxidation units, liquid waste incinerators and smaller-scale solid
incinerators (e.g., pathological, medical/infectious, and solid waste incinerators located at
industrial facilities), GHG emissions are to be calculated based solely on supplemental fuel
combustion." If this change is not made, emissions factors for the range of wastes that could be
incinerated at industrial facilities must be provided.
Response: See the Preamble and source category Preamble section(s), as well as the separate
comment response document(s), for the response on the definition of the source category, and the
selection of the level of reporting.
EPA acknowledges the concerns of the commenter. A number of exemptions to GHG emissions
reporting have been added for certain unconventional combustion processes and types of fuel.
§98.30 of the final rule clarifies the definition of the general stationary fuel combustion source
category and provides an expanded list of exemptions from GHG emissions reporting under
Subpart C. Flares are excluded from Subpart C, but are addressed by means of special protocols
in other subparts of the rule. Also hazardous waste incinerators only report the GHG emissions
from combustion of supplementary fossil fuels listed in Table C-l. Other combustion units with
heat input less than 250 mmBtu/hr are only required to report emissions from fuels in Table C-l.
EPA believes that these provisions account for all appropriate allowances and require all
appropriate calculations necessary to satisfy the intent of Part 98, to collect accurate and
consistent GHG emissions data that can be used to inform future decisions.
347
-------
Commenter Name: Gregory M. Adams
Commenter Affiliation: Sanitation Districts of Los Angeles County
Document Control Number: EPA-HQ-OAR-2008-0508-0710.1
Comment Excerpt Number: 8
Comment: Under §98.6, p. 16626: Standard conditions are defined in the proposed rule as 14.7
pounds per square inch and 60 degrees Fahrenheit. However, in Subpart C, §98.33 - General
Stationary Fuel Combustion Sources, the Molar Volume (p. 16633) is listed as 849.5 scf per kg-
mole at standard conditions. Our calculations suggest this value should be 836.5 scf per kg-
mole. Please confirm that the molar volume listed is referenced to the standard temperature
stated in 98.6, p. 16626.
Response: EPA has revised the definition of "Standard conditions or standard temperature and
pressure (STP)" in §98.6 to mean "68 degrees Fahrenheit and 14.7 pounds per square inch
absolute." Given this revised definition, EPA believes that the value for MVC provided in
Equation C-5 is correct.
Commenter Name: H. Allen Faulkner
Commenter Affiliation: Ascend Performance Materials, LLC, Decatur Plant
Document Control Number: EPA-HQ-OAR-2008-0508-1578
Comment Excerpt Number: 3
Comment: Ascend operates two unique devices for the production of coke from coal at its
Decatur Alabama Plant. To our knowledge these are the only two units like this in the United
States. Our coking units burn the volatiles out of the coal and produce a high grade "buckwheat"
coke used primarily in the steel industry. Generally, half the coal input to Image is discharged as
coke and the other half is the volatiles combusted. Ascend is requesting allowances in the Tier 3
methodology to subtract the carbon remaining in the coke product from the carbon in the coal
input. The coking units partially combust coal to make a product (i.e. coke). These coking units
are designed for incomplete combustion. Much of the carbon will remain in the coke product
and not be converted to CO2 in the off-gas. Therefore, we suggest provisions in the Tier 3
methodology for product sampling for carbon and subtract the carbon remaining in the coke from
the carbon in the coal prior to calculating the CO2 emissions.
Response: EPA refers the commenter to §98.2(a)(1) of Subpart A that requires the annual GHG
report must cover all source categories and GHGs for which Calculation Methodologies are
provided in Subparts C through JJ of this part. See also the response to comment EPA-HQ-
OAR-2008-0508-1578 excerpt 2 for additional rationale relating to coverage of coke under the
rule.
EPA has revised the use of Tier 3 in §98.33(b)(3) of Subpart C to be required only when a unit
with a maximum rated heat input capacity greater than 250 mmBtu/hr that combusts any type of
fuel listed in Table C-l of this subpart (except MSW), unless the use of Tier 1 or 2 is permitted
or Tier 4 is required. Tier 3 is also required for a unit with a maximum rated heat input capacity
greater than 250 mmBtu/hr that combusts a fuel that is not listed in Table C-l of this subpart,
provided that the use of Tier 4 is not required, and the fuels provide ten percent or more of the
348
-------
annual heat input to the unit or to a group of units served by common supply pipe, as described
in §98.36(c)(3).
Commenter Name: Melvin E. Keener
Commenter Affiliation: Coalition for Responsible Waste Incineration (CRWI)
Document Control Number: EPA-HQ-OAR-2008-0508-0446.1
Comment Excerpt Number: 3
Comment: Subpart sources are also required to report methane, and nitrous oxide emissions.
Emission factors for these two gases are shown in Table C-3 for common fuels and certain
wastes. If the materials burned in a facility are not included in this Table, it is not clear how to
report these emissions. EPA stated in the Technical Support Document for this proposed rule
that methane and nitrous oxide accounts for less than one percent of the carbon dioxide
equivalents. Since greater than 99% of the greenhouse gas emissions for this sector are covered
by reporting carbon dioxide, little additional accuracy would be gained by reporting methane and
nitrous oxide emissions. CRWI suggests that only facilities that have default emissions factors
in Table C-3 be required to report methane and nitrous oxide emissions. All incinerators, boilers,
and process heater that burn hazardous waste are required to destroy 99.99% of the organic
material fed. Some of these materials are very difficult to destroy. Since methane is very easy to
destroy, it is highly unlikely that any methane will be emitted from these facilities. This is not a
compound 'that many hazardous waste combustors routinely measure. The One CRWI member
that measured methane emissions found that the concentration was less than 1 ppmv in the stack.
Given this information, CRWI sees no reason why these facilities should be required to report
methane emissions. Most, if not all will simply report zero emissions of methane. There is very
little, if any, information on nitrous oxide emissions for hazardous waste combustors. As far as
we know, this has never been measured during testing. However, there is information in the
literature that indicates the nitrous oxide emissions from high temperature combustion are very
small. The Department of Energy stated on their web site that "Until a few years ago, fuel
combustion was thought to be a major source of nitrous oxide emissions. However, the
discovery of a sampling error, which resulted in erroneously high emissions factors, revealed that
combustion is actually a minor anthropogenic source."
http://www.eia.doe.gov/oiaf/1605/archive/87-92rpt/chap4.htnil — accessed 4/20/09 This is
echoed in the technical support document3 for this proposed rule where EPA states In addition,-
the 2009 inventory of greenhouse gas-emissions in the United States, EPA estimated that the
2007 nitrous oxide emissions from waste combustion were 0.4 Tg CO2 equivalents. The total
U.S. greenhouse gas emissions for 2007 were 7,150.1 Tg CO2 equivalents. Nitrous oxide
emissions from this source category represent less than 0.006 percent of the total greenhouse gas
emissions. Research on nitrous, oxide formation or destruction during the combustion processes
gives the same picture. In a 1989 paper, Miller and Bowman stated that "N2O is a very short-
lived species in hot combustion gases..." (page 324). Miller, J.A., and C.T. Bowman. 1989.
Mechanism and Modeling of Nitrogen. Chemistry in Combustion. Prog. Energy Combust. Sci.,
Vol. 15: 287 - 338. In a subsequent article, Miller and Bowman state that "At low temperatures,
the N2O is relatively stable and appears as a major product in the gas stream; however, at
temperatures above 1150 k, the calculations show that N2O decays rapidly in the gas stream and
is still decomposing at the exit of the reactor..." [Footnote: Miller, J. A., and C.T. Bowman.
1991. Kinetic Modeling of the Reduction of Nitric Oxide in Combustion Products by Isocyanic
Acid. International Journal of Chemical Kinetics, Vol. 23: 289.] The temperature mentioned in
349
-------
the quote corresponds to approximately 1600° F, lower than the temperatures in hazardous waste
combustors. In addition, the authors state that nitrous oxide decays rapidly in gas-phase
temperatures above 1150 K (page 310). Finally, in his book, Kuo' states that N20 formed during
combustion reacts rapidly with hydrogen ions to form [Footnote: Kuo, K.K. 2005. Principles of
Combustion, John Wiley & Sons, Inc.] (p. 268). Given this, it seems logical to require only the
hazardous waste combustors that; have emission factors in Table C-3 to report their emissions
for methane and nitrous oxide. This would not create a large error in reporting since all of the
sources in this category are less than one percent of the CC^e. Not reporting emissions for those
sources without emission factors would be much less than one percent. This is a similar
conclusion to what EPA came to in the Preamble (74 Fed. Reg. at 16485) when discussing,
whether to require the development of site-specific emission factors for methane and nitrous
oxide. Here, EPA decided that this would be "too costly for the small improvement in data
quality it might achieve." Based on the science of nitrous oxide formation and destruction,
CRWI suggests that EPA require reporting of nitrous oxide emissions only for those facilities
that can use the emission factors found in Table C-3. Since this is such a-small portion of the
CC^e, the gain in accuracy would not be worth the cost.
Response: EPA acknowledges the concerns of the commenter. Section 98.33(c) of the final
rule excludes from calculations any CH4 and N20 emissions from fuels that are only used for
unit startup or are not listed in Table C-2 (formerly C-3). Table C-2 has been revised to include
CH4 and N20 emission factors for more fuels, including blast furnace gas and coke oven gas, as
well as generic emission factors covering all fuel types listed in Tables C-l. EPA has also
dropped the option which allowed facilities burning other fuels to develop site-specific emission
factors based on the results of source testing. Finally, hazardous waste incinerators and all units
with a rated heat input capacity less than 250 mmBtu/hr are only required to report GHG
emissions from the combustion of any fuels listed in Table C-l.
Commenter Name: Melvin E. Keener
Commenter Affiliation: Coalition for Responsible Waste Incineration (CRWI)
Document Control Number: EPA-HQ-OAR-2008-0508-0446.1
Comment Excerpt Number: 2
Comment: CRWI suggests that EPA develop a mechanism by which additional emission
factors can be added to Tables C-l and C-2. As facilities get more experience in developing and
using site-specific emissions factors, there may be a need to expand these tables.
Response: Based on comments, additional factors have been added to Tables C-l and C-2
(formerly C-3), and other factors may be brought into future programs.
350
-------
Commenter Name: Melvin E. Keener
Commenter Affiliation: Coalition for Responsible Waste Incineration (CRWI)
Document Control Number: EPA-HQ-OAR-2008-0508-0446.1
Comment Excerpt Number: 1
Comment: Hazardous waste combustors will not be able to use either Tier 1 of Tier 2 because
there are no default values for their "fuel" in Tables C-l and C-2. Thus, it appears that these
units will, be forced to use either Tier 3 or 4 to calculate their carbon dioxide emissions. Very
few of these units have carbon dioxide continuous emission monitors so most will be forced to
use Tier 3. If every-facility that does not have a carbon dioxide monitor tried to purchase and
install one in the fourth quarter of 2009, it is highly unlikely there would be enough monitors
available to fill the need. While this may be appropriate for certain conditions, it will not be
appropriate in others. Some hazardous waste combustion facilities will burn thousands of
different waste streams in a year. Some are burned daily; others are burned once or twice a year
Trying to put a system in place to use Tier 3 would quickly become an unmanageable problem.
Thus, certain hazardous waste combustors have no good choices on how to estimate, their carbon
dioxide emissions. To address this problem, CRWI has three suggestions. The first one is to
require reporting only from those facilities that have a default emissions factor in either Tables
C-l or C-2. This would cover the major combustion sources while not subjecting the minor
sources to extensive testing requirements. The/rest of the sources contribute relatively small
amounts to the total inventory. EPA has already recognized the relatively small contribution by
exempting hazardous waste from the calculations and reporting in the landfill subpart of this
proposed rule. The second suggestion is to add a Tier 5 to Subpart C so those facilities, if they
choose to do so, can develop site-specific emissions factors. This is already allowed (or
required) on some level for the cement kiln (98.83) and nitric acid production (98.223)
categories. Hazardous waste combustors conduct, performance tests every 5 years as required
under Part 63,'Subpart EEE. During these periodic tests, the facility could measure and analyze
for the parameters necessary to develop a site-specific emissions factor. Other sources may be
able to, use historical data to develop a relationship between carbon dioxide emitted and mass of
waste burned. Adding the ability to develop a site-specific emission factor, gives these facilities
another tool to accurately estimate carbon dioxide emissions without the unnecessary burden of
frequent sampling or continuous monitoring. The third suggestion is to allow facilities to use
Dulong's approximation to estimate the carbon content, of the materials combusted. C. R.
Brunner, 1993. Hazardous Waste Incineration, Second Edition, McGraw-Hill, Inc., p. 326.
Normally, this approximation is used to estimate the Btu's per pound of a material based on
carbon, hydrogen, oxygen, and sulfur content of the material to be burned. Some hazardous
waste combustors will have a good estimate of the sulfur content and the Btu/lb but will not have
a good estimate of the carbon content. By rearranging this equation, assuming the oxygen
content of the waste is small, and that there are two hydrogens for every carbon, the equation can
be used to estimate the carbon content for materials burned.
Response: In the revised §98.30(c), unless CEMS are used to quantify CO2 mass emissions,
hazardous waste incinerators are only required to report GHG emissions from the combustion of
any supplemental fuels listed in Table C-l.
351
-------
Commenter Name: Ron Downey
Commenter Affiliation: LWB Refractories
Document Control Number: EPA-HQ-OAR-2008-0508-0719.1
Comment Excerpt Number: 27
Comment: The formulae set forth in 40 CFR 98.33(a)(2)(iii) and 98.33(c) regarding the
methods for calculating emissions from the combustion of municipal solid waste ("MSW") does
not apply to lime plants. The formulae assume MSW is used to produce steam, but lime plants
do not produce steam from burning MSW. LWB proposes the following formulae to calculate
emissions from "non-steam" facilities: Eq. C-2b would be C02 = 1 x 10"3 * (EF) * (Fuel)p *
(HHV)p. Eq. C-lOb would be CH4 or N20 = 1 x 10"3 * (EF) * (Fuel)p * (HHV)P. (Fuel)p and
(HHV)p would use the same definition as Eq. C-2a and C-l 0a.
Response: EPA has added default C02 emission and heat content factors for municipal solid
waste that may be used in conjunction with the Tier 1 methodology if the unit does not produce
steam.
Commenter Name: See Table 10
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0635
Comment Excerpt Number: 18
Comment: It is not clear from the rule's text whether the reporting rule itself (as opposed to
some other federal requirement) may ever independently require sources to install a CEMS -
indeed, both the text and EPA's statements in the Preamble suggest the contrary. EPA should
instead make clear that such a requirement is present. The ambiguity lies primarily in proposed
40 C.F.R. §98.33(b)(5)(ii). Looking again at the list of factors in that provision, listed above,
note that it is not clear whether the list is conjunctive or disjunctive. In other words, must a
source directly monitor its emissions only if it satisfies every factor in the list, or is satisfying one
factor in the list sufficient to require GHG CEMS? The list itself provides little guidance. The
first four factors could easily be disjunctive: A) The unit has a maximum rated heat input
capacity greater than 250 mmBtu/hr, or if the unit combusts municipal solid waste and has a
maximum rated input capacity greater than 250 tons per day of MSW. (B) The unit combusts
solid fossil fuel or MSW, either as a primary or secondary fuel. (C) The unit has operated for
more than 1,000 hours in any calendar year since 2005. (D) The unit has installed CEMS that
are required either by an applicable Federal or State regulation or the unit's operating permit.
Indeed, it would be entirely appropriate if they were disjunctive, as burning municipal solid
waste, burning solid fossil fuel, operating for long periods, or having a CEMS of any kind would
all be sensible reasons to require direct monitoring of GHG emissions. As we have outlined
above, it is precisely these sort of factors - and, in particular, burning solid fuels - which EPA
itself has recommended should trigger a CEMS requirement. The last two factors, however, cut
a bit differently. Paragraphs (E) and (F) both refer to particular certification and quality control
requirements for a CEMS. They do not make sense independently of paragraph (D), as a CEMS
cannot be certified or assessed unless it exists in the first place. So those factors, at least, must
be conjunctive. The factor list, in short, is confusing. Portions of it could, and should,
independently trigger CEMS, while other sections presume CEMS has already been installed.
352
-------
EPA appears at present to be working under the latter presumption. The Preamble states that this
provision "would require the use of certified CEMS to quantify CO2 mass emissions where
existing CEMS equipment is installed." This line suggests that, whatever other factors on the
(b)(5)(ii) list are satisfied, subparagraph (b)(5)(ii)(D), which specifies that a CEMS has already
been installed, must be fulfilled. EPA complicates this impression, however, by writing, a few
lines later, that "the use of CEMS ... is required for solid fossil fuel-fired units with a maximum
heat capacity greater than 250 mmBtu/hr (and for units with a capacity to combust greater than
250 tons per day of [municipal solid waste]." These requirements, which are factors
(b)(5)(ii)(A)-(B), phrased slightly differently, appear to stand alone, suggesting that these fuels
trigger a CEMS requirement, even if a CEMS has not been installed. Nonetheless, in the next
paragraph, EPA writes "[i]n addition [to the above-listed factors], in order to be subject to the
[direct monitoring] requirements," the 1,000 hour operation factor, (b)(5)(ii)(C), must be
satisfied. This language, of course, suggests the factors must all be satisfied. On balance, and
after reviewing EPA's guidance documents for this rule, which so indicate, we take this
conjunctive reading to be the one EPA intends. If so, EPA should rethink this approach (and, if
not, EPA should make that clear). First, the conjunctive reading will cause some practical
difficulties because not all of the factors operate in the same way. Unlike factors (b)(5)(ii)(A) -
(D), each of which could stand alone, factors (b)(5)(ii)(E) - (F) are really just CEMS operations
requirements. Certainly, they should be met by plants using CEMS to measure GHGs, but it
makes little sense to recast them as requirements for employing CEMS at all. They specify how
well CEMS should perform, not the characteristics of a source that should use CEMS in the first
place. Leaving them as independent factors would mean that a source with a poorly-performing
CEMS would be excused from direct monitoring all together, because it would not satisfy
subparagraphs (b)(5)(ii)(E) - (F). That result gets the proper incentives backwards: Sources
should be encouraged to properly certify and maintain their CEMS, not be rewarded with less
rigorous monitoring if they let matters slide. Treating these 'maintenance-based' concerns as
requirements for sources using CEMS, rather than as factors triggering CEMS would avoid that
improper result. If a source has a CEMS device, it should upgrade and use it. Thus, each of
factors subparagraphs (b)(5)(ii)(A) - (D) should be disjunctive. That reading is consistent with
the course EPA takes in the Acid Rain Program and with good practice. Finally, whether or not
EPA makes these modifications, it should clarify the language other provisions of the rule use to
reference the CEMS factors, as it is presently inconsistent. Some of the references address each
factor: Ammonia manufacturers, for instance, are required to use a GHG CEMS if they "meet
the conditions specified in . . . §98.33(b)(5)(ii)(A) through (F),"120 and cement kiln operators
are similarly required to directly monitor their emissions if they "meet the conditions specified in
§98.33(b)(5)(ii)."121 Other provisions are less clear, seeming to overlook some, but not all, of the
requirements of proposed §98.33(b)(5)(ii): Ferroalloy, iron and steel, and lead producers, for
instance, are all required to "estimate emissions according to the requirements in §98.33" if they
"operate and maintain a CEMS that measures CO2 consistent with the requirements in subpart C
[which contains §98.33(b)(5)(ii)]."122 This language calls subparagraphs (b)(5)(ii)(D) - (F) to
mind, as they specify requirements for which a "CEMS that measures CO2," should be
'consistent with,' but leave readers guessing as to whether (if ever) subparagraphs (b)(5)(ii)(A) -
(C) might matter. EPA should clearly state which factors are meant to apply in each case and
should either use the same factor list in each circumstance or give clear reasons why it does not.
Response: EPA acknowledges the commenter's concerns regarding Tier 4 applicability. EPA
has revised the rule to clarify that all six criteria must be met before Tier 4 is required.
353
-------
Commenter Name: Lorraine Krupa Gershman
Commenter Affiliation: American Chemistry Council (ACC)
Document Control Number: EPA-HQ-OAR-2008-0508-0423.2
Comment Excerpt Number: 77
Comment: In Table C-l of Subpart C, under the heading of "Petroleum Products" there is a
listing for "Natural Gasoline" with a default HHV of 0.110. It would at first appear that "natural
gas" is intended, but that fuel appears elsewhere in Table C-l. "Motor gasoline" also appears
under this heading in Table C-l, but neither that term nor "natural gasoline" is defined in §98.6
and neither appears in Table C-3 of Subpart C, where the term "gasoline" does appear.
"Gasoline" is not defined in §98.6. ACC suggests that EPA add definitions of "gasoline,"
"natural gasoline" and "motor gasoline" to §98.6. The headings "Biomass-derived Fuels (solid)"
and "Biomass-derived Fuels (Gas) appear in Table C-l. Listed under the heading "Biomass-
derived Fuels (solid)" is the phrase "Wood and Wood waste (12% moisture content) or other
solid biomass-derived fuels." Table C-3 contains the terms "Other Biomass" and "Wood and
Wood Waste," without a moisture content qualifier, but that table does not include a gaseous
biomass-derived fuel entry. EPA should clarify its intent when using the "Biomass" terms.
Response: In response to the comments received, EPA has greatly expanded §98.6 to include
detailed explanations of the meanings of all terms used in 40 CFR Part 98 that required
clarification. The final rule includes all additional and revised language deemed necessary.
In response to the comment, EPA has significantly revised Tables C-l and C-3 (now C-2) to
clarify what emissions from biomass-derived fuels are reported. Any fuel types not listed with
default factors are exempted from reporting CH4 or N2O emissions.
Commenter Name: Lorraine Krupa Gershman
Commenter Affiliation: American Chemistry Council (ACC)
Document Control Number: EPA-HQ-OAR-2008-0508-0423.2
Comment Excerpt Number: 76
Comment: In Table C- 1 of Subpart C, under the heading of "Petroleum Products" there is a
listing for "LPG (energy use)". There is no definition of "LPG" in §98.6. However, there is a
definition of "liquefied natural gas (LNG)" in §98.6, but that fuel is not listed in any of the
Tables in Subpart C. In Table C- 1 of Subpart C, under the heading of "Petroleum Products"
there are listings for "Aviation gasoline" and "Jet fuel". These terms also appear in Table C-3.
Neither of these terms is defined in §98.6. However, "Kerosene-type jet fuel" is defined in
§98.6, but that term is not used in Subpart C. EPA should clarify its use of these three terms in
the proposed rules.
Response: In response to the comments received, EPA has greatly expanded §98.6 to include
detailed explanations of the meanings of all terms used in 40 CFR Part 98 that required
clarification. The final rule includes all additional and revised language deemed necessary.
354
-------
Commenter Name: Kim Dang
Commenter Affiliation: Kinder Morgan Energy Partners, L P.
Document Control Number: EPA-HQ-OAR-2008-0508-0370.1
Comment Excerpt Number: 38
Comment: Kinder Morgan recommends the addition of the following to §98.6: Natural
gasoline means a mixture consisting mostly of pentanes and heavier hydrocarbons, extracted
from natural gas, that meets vapor pressure, end-point, and other specifications for natural
gasoline set by the Gas Processors Association.
Response: EPA provides a definition of natural gasoline in §98.6 that is largely consistent with
the recommendation by the commenter.
Commenter Name: See Table 6
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0679.1
Comment Excerpt Number: 66
Comment: Continuous Emissions Monitoring System §98.6 (p. 16618): EPA's definition of
CEMS includes a requirement for "readings every 15 minutes" which is not appropriate for a
definition.
Response: See the Preamble and separate comment response document volumes for the
response on the general monitoring approach and general recordkeeping requirements.
The commenter does not claim that the frequency of readings by equipment qualifying as a
CEMS should be different than at least once every 15 minutes, but rather claims that a
requirement for readings every 15 minutes is "not appropriate" to include in a definition. EPA
does not agree with this comment because it is certainly reasonable to include, in the definition
of a term (CEMS) that, on its face, includes the concept of "continuous" monitoring, a
performance specification concerning frequency of monitored readings. Moreover, this
performance specification has been used in defining "CEMS" in the Acid Rain Program since the
program began in 1995 and, in conjunction with other elements of the monitoring requirements
in that program, has resulted in a high level of data quality and consistency.
Commenter Name: Steven J. Rowlan
Commenter Affiliation: Nucor Corporation (Nucor)
Document Control Number: EPA-HQ-OAR-2008-0508-0605.1
Comment Excerpt Number: 43
Comment: In 98.33(b)(6), a new (iii) is needed stating when a source that newly acquires a
CEMS after January 1, 2011 should begin reporting using Tier 4 calculation methodology.
Response: EPA disagrees with the commenter that a new section is required to deal with
changes that occur after the passage of the rule. EPA does not believe that any further language
355
-------
is necessary to clarify that Tier 4 will be required of any sources that meet all of the criteria in
§98.33(b)(4)(ii) or (iii) in the future.
Commenter Name: Steven J. Rowlan
Commenter Affiliation: Nucor Corporation (Nucor)
Document Control Number: EPA-HQ-OAR-2008-0508-0605.1
Comment Excerpt Number: 44
Comment: 98.33(c)(3) should include a cross-reference to the GWP Table A-l.
Response: EPA appreciates the comment but does not feel that a rule revision is necessary
because the GWP Table A-l applies to all Subparts.
Commenter Name: Jennifer McGraw
Commenter Affiliation: Center for Neighborhood Technology (CNT)
Document Control Number: EPA-HQ-OAR-2008-0508-0723.1
Comment Excerpt Number: 8
Comment: CNT encourages EPA to harmonize its default emissions factors, heating values,
and any other default values supplied for reporting with default factors it uses in other materials.
For example, the default high heat value for natural gas is 1,027 BTU/SCF in table C-l of
Subpart C of the Draft Reporting Rule; this value matches the default value in Table A-251 of
EPA's Inventory of U.S. Greenhouse Gas Emissions And Sinks: 1990 - 2007; but the default
value for anthracite is listed as 25.09 mmBTU/short ton in the first document and 22.573 million
BTU/short ton in the second document. There may be some very logical reason for such
variations, but if it just a matter of different source data we recommend choosing a standard
default so as to avoid confusion among those using these documents as the basis of greenhouse
gas estimates and analysis. We would further encourage EPA to work to harmonize and update
such default values with other agencies such as the Department of Energy's Energy Information
Agency.
Response: EPA has extensively reviewed the default emission factors and high heat values
provided in Subpart C of the final rule, and believes that they are appropriate and, to the extent
possible, consistent with those used in other programs.
356
-------
6. MONITORING AND QA/QC REQUIREMENTS
Commenter Name: Keith Adams
Commenter Affiliation: Air Products and Chemicals, Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-1142.1
Comment Excerpt Number: 25
Comment: The proposed rule requires periodic sampling and analysis of fuels for HHV or
carbon content under §98.34(c)(1) and (2) and §98.34(d)(3). The rule implies this sampling and
analysis is to be done by the consumer of the fuel, the reporting source. The proposed rule
further describes minimum sampling and analysis frequencies for each fuel type. The proposed
rule implies a need for characterization of standard commercial fuels to meet calculation method
Tier 2 and 3, when, in actuality, the HHV and carbon content of standard fuels are nearly
constant values and default values (e.g. Tier 1 calculation method) yield sufficiently accurate
emission estimates. Recognizing the objective of the reporting rule is to develop a reasonable
estimate of the annual emissions from a source: 1. Standard fuels of commerce (natural gas, LP
gas, fuel oils, etc.) that are supplied to multiple consumers are more efficiently characterized by
their suppliers than by their consumers. 2. Standard fuels of commerce (excepting coal) have
very consistent H HV and carbon contents, requiring much lower characterization frequency.
Monthly characterization, as required under §98.34(c)(1) and §98.34(d)(3), of such consistent
fuels is costly and does not materially improve the annual estimate of emissions. 3. Process-
specific fuel sources (e.g. refinery gas) vary over time, but requiring daily sampling and analysis
is very burdensome and costly for a degree of characterization that is intended to yield an annual
emission estimate. Air Products Comment: The characterization of standard fuels of commerce
should not be required since default values employed under the Tier 1 calculation method will
yield a sufficiently accurate emission estimate. If a fuel characterization is required, the
characterization sampling and analysis should be the responsibility of the fuel supplier. Such
suppliers should then be required to provide the characterizations to any fuel consumers, upon
request. The agency should then accept these characterizations for use under Tier 2 and 3
calculation methods. The characterization frequency of standard fuels of commerce should be
reduced to annually. The characterization of process-specific fuels should be reduced to
monthly. Alternately, a source should be able to demonstrate that, after a period of required
characterization, the variability of the average fuel characteristic (HHV or carbon content) is
sufficiently small to justify a reduction in the sampling and analysis burden.
Response: See the Preamble and separate comment response document volume for the response
on Method for Calculating GHG Emissions.
EPA appreciates the comment and has significantly revised the sampling requirements in the
final rule. Sections 98.34(c) and 98.34(d) have been revised as follows: mandatory monthly fuel
sampling and analysis requirements for traditional fossil fuels have been dropped from Tiers 2
and 3, and natural gas must be sampled only semiannually. For fuel oil and coal, a representative
sampling is required for each fuel lot, i.e., for each shipment or delivery. For other liquid fuels
and biogas, quarterly sampling is required. For other solid fuels, excluding municipal solid
waste, weekly composite sampling with monthly analysis is required. For other gaseous fuels,
the daily sampling requirement has been retained, but only for facilities with existing equipment
in place that is capable of providing the data. Otherwise, weekly sampling is required, which
may be postponed in favor of monthly sampling until 2011 if new equipment must be purchased
357
-------
or if existing equipment must be upgraded to meet the weekly sampling and analysis
requirements.
The final rule clarifies that fuel sampling and analysis data provided by the supplier may be used
in the emission calculations, and that fuel billing meters may be used to quantify fuel
consumption. To simplify the emission calculations in Tiers 2 and 3, averaging of HHV and
carbon content data is permitted if these data are obtained at least at the minimum frequency
specified in §98.34. If the results of fuel sampling are received monthly or more frequently, the
weighted annual average high heat value shall be calculated using Equation C-2b. If the results
of fuel sampling are received less frequently than monthly, then the annual average HHV shall
be calculated using the arithmetic average HHV for all valid samples for the year. However,
regardless of the sampling frequency, the owner or operator must use the results of all available
valid fuel analyses in the emissions calculations.
Under Subpart NN, EPA is providing the option for natural gas suppliers to report measured
HHV and carbon content but it is not required.
Commenter Name: Alexander D. Menotti
Commenter Affiliation: Kelley Drye & Warren et. al LLP on behalf of the Steel Manufacturers
Association (SMA) and Specialty Steel Industry of North America (SSINA)
Document Control Number: EPA-HQ-OAR-2008-0508-0656.1
Comment Excerpt Number: 8
Comment: Many steel facilities have natural gas burners above the 250 MMBTU threshold and
therefore would be subject to the proposed Tier III reporting thresholds, which would require
monthly sampling of the carbon content of natural gas. We do not believe that monthly sampling
of pipeline quality natural gas is warranted. Such a requirement is inconsistent with methods
EPA previously has found acceptable under Title IV. The Title IV requirements allow CO2
calculations based on fuel flow measurements and heat content values supplied by natural gas
utilities. If EPA believes that this is not sufficient to extrapolate a reasonable value for average
carbon content, they should require that natural gas suppliers sample their product and provide
the data to customers along with heating values. It is unreasonable to require each consumer to
sample the same fungible commodity material.
Response: See the Preamble and separate comment response document volume for the response
on methods for calculating GHG emissions.
EPA has revised §98.34 to require that natural gas be sampled semiannually. In addition, the
final rule clarifies that fuel sampling and analysis data provided by the supplier may be used in
the emission calculations, and that fuel billing meters may be used to quantify fuel consumption.
358
-------
Commenter Name: Paul L. Carpinone
Commenter Affiliation: Tampa Electric Company (TECO)
Document Control Number: EPA-HQ-OAR-2008-0508-0717.1
Comment Excerpt Number: 9
Comment: Due to the potential variability of sulfur in coal, the need for stringent monitoring
and emissions calculation is warranted, but variation in the carbon content of coal is much less.
Because of the homogenous carbon content of coal, Tampa Electric recommends allowing a
solid fuel-fired combustion source CO2 emissions based on carbon content measurements and
the amount of coal burned, so long as a facility can certify its coal quantity measurements.
Response: See the response to comment EPA-HQ-OAR-2008-0508-0455.1 excerpt 7 and the
response to comment EPA-HQ-OAR-2008-0508-0580 excerpt 10 for EPA's rationale and
approach to the use of CEMS.
The Tier 4 CEMS requirement is limited to larger solid fossil fuel units with an existing pollutant
CEMS or volumetric flow rate monitor. EPA is requiring the use of CEMS due to the
complexity of monitoring solid fuel consumption and the heterogeneous nature of the solid fuels.
Many of these fossil-fuel fired units with a pollutant CEMS have an existing diluent monitor (O2
or C02) that can be used to determine C02 emissions. EPA has permitted the use of carbon
content measurements under Tier 3 requirements for solid fuels, if the unit is not required to
meet Tier 4.
EPA is requiring the use of CEMS for solid fossil fuel-fired units due to the complexity of
monitoring solid fuel consumption and the heterogeneous nature of the solid fuels. EPA has
considered the commenter's analysis, but disagrees with the commenter's assessment of the
burden associated with installing and maintaining the concentration and volume monitors that the
rule requires be added to an existing CEMS. In the revised rule, EPA has clarified that if the unit
in question meets all six criteria for Tier 4 to apply. EPA's estimates of monitoring costs are
averages for a representative facility and may not represent the actual cost in individual
circumstances. Note that EPA's cost estimates are annualized and do not widely differ from the
capital cost cited in this comment. Further detail on the engineering cost analysis for Subpart C
can be found in RIA (EPA-HQ-OAR-2008-0318-002) Section 4.3.
Commenter Name: Paul L. Carpinone
Commenter Affiliation: Tampa Electric Company (TECO)
Document Control Number: EPA-HQ-OAR-2008-0508-0717.1
Comment Excerpt Number: 10
Comment: Under proposed §98.43, Electric Generating Units (EGUs) subject to the
requirements of the Acid Rain Program would continue to monitor and report CO2 mass
emissions in accordance with the monitoring requirements of 40 C.F.R. Part 75. As stated
earlier, Tampa Electric supports the monitoring and reporting of this proposed rule to build on
the already well establish ARP, but with some exceptions. There is a known upward bias in
current stack flow measurement regulations under 40 C.F.R. Part 75. Under these measurement
standards, a "reference monitor" is introduced each year and compared to an affected unit's stack
359
-------
flow monitor. A side-by-side comparison is performed, and for any resulting difference, a bias
adjustment factor must be applied. The current rules, however, prescribe that only a positive
adjustment factor can be applied. If the reference monitor demonstrates a higher level of flow
than the affected unit's monitor, then a bias adjustment factor is added into the stack flow
equation. If the reference monitor demonstrates a lower level of flow, no bias adjustment can be
made. As a result, this procedure commonly results in high biased stack flow measurements. In
the aggregate, Tampa Electric has noticed a bias adjustment for stack gas flow calculations (0 -
3% is typical with 3D probe technology) and the natural drift error associated with CEMS (±
3%), combining to establish an allowable upward error or uncertainty of up to 6%. This error
represents a very costly misrepresentation of Tampa Electric's true GHG emissions. For
example, at a carbon allowance value of just twelve dollars, Tampa Electric would end up paying
an additional $10,800,000.00 annually for emissions never emitted. As a regulated utility,
Tampa Electric expects that the costs to comply with new environmental regulations would be
eligible for retail rate cost recovery through the Environmental Cost Recovery Clause. If
approved as prudent by the Florida Public Service Commission, the costs required to comply
with CO2 emissions reductions would be reflected in retail customers' bills through this
mechanism. Therefore, Tampa Electric recommends EPA should amend the stack flow
measurement regulations under 40 CFR Part 75 to allow an adjustment to be made for a low or
high bias of the CEMS instrumentation monitoring and reporting.
Response: See the Preamble, Section III. C., the Subpart D comment response document
volume, and the response to comment EPA-HQ-OAR-2008-0508-0956.1 excerpt 20 for the
rationale for using substitute data reported under Part 75.
Under this rulemaking, EPA is not revising Part 75 reporting requirements. EPA is keeping
GHG monitoring requirements consistent with current monitoring because the Agency does not
want to require two sets of data, as that would add to the cost and complexity of this rule. EPA
has adopted changes to Part 75 over time to address these types of technical issues, including
adoption of alternative stack flow reference test methods to address concerns with high bias.
Commenter Name: Keith A. Nagel
Commenter Affiliation: ArcelorMittal USA and Severstal North America
Document Control Number: EPA-HQ-OAR-2008-0508-0496.1
Comment Excerpt Number: 11
Comment: Another significant challenge is how to measure the amount of coke oven gas and
blast furnace gas generated during steelmaking and thus ultimately combusted. Section
98.34(d)(1) proposes to require the tracking of gas combustion using flow meters. It would
require that those flow meters be calibrated "prior to the first year for which GHG emissions are
reported . . . using an applicable flow meter test method" and recalibrated annually or as
recommended by the manufacturer. While that may be appropriate for assessing natural gas
flow, there are significant practical problems with applying this approach where coke oven gas
and blast furnace gas are involved. For example, the potential requirement to examine and/or
calibrate orifice plates under the published standards is unworkable. The gas lines at issue do not
have engineering bypasses and serve continuous processes that cannot be shut down without
major operating implications for the entire facility (e.g., blast furnaces and coke ovens). We
expect additional difficulty calibrating flow meters for coke oven gas under ASME standards at
360
-------
several of our facilities due to precipitate in the gas and the need for significant process
interruptions. Finally, it would be exceptionally difficult to precisely measure the volume of
blast furnace gas because it is widely distributed, contains potentially significant amounts of
moisture and is conveyed in very large pipes. Those factors would make the use of ANSI
requirements problematic and significantly impair the accuracy of flow meters. The rule should
be amended to provide owners and operators the flexibility to quantify coke oven gas and blast
furnace gas generation at the source using industry benchmarks. Rather than attempting to
upgrade, calibrate and maintain countless meters plant-wide (with varying degrees of resulting
accuracy), sources should be allowed to calculate the quantity of blast furnace gas using process
information that will provide equal or greater precision. ArcelorMittal's Indiana Harbor facility
uses just such a system, which involves measuring: (1) the total amount of nitrogen entering its
blast furnaces (primarily in air) and (2) the total amount of nitrogen present in top gas coming
from its blast furnaces. These measurements are highly accurate (due to the use of a frequently
calibrated gas chromatograph). Since functionally all of the nitrogen introduced into the furnace
leaves in resulting blast furnace gas, measuring nitrogen concentrations as a "tracer element" in
top gas samples allows the plant to precisely determine the amount of blast furnace gas
generated. This alternate approach would yield results that are significantly more reliable than
the proposed metering - particularly given the expected calibration difficulties. Further, since
top gas analysis is a critical tool for ensuring proper blast furnace operation, sources already have
ample incentive to ensure accurate and consistent data. Thus, use of nitrogen tracing potentially
presents a less costly, more precise way to determine the amount of blast furnace gas produced.
That figure can then be used to precisely determine GHG emissions from combustion. To
authorize the development of such more accurate and less burdensome options, we request that
EPA amend the Proposed Rule to allow any alternate approach for determining the amount of
process gas generated (and combusted) that has equal or greater accuracy than the current
monitoring proposal.
Response: EPA refers the commenter to §98.3(i)(6) of Subpart A that allows the owner or
operator to postpone initial calibration until the next scheduled maintenance outage if there are
units and processes that operate continuously with infrequent outages. Such postponements shall
be documented in the monitoring plan that is required under §98.3(g)(5).
The commenter is also referred to Table C-l of Subpart C, which now includes a default high
heat value and CO2 emission factor for blast furnace gas. The Tier 1 methodology may be used
for any fuel listed in Table C-l that is combusted in a unity with a maximum rated heat input
capacity of 250 mmBtu/hr or less. If eligible to use the Tier 1 methodology, mass or volume of
fuel combusted can be taken from company records.
EPA has revised the use of Tier 3 in §98.33(b)(3) of Subpart C to be required only when a unit
with a maximum rated heat input capacity greater than 250 mmBtu/hr that combusts any type of
fuel listed in Table C-l of this subpart (except MSW), unless the use of Tier 1 or 2 is permitted
or Tier 4 is required. Tier 3 is also required for a unit with a maximum rated heat input capacity
greater than 250 mmBtu/hr that combusts a fuel that is not listed in Table C-l of this subpart
provided that the use of Tier 4 is not required and the fuels provide ten percent or more of the
annual heat input to the unit or to a group of units served by common supply pipe, as described
in §98.36(c)(3).
EPA's approach makes use of existing data and methodologies to the extent feasible, and is
consistent with the types of methods contained in other GHG reporting programs (e.g., the
361
-------
California mandatory reporting rule, WCI, RGGI, TCR, and Climate Leaders). Because this
approach specifies methods for each source category, it will result in data that are comparable
across facilities. For consistency, EPA did not provide for alternative approaches as described
by the commenter.
Commenter Name: Dan F. Hunter
Commenter Affiliation: ConocoPhillips Company
Document Control Number: EPA-HQ-OAR-2008-0508-0515.1
Comment Excerpt Number: 19
Comment: The calculation methodology (98.33) and Monitoring and QA/QC requirements
(98.34) require clarification. The proposed regulatory language does not reflect the intent and
understanding explained in the Preamble to the rule. The rule appears to clearly require fuel
flow measurements under Tier 3 and Tier 4 calculation methodologies while for Tier 1 and Tier
2 it requires company records to be utilized to determine quantity of fuel combusted. The rule is
unclear about how quantity of fuels combusted can be determined from company records.
ConocoPhillips seeks EPA's confirmation of our interpretation that under Tier 1 and 2
calculation methodologies, the affected facilities may use other methods to estimate fuel flow to
combustion devices such as rated capacities, load factors, hours of operation or conservative
estimates of hours of operation, etc.
Response: EPA acknowledges the commenter's concerns, and has defined the term "company
records" in §98.6 of the final rule. EPA believes that the revised definition provides appropriate
guidance as to what records a facility may use to determine fuel consumption.
Commenter Name: Jack Gehring et al.
Commenter Affiliation: Caterpillar Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-0499.1
Comment Excerpt Number: 23
Comment: EPA should clarify the following if it promulgates the Reporting Rule substantially
as it has proposed: 1. That the "company records" from which fuel usage is derived under the
Tier 1 and Tier 2 calculation methods may include, for example, natural gas billing records or
estimates derived from such records rather than direct measurement (via fuel flow meters); 2.
That data collection and calculations requirements applicable to individual stationary fuel
combustion units (in proposed 40 CFR 98.33, 98.34 and 98.36) may be aggregated at the
discretion of the facility, and fuel usage for Tier 1 and 2 calculation methods (for unlimited
groups of units with aggregate rated heat input capacity of less than 250 mmBTU) can be derived
from, for example, natural gas billing records rather than direct measurement (via fuel flow
meters); 3. That facilities which are required to, or choose to, use Tier 3 calculation methods may
utilize existing natural gas billing meters (including multiple meters at a single facility) to report
facility wide GHG emissions if the relevant data concerning fuel properties is provided by
natural gas suppliers; and 4. That facilities using the "common pipe configuration" option for
reporting (in proposed 40 CFR 98.36(c)(3)) may utilize existing gas billing meters to satisfy the
requirement to use a "calibrated fuel flow meter." Many of the clarifications requested are
362
-------
intended to ensure operational flexibility and make clear that, provided facilities have a reliable
source of fuel usage information, they generally will be able to estimate emissions from
individual units (or groups of units) and will not be required to install additional fuel meters to
measure usage at each individual unit. This is a critical consideration, since requiring installation
of fuel meters for each stationary fuel combustion unit will drive significant unnecessary expense
and hamper each facility's ability to modify its operations as needed.
Response: See the Preamble and separate comment response document volume for the response
on the method for calculating GHG emissions.
In preparation of the final rule, EPA believes it has clarified instructions regarding aggregation
and common pipe provisions. EPA has retained the provision requiring fuel use in a common
pipe configuration to be accurately measured by a calibrated fuel flow meter, noting that fuel
billing meters can be used for this purpose. In addition, EPA acknowledges the commenter's
concerns regarding the term "company records" in §98.6 of the final rule. EPA believes that the
revised definition provides appropriate guidance as to what records a facility may use to
determine fuel consumption.
Commenter Name: Leslie Bellas
Commenter Affiliation: National Lime Association (NLA)
Document Control Number: EPA-HQ-OAR-2008-0508-0520.1
Comment Excerpt Number: 24
Comment: 40 C.F.R. §98.34(e)(1) appears to require that all procedures identified must be
followed to initially certify a CEMS. Based on our May 14 conference call with EPA, only one
of the listed procedures must be followed to initially certify a CEMS. NLA proposes that 40
C.F.R. §98.34(e)(1) be revised to state that "For initial certification, use one of the following
procedures:"
Response: EPA agrees that the proposed language could be confusing, and has added language
to the final rule to clarify that any one of the alternate initial certification procedures for CO2
CEMS is acceptable.
Commenter Name: Jeffrey L. Clark
Commenter Affiliation: Environmental Coordinator, Teck Alaska Incorporated
Document Control Number: EPA-HQ-OAR-2008-0508-0142
Comment Excerpt Number: 7
Comment: I oppose the inclusion of the quantity of electricity purchased by the facility. This
again leads to double reporting. The same can be said about reporting indirect GHG emissions.
Response: This rule does not have a requirement for reporting electricity purchases or indirect
emissions. See the Preamble and separate comment response document volume for the response
on the general content of the annual emissions report.
363
-------
Commenter Name: Dan F. Hunter
Commenter Affiliation: ConocoPhillips Company
Document Control Number: EPA-HQ-OAR-2008-0508-0515.1
Comment Excerpt Number: 25
Comment: The statement "All oil and gas flow meters" should be revised to "All liquid and gas
flow meters." There currently are no QA/QC provisions for liquid flow meters used in support
of the Tier 3 combustion emission calculations.
Response: EPA agrees that the proposed language was ambiguous, and changed the final rule to
read as follows: "Each Fuel meter that provides fuel usage data for the GHG emissions reported
under this part..." This does not explicitly specify liquid flow meters, but the Agency believes
the provisions for liquid flow meters are implied.
Commenter Name: Michael DiMauro
Commenter Affiliation: Massachusetts Municipal Wholesale Electric Company (MMWEC)
Document Control Number: EPA-HQ-OAR-2008-0508-0580
Comment Excerpt Number: 7
Comment: The GHG Reporting Rule should allow all stationary combustion sources (not just
Acid Rain units) the option to conform with applicable Part 75 procedures. Such an approach
would be consistent with many NSPS rules (e.g. Subpart Da, Subpart Db, Subpart KKKK),
which have gradually been incorporating Part 75 procedures as an acceptable alternative to 40
CFR 60 Appendix B and F for CEMS monitoring, fuel metering and fuel sampling. In
particular, all stationary sources should be provided the option to: a) Conduct Fuel Meter
Quality Assurance in accordance with 40 CFR 75 Appendix D procedures, performance
specifications and testing timelines. Testing timelines should be based on QA operating
quarters, not calendar quarters, and if feasible the option to perform fuel flow/load analyses to
extend testing deadlines should also be adopted. Note that the Preamble (FR Page 16484,
Column 1) indicates that EPA "recommends the use of fuel flow calibration methods in 40 CFR
75", but this language is not explicitly reflected in 98.34(d). Moreover, not only the use of Part
75 Calibration Methods, but also the use of Part 75 Test Cycle Timelines should be allowed
under the GHG Reporting rule, b) Perform fuel sampling to determine high heat content in
accordance with 40 CFR 75 Appendix D procedures, and also report this fuel heat content data,
and use it in emission calculations, in accordance with 40 CFR 75 Appendix D procedures The
40 CFR 75 Appendix D procedures provide a well established and broadly accepted
methodology for compliance monitoring and regulatory emission reporting, and are therefore
well suited to support GHG Emission reporting.
Response: See the Preamble and separate comment response document volume for the response
on the method for calculating GHG emissions.
EPA believes that the structure of the final rule mirrors the commenter's suggestion to a large
extent. As stated in the Preamble, new methodologies in addition to the tiers have been added,
allowing non-Acid Rain sources that monitor and report heat input according to Part 75 to use
364
-------
established Part 75 C02 emission calculation methods to meet the Part 98 reporting
requirements.
Commenter Name: Keith Adams
Commenter Affiliation: Air Products and Chemicals, Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-1142.1
Comment Excerpt Number: 26
Comment: The proposed rule requires all liquid and gaseous fuel flow meters to be calibrated
initially and annually, or at the meter manufacturer's specified frequency, thereafter. This
requirement fails to recognize that some fuel measurement device installations do not allow
calibration without taking the fuel line out of service, thereby forcing a shutdown of the
combustion/manufacturing process. In many instances, scheduled maintenance shutdowns for
such equipment/processes will not occur on this prescribed frequency. Unless provisions are
added to the proposed rule which provide relief from this required calibration frequency,
manufacturing processes will be required to shutdown solely to complete the required
calibration, resulting in significant cost, business disruption and, in many cases, increase
environmental impacts from the inefficiencies of the start-up/shutdown activity. This need is
comparable to provisions under many EPA rules regarding the repair of leaking VOC fugitive
emissions components where repair would require a process shutdown, and instead the repair
deadline is extended to the next scheduled maintenance shutdown. In most instances, the delay
in calibration of a flow meter requiring a process shutdown would not materially compromise the
annual emission estimate. This is particularly true for those combustion units using the simplest,
cleanest fuels - there is typically less "drift" in the calibration of flow measurement devices for
such clean fuels and such combustion units/processes often require less frequent maintenance
turnarounds, exacerbating the need for extension of the calibration frequency. Air Products
Comment: The rule should include provisions for an extension of the required flow meter
calibration deadline (as well as the initial calibration, if appropriate) where the calibration would
require removing the fuel supply from service. The calibration requirement should then be
extended to the next scheduled maintenance shutdown for the impacted unit/process.
Response: See the Preamble, Section II. G., "Summary of Comments and Responses on Initial
Reporting Year and Best Available Monitoring Methods," for a description of additional
flexibility for monitoring methods in 2010.
EPA acknowledges the concerns of the commenters. The final rule clarifies that for units and
processes that operate continuously with infrequent outages and use orifice, nozzle or venturi
meters, the owner or operator may postpone the initial calibration or PEI (as applicable) until the
next scheduled maintenance outage, and may similarly postpone the subsequent recalibrations
and PEIs.
Regarding the ongoing QA requirements for fuel flow meters (except for orifice, nozzle, and
venturi meters), the final rule has kept the annual requirement for successive required
calibrations, but has also allowed calibration at the frequency as specified by the manufacturer or
accepted industry consensus. For orifice, nozzle, and venturi meters, recalibration of the
transmitters is required annually, supplemented by a primary element inspection (PEI) once
every three years. For continuous processes, if the PEI cannot be performed safely without
disrupting normal operation, it may be postponed until the next maintenance outage.
365
-------
Commenter Name: Keith Adams
Commenter Affiliation: Air Products and Chemicals, Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-1142.1
Comment Excerpt Number: 27
Comment: The proposed rule defines the alternate initial certifications for C02 CEMS systems
under §98.34(e)(l)(i), (ii), and (iii). The propose rule language is not clear that any one of the
certifications described in §98.34(e)(l)(i), (ii), and (iii) is acceptable. Clarify that any one of the
alternate initial certifications under §98.34(e)(l)(i), (ii), and (iii) is acceptable by separating the
(i), (ii), and (iii) options with "or".
Response: EPA agrees that the proposed language could be confusing, and has added language
to the final rule to clarify that any one of the alternate initial certification procedures for CO2
CEMS is acceptable.
Commenter Name: Linda Farrington
Commenter Affiliation: Eli Lilly and Company (Lilly)
Document Control Number: EPA-HQ-OAR-2008-0508-0680.1
Comment Excerpt Number: 28
Comment: The dates and results of the initial CEMS certification tests and major quality
assurance tests performed on the CEMS during the reporting year (i.e., linearity checks, cylinder
gas audits, and relative accuracy audit tests) are required to be submitted to the EPA as part of
the verification data for the GHG emission report. This requirement is duplicative and not
necessary because the results of CEMS QA/QC tests are already submitted to state or local
regulatory authorities. Therefore, there is no need for EPA to require redundant reporting of this
information. State and local regulatory authorities typically provide oversight for CEMS
required by other regulatory programs and we believe they should provide oversight for CO2
CEMS required by the proposed GHG reporting rule; thereby eliminating the need for EPA to
verify the validity of CEMS data on an on-going basis.
Response: EPA believes that it is appropriate for reporters using the Tier 4 methods of Subpart
C to submit the results of CEMS certification and QA tests directly to EPA. However, EPA has
added language to §98.36(e)(2)(iv)(E) and (F) clarifying that sources must only submit the
summarized results of these tests, rather than the complete results. EPA believes that this will
reduce the burden on reporters. EPA has also clarified that no additional verification data is
required to be reported for Acid Rain Program units or other units that report under Part 75 (see
§98.36(e)(1)).
366
-------
Commenter Name: Leslie Bellas
Commenter Affiliation: National Lime Association (NLA)
Document Control Number: EPA-HQ-OAR-2008-0508-0520.1
Comment Excerpt Number: 29
Comment: To determine the biogenic portion of C02 emissions from MSW combustion, 40
C.F.R. §98.34(f) requires sources to quarterly sample gases when the unit has been exclusively
burning MSW for twenty-four hours. In the case of a lime plant, this requirement would mean
that the kiln could not generate lime during sampling because burning only MSW would not
generate the heat necessary for lime production. In many cases it would be difficult to burn only
MSW as supplemental fuel such as coal might be required to keep the flame burning.
Consequently, this sampling methodology would discourage the use of alternative fuels, such as
MSW. Revise 40 C.F.R. §98.34(f) to also permit the use of fuel input data on a quarterly basis
so that stack testing is not required. Utilizing fuel input data on a quarterly basis would
adequately address EPA's concern about the variability of the fuel.
Response: EPA refers commenter to §98.33(e) and §98.34(d) of Subpart C for the final text on
determining the biogenic portion of C02 emissions from MSW combustion. However, the
requirement in §98.34(d) noted by the commenter has not changed given that an acceptable
alternative method was not identified by EPA.
EPA notes the provisions of §98.34(d) of the final rule which provide instructions for
determination of the biogenic portion of the CO2 emissions from MSW combustion as follows:
Perform the ASTM D7459-08 sampling and the ASTM D6866-08 analysis at least once in every
calendar quarter in which MSW is combusted in the unit. Collect each gas sample during normal
unit operating conditions while MSW is the only fuel being combusted for at least 24
consecutive hours or collect each gas sample for as long as is necessary to obtain a sample large
enough to meet the specifications of ASTM D6866-08. Use the results from ASTM D7459-08 to
separate CO2 emissions into the biogenic and non-biogenic fraction, using the average
proportion of biogenic emissions of all samples analyzed during the reporting year. EPA further
notes that the provisions provide a choice of collection options for the gas samples.
Commenter Name: Linda Farrington
Commenter Affiliation: Eli Lilly and Company (Lilly)
Document Control Number: EPA-HQ-OAR-2008-0508-0680.1
Comment Excerpt Number: 29
Comment: The EPA solicits comments on ways to ensure that the feed rate of solid fuel to a
combustion device is accurately measured. Lilly suggests the EPA allow the use of engineering
calculations and best available information to estimate solid fuel consumption. An example of a
reasonable engineering calculation would be to calculate the amount of solid fuel combusted
based upon the amount of steam generated and boiler efficiency. This could provide more
accurate data than fuel mass measurement, especially for units where retrofits may be required.
Lilly does not believe it is necessarily beneficial or cost effective to require the installation of
weighing devices for direct measurement of solid fuel usage.
367
-------
Response: EPA has extended the use of steam production and combustion unit efficiency to
calculate CO2 emissions to other solid fuels in addition to municipal solid waste. These
parameters may also be used to quantify the amount of biomass combusted in a unit.
Commenter Name: Jeff A. Myrom
Commenter Affiliation: MidAmerican Energy Holdings Company
Document Control Number: EPA-HQ-OAR-2008-0508-0581.1
Comment Excerpt Number: 31
Comment: EPA solicited comment on ways to ensure that the feed rate of solid fuel to a
combustion device is accurately measured (page 16485). Facilities already have sufficient
motivation to accurately report emissions from solid fuel combustion (and thus the quantification
of that fuel) due to potential Clean Air Act violation fines of up to $32,500 per day as well as
other administrative, civil, and criminal measures. Thus, EPA does not need additional measures
to ensure that total fuel use is measured correctly.
Response: EPA appreciates the commenter's concern, and has simplified the rule. The revised
rule states that fuel combustion may be determined from company records. Also, the use of
steam production and combustion unit efficiency to calculate C02 emissions is extended to other
solid fuels in addition to municipal solid waste. These parameters may also be used to quantify
the amount of biomass combusted in a unit.
Commenter Name: Leslie Bellas
Commenter Affiliation: National Lime Association (NLA)
Document Control Number: EPA-HQ-OAR-2008-0508-0520.1
Comment Excerpt Number: 34
Comment: The Preamble, 74 Fed. Reg. at 16,484, and Table 8 in the Technical Support
Documentation indicate that 40 C.F.R. §§98.34(c) and (d)(3) require Tier 2 and Tier 3 facilities
using solid fuel to sample weekly and composite weekly sample results into a monthly carbon
content value that is reported. However, 40 C.F.R. §§98.34(c) and 98.34(d)(3) also incorporate
by reference several ASTM standards, including ASTM D2234 (Standard Practice for Collection
of a Gross Sample of Coal), which permits less frequent sampling. To the extent that the specific
sampling procedures in 40 C.F.R. §§98.34(c) and (d)(3) conflict with the general reference to
ASTM D2234, the requirements in 40 C.F.R. §§98.34(c) and 98.34(d)(3) should control.
Request for Clarification and NLA's Proposal: The Proposed Rule should clearly state that the
incorporation by reference of ASTM D2234 at 40 C.F.R. §98.7 does not supersede the sampling
frequency requirements in 40 C.F.R. §§98.34(c) and 98.34(d)(3). Adherence to the sampling
requirements in 40 C.F.R. §§98.34(c) and 98.34(d)(3) will provide a minimum, consistent
sampling frequency among Tier 2 and Tier 3 facilities. ASTM D2234, in contrast, requires a
sampling frequency that is calculated based on plant-specific factors, possibly as often as daily or
even several times daily.
Response: EPA has revised §98.34 to clarify that only the methods listed in that section may be
used for fuel sampling and analysis for Tiers 2 and 3, regardless of any other methods that are
368
-------
incorporated in §98.7. ASTM D2234, though incorporated by reference at §98.7, is not listed in
§98.34, and therefore may not be used for the purposes of Subpart C.
Commenter Name: Leslie Bellas
Commenter Affiliation: National Lime Association (NLA)
Document Control Number: EPA-HQ-OAR-2008-0508-0520.1
Comment Excerpt Number: 47
Comment: The Preamble, 74 Fed. Reg. at 16,523 and 40 C.F.R. 98.194(d) states that the NLA
Protocol is incorporated by reference at 98.7. However, 40 C.F.R. 98.7 does not incorporate the
NLA Protocol.
Response: The NLA C02 Emissions Calculation Protocol for the Lime Industry — English
Units Version is incorporated by reference into the final rule at §98.7.
Commenter Name: Lorraine Krupa Gershman
Commenter Affiliation: American Chemistry Council (ACC)
Document Control Number: EPA-HQ-OAR-2008-0508-0423.2
Comment Excerpt Number: 59
Comment: For §§98.34(c)(1) and (d)(3), the composition of natural gas does not change often
enough to warrant monthly sampling. At most, ACC recommends annual sampling. ACC
recommends eliminating the source sampling and testing of fuels, including pipeline natural gas
supplies, to reduce the excessive burden of each facility needing to sample and analyze the fuel
when instead it could be more efficiently sampled and analyzed only once by the supplier.
Additionally, the sampling frequency should be yearly or whenever the supplier changes the
source of the fuel such that the fuel composition may be likely to change. These fuels will not
appreciably change in composition from month to month. As an alternative, requiring these fuels
to be sampled twice per year would align with many custom fuel sampling schedules for
determining sulfur content of natural gas.
Response: EPA acknowledges the commenters' concerns regarding natural gas sampling costs,
and has revised the §98.34 as follows: for natural gas, semiannual sampling and analysis is
required.
Commenter Name: Dan F. Hunter
Commenter Affiliation: ConocoPhillips Company
Document Control Number: EPA-HQ-OAR-2008-0508-0515.1
Comment Excerpt Number: 24
Comment: In 98.34(c)(1), sources combusting natural gas require monthly sampling and
analysis for HHV. Monthly collection of production fuel gas samples can be burdensome. The
composition of production field gas at natural gas processing facilities does not vary enough to
369
-------
warrant monthly analysis of HHV. Production field gas should be measured no less frequent
than quarterly. Monthly sampling and analysis of refinery fuel gas is reasonable. The ability to
justify a longer frequency should be considered for the final rule. ConocoPhillips encourages
EPA to develop an approach under Tier 2 that would allow facilities to reduce the frequency of
testing once the measured data demonstrates the HHV of the natural gas meets certain statistical
requirements (variability) and then periodic testing to demonstrate the measurement results
remains statistically equivalent to the established HHV. Note that under 98.3 6(d)(l )((ii)(A), for
Tier 2 calculation methodology, the rule requires submittal of the monthly fuel HHV data. This
requirement would need to be modified to meet the required measurement frequency.
Response: EPA acknowledges the commenters' concerns regarding natural gas sampling costs,
and has revised the rule to require semiannual sampling and analysis.
Commenter Name: Paul R. Pike
Commenter Affiliation: Ameren Corporation
Document Control Number: EPA-HQ-OAR-2008-0508-0487.1
Comment Excerpt Number: 14
Comment: Our acceptance of a requirement for ARP units to rely on their Part 75 cumulative
CO2 mass emissions estimates is limited to this rulemaking, and does not automatically extend to
rules regulating emissions of C02. C02 mass emissions data reported under Part 75 are affected
by a rule requiring "bias" adjustment of volumetric flow monitor data based on the results of a
statistical analysis of relative accuracy test audit ("RATA") data comparing the flow monitor's
response to an EPA reference method. If the RATA data are determined to be "biased" based on
a one-tailed test, all hourly flow monitor data from that RATA forward are adjusted "upward" by
a calculated bias adjustment factor ("BAF") until a new RATA is performed. We believe that the
test, which is based on data from a single stack test, does not represent true "bias." The test also
does not allow for adjustment of data downward if the test indicates that the "bias" in the data is
positive. Adjustment of volumetric flow monitoring data in this manner can result in a
significant difference in the reported, versus measured, CO2 mass emissions. When EPA has
relied upon Part 75 data in other regulatory programs, like the NSPS, EPA has always made clear
that sources are to use the unadjusted data, which is also recorded. However, because Part 75
does not require calculation of hourly CO2 mass emissions in its "unadjusted" form (only
unadjusted hourly volumetric flow data are reported), using unadjusted data for the purposes of
this rule would require additional calculations and software changes for ARP units. ARP units
could not rely on their reported cumulative values. As a result, Ameren is not seeking an
alternative to report unadjusted data at this time, but may do so in a future rulemaking if the data
are to be used for regulatory purposes.
Response: See the Preamble, Section III. C., the Subpart D comment response document
volume, and the response to comment EPA-HQ-OAR-2008-0508-0956.1 excerpt 20 for the
rationale for using substitute data reported under Part 75.
Under this rulemaking, EPA is not revising Part 75 reporting requirements. EPA is keeping
GHG monitoring requirements consistent with current monitoring because the Agency does not
want to require two sets of data which would add cost and complexity.
370
-------
Commenter Name: Trudy Richter
Commenter Affiliation: Minnesota Resource Recovery Association (MRRA)
Document Control Number: EPA-HQ-OAR-2008-0508-0546
Comment Excerpt Number: 1
Comment: The MRRA objects to the proposed rule in section (f) on page 16637 of the Federal
Register, Volume 74, No. 68 that requires a determination of the biogenic portion of C02
emissions utilizing ASTM D6866-06a and ASTM D 7459-08. The rule requires that the tests be
performed every calendar quarter. This testing methodology and frequency are burdensome for
waste to energy facilities. In Minnesota, we have gathered information every five years from
waste sorts performed consistent with applicable rules. These sorts indicate that the waste
stream components have not varied significantly in the last twenty years and that approximately
66% of the waste, when combusted, would produce biogenic C02. Testing quarterly is totally
unnecessary and the rule should offer acceptable alternatives as follows: 1) No testing is
required unless the facility proposes to sell its renewable electricity to the grid; and 2) Testing
only applies if there is parity with landfill gas recovery systems also performing an equal amount
of testing; and 3) Testing only once every three years is adequate (in conjunction with other stack
testing) or 4) Allowing in the alternative, the use of waste sort data to calculate the biogenic
portion of C02.
Response: EPA disagrees with the commenter, and believes that quarterly sampling is necessary
given the potential for variation in different solid waste streams across the municipal waste
combustor population.
Commenter Name: Obadiah Bartholomy
Commenter Affiliation: Sacremento Municipal Utility District
Document Control Number: EPA-HQ-OAR-2008-0508-0540.1
Comment Excerpt Number: 2
Comment: SMUD believes there is a need for flexibility in metering of biogas fuel in locations
offsite from the facility where the fuel is to be combusted. The electric utility industry is
experiencing unprecedented change in the kinds of fuels used to generate electricity and any
mandatory reporting rule should facilitate such innovation. Heretofore, biogenic gas or biogas
(such as landfill gas and digester gas) has been burned for energy at the same location the gas has
been generated. But new arrangements are being used to generate gas in one location and
transmit it to generators in some cases states away for convenient electricity generation. One
model is to connect a landfill or digester with a dedicated pipeline to a gas-fired power plant.
Another model is to purchase biogas from a remote location, clean the gas to pipeline gas quality
specifications, and transmit it through common pipelines to the LDC's system, again for
combustion at a gas-fired power plant. These kinds of agreements enable more efficient
conversion of chemical energy to electrical energy because combined-cycle gas plants are among
the cleanest and most efficient generating units in use, whereas many on-site combustion
technologies are less efficient and face challenges in managing associated criteria pollutants.
Consequently, with greater conversion efficiencies, the relative emissions of GHG are reduced
per unit of energy (MWh) produced and consumed. The EPA should make sure that its reporting
371
-------
rule is consistent with the more efficient use of biogenic gas. Many electric generating units
(EGUs) that burn natural gas are subject to EPA's acid rain program (ARP). Subpart D of the
Proposed Rule (proposed §98.46(a)) specifies that the Data Reporting Requirements for EGUs
subject to the ARP are the same as some but not all of those specified in Subpart C, §98.36.
However, for EGUs subject to the ARP, there does not appear to be a clear nexus between
Subpart D and the calculation methodologies in Subpart C with respect to biogenic GHG
emissions. Furthermore, it is unclear from Subpart C how such EGUs should report biogas co-
mingled in either dedicated or common supply pipelines that deliver gas for combustion in power
plants. While the Proposed Rule does address metering of gas drawn from common supply
pipelines in certain situations, there is ambiguity in the Proposed Rule about separate metering
and reporting of co-mingled gas. Landfill or digester gas piped to power plants from remote
locations is ultimately burned and generates GHG emissions. The proposed regulation clearly
evidences an intent to report these emissions separately from the combustion of natural gas. (See
proposed §98.33(e)) However, if such biogas is co-mingled in a pipeline it becomes
indistinguishable from natural gas so that, arguably, the same gas is not burned when it is
withdrawn at the purchaser's power plant. If the biogas is not accounted for then there is gas in
the interstate system that leads to GHG emissions that are not reported separately. Rather than
abandon efforts to track emissions from biogas transmitted by pipeline, a simple solution would
be to provide for metering the gas at the point of injection and backing out the same amount from
the amount withdrawn by the owner of the biogas. In this way, the same amount of biogas
injected into the pipe is accounted for. If EPA amends its Proposed Rule to provide a method for
separate metering and netting of such co-mingled biogas the intent of the rule is preserved and
whatever attributes or benefits that may come with purchasing a renewable or recycled product is
preserved to the purchaser. This change should promote use of such gas in higher efficiency,
combined cycle gas-fired power plants rather than at lower efficiency combustion units at
landfills or digesters.
Response: See Subpart D for a description of the reporting requirements for EGUs over and
above the requirements under 40 CFR Part 75.
In §98.33(e)(2), EPA has added a provision allowing facilities to calculate biogenic CO2
emissions from the combustion of biogas using Tier 1 methods, provided that the quantity of the
biogas combusted can be determined from company records, as defined in §98.6, and default
factors for the fuel are provided in Table C-l. Biogas has been added to Table C-l, and is listed
as "Biogas (captured methane)." Also, for premixed fuels that contain biomass and fossil fuels
(e.g., mixtures containing biodiesel), best available information can be used to determine the
mass of biomass fuels and document the procedure used in the GHG Monitoring Plan required
by §98.3(g)(5).
Commenter Name: LisaD. Schmidt
Commenter Affiliation: Dow Corning Corporation
Document Control Number: EPA-HQ-OAR-2008-0508-0562
Comment Excerpt Number: 3
Comment: The timeline to respond to data requests from the EPA needs to be extended to a
minimum of 30 days. The current proposal of seven days is insufficient to provide a thorough
response to any request for detailed technical information.
372
-------
Response: EPA acknowledges the commenters' concerns. In §98.36(e)(3) of the final rule, EPA
has allowed owners or operators 30 days from receipt of a written request for information to
respond to that request.
Commenter Name: Laurie Zelnio
Commenter Affiliation: Deere & Company
Document Control Number: EPA-HQ-OAR-2008-0508-0355.1
Comment Excerpt Number: 5
Comment: The Tier 3 calculation methodology set forth in §98.33(a)(3) states: "For liquid and
gaseous fuels, the volume of fuel combusted is measured directly, using fuel flow meters
(including gas billing meters)." At Deere's affected facilities, the natural gas billing meters are
installed and maintained by our utility companies. As the meters do not belong to our affected
facilities, calibrating the meters becomes an ownership issue. In the proposed rule, calibration of
natural gas billing meters is exempted under §98.34(d)(1) Monitoring and QA/QC Requirements
as follows: "All oil and gas flow meters (except for gas billing meters) shall be calibrated prior
to the first year for which GHG emissions are reported... and recalibrated annually or at the
minimum frequency specified by the manufacturer." However, the calibration of natural gas
billing meters is not exempted under alternative reporting requirements or verification data. To
effectively implement this exemption, Deere recommends the phrase "except for gas billing
meters" be added to §§98.38(c)(3) and 98.35(d)(l)(iii)(F).
Response: EPA acknowledges the concerns of the commenter. Section 98.34 of the final rule
has been clarified to exempt fuel billing meters from the calibration requirement, "provided that
the supplier and the unit(s) combusting the fuel do not have any common owners and are not
owned by subsidiaries or affiliates of the same company."
Commenter Name: Gary Moore
Commenter Affiliation: Pensacola Plant of Ascend Performance Materials LLC
Document Control Number: EPA-HQ-OAR-2008-0508-0366.1
Comment Excerpt Number: 8
Comment: In the Preamble to the rule on page 16483 it states: "In addition, EPA is proposing
that a facility may use the Tier 3 calculation methodology to calculate facility-wide CO2
emissions (rather than unit-by-unit emissions) when the same liquid or gaseous fuel is used
across the facility and a common direct measurement of fuel consumed is available (e.g., a
natural gas meter at the facility gate). This flexibility is consistent with existing protocols and
methodologies allowed by EPA in existing programs." In §98.36(c)(1) only the aggregation of
small units is allowed. Allowing the option of aggregation of emissions for all sources
(including boilers, combustion turbines, process heaters, natural gas fueled hydrogen plants,
control devices) using the common fuel and a single billing meter would ease reporting and not
reduce data quality. Furthermore, this reduces propagation of error issues due to summing up
emissions from many meters and also allows the Agency to more accurately track natural gas
from production to end use. We propose that the Agency allow the use of natural gas fence line
373
-------
billing meters or invoices from the distribution company to be used in Tier 3 emission
calculations for all emissions from natural gas. Other fuels combusted would be reported
separately for each individual combustion unit.
Response: EPA acknowledges the concerns of the commenter and has revised the rule to allow
more flexibility in reporting. For units that use Tiers 1, 2, and 3 to calculate CO2 mass
emissions, the cumulative 250 mmBtu/hr heat input capacity limit on the aggregation of units
into a group has been dropped. Rather, the 250 mmBtu/hr restriction applies only to the
individual units in the group. Therefore, for reporting purposes, individual units with maximum
rated heat input capacities of 250 mmBtu/hr or less may be aggregated without limit into a single
group, provided that the Tier 4 methodology is not required for any of the units, and all units in
the group use the same Tier for any common fuel(s) that they combust. Units with maximum
rated heat inputs greater than 250 mmBtu/hr using Tiers 1, 2, and 3 must report as individual
units, unless they burn the same type of fuel (oil or gas) provided by a common pipe or supply
line; in that case, the owner or operator may opt to use the highest Tier required for a grouped
unit for the calculation method with the common pipe reporting provisions in §98.36. Units
using Tier 4 must report as individual units unless they share a monitored common stack; in that
case, the common stack reporting provisions of §98.36 may be used.
Commenter Name: See Table 4
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0455.1
Comment Excerpt Number: 8
Comment: Under proposed §98.34, stationary fuel combustion sources subject to Tier Four
monitoring requirements would be required to upgrade their existing CEMS if (1) the CEMS gas
monitor is neither a CO2 concentration monitor nor an O2 concentration monitor and (2) if a
flow monitor is not already installed. The Class of'85 believes that concentration monitors are
not necessary to accurately report CO2 emissions from EGUs. Many EGUs with CEMS
currently utilize other means for calculating their CO2 emissions that are equally as accurate as
and less costly than installing new monitors. Several of these EGUs, which currently report CO2
emissions to state and regional mandatory GHG programs, use fuel emission factors and EPA
approved methodologies to accurately calculate and report their CO2 emissions. Required
upgrades to CEMS would impose an unnecessary economic burden on facilities. Upgrading an
EGU's CEMS to include a concentration monitor can cost well over $50,000 per unit, plus costs
associated with certification, ongoing testing, and maintenance. Furthermore, the Agency's
proposed implementation schedule would not provide sufficient time to acquire, install, and test
new concentration monitors prior to beginning mandatory reporting in January 2010. For these
reasons, the Class of '85 believes that EPA should not require EGUs with existing CEMS to
upgrade their systems to include a concentration monitor. Instead, EPA should allow these
EGUs to utilize fuel emission factors and EPA approved methodologies to calculate their CO2
emissions. At the least, EPA should extend its proposed reporting deadline to allow adequate
time for EGUs to upgrade their CEMS.
Response: See the Preamble, Section II. L., on General Monitoring Requirements for the overall
rationale for methodologies required under this rule, and the response to comment EPA-HQ-
374
-------
OAR-2008-0508-0909.1 excerpt 4 and EPA-HQ-OAR-2008-0508-0580 excerpt 10 for the
rationale for methodologies required under Subpart C.
EPA is requiring the use of CEMS for solid fossil fuel-fired units due to the complexity of
monitoring solid fuel consumption and the heterogeneous nature of the solid fuels. EPA has
considered the commenter's analysis, but disagrees with the commenter's assessment of the
burden associated with installing and maintaining the concentration and volume monitors that the
rule requires be added to an existing CEMS. In the revised rule, EPA has clarified that if the unit
in question meets all six criteria for Tier 4 to apply. EPA's estimates of monitoring costs are
averages for a representative facility and may not represent the actual cost in individual
circumstances. Note that EPA's cost estimates are annualized and do not widely differ from the
capital cost cited in this comment. Further detail on the engineering cost analysis for Subpart C
can be found in RIA (EPA-HQ-OAR-2008-0318-002) Section 4.3.
Commenter Name: John L. Wittenborn et al.
Commenter Affiliation: Steel Manufacturers Association (SMA) and Specialty Steel Industry
of North America (SSINA)
Document Control Number: EPA-HQ-OAR-2008-0508-0518.1
Comment Excerpt Number: 8
Comment: Many steel facilities have natural gas burners above the 250 MMBTU threshold and
therefore would be subject to the proposed Tier III reporting thresholds, which would require
monthly sampling of the carbon content of natural gas. We do not believe that monthly sampling
of pipeline quality natural gas is warranted. Such a requirement is inconsistent with methods
EPA previously has found acceptable under Title IV. The Title IV requirements allow CO2
calculations based on fuel flow measurements and heat content values supplied by natural gas
utilities. If EPA believes that this is not sufficient to extrapolate a reasonable value for average
carbon content, they should require that natural gas suppliers sample their product and provide
the data to customers along with heating values. It is unreasonable to require each consumer to
sample the same fungible commodity material.
Response: EPA acknowledges the commenters' concerns regarding natural gas sampling costs,
and has relaxed the natural gas sampling requirement to semiannual sampling and analysis.
Data provided by the fuel suppliers may be used in some circumstances.
Commenter Name: See Table 4
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0455.1
Comment Excerpt Number: 10
Comment: Under proposed §98.43, EGUs subject to the requirements of the Acid Rain
Program would continue to monitor and report CO2 mass emissions in accordance with the
monitoring requirements of 40 C.F.R. Part 75. Under Part 75, certain distillate oil and natural
gas acid rain affected units may use alternative monitoring methods in lieu of CEMS. The Class
of'85 supports this decision to continue the use of time-proven monitoring techniques.
375
-------
However, under proposed §§98.43(b) and 98.44(b), EGUs not subject to the Acid Rain Program
would be required to calculate CO2 emissions and follow the quality assurance and quality
control procedures identified in the four-tiered system of Subpart C of the Proposal. Within this
four-tiered system, distillate oil and natural gas EGUs that are not subject to the Acid Rain
Program may elect to employ the monitoring methods of Tier Four, as it is available to a unit of
any size combusting any type of fuel. Tier Four, however, only allows monitoring via CO2 or
02 concentration monitors or flow CEMS, which must be quality assured in accordance with
Part 75 requirements. Importantly, Tier Four does not include the alternative monitoring
methods found in Appendices D and G of Part 75. If the alternative monitoring methods of 40
C.F.R. Part 75 are acceptable for measuring, reporting, and quality assuring CO2 emissions from
acid rain affected EGUs, then it seems only logical that they should be acceptable for measuring,
reporting, and quality assuring CO2 from non-acid rain affected units. Therefore, the Class of
'85 believes that the Agency should allow EGUs that are not subject to the Acid Rain Program to
monitor and report CO2 mass emissions in accordance with the monitoring requirements of 40
C.F.R. Part 75, including the alternative methods allowed under Appendices D and G of Part 75.
Response: EPA has added Part 75 methodologies in Subpart C that may be used by sources that
are currently required to report heat input data under Part 75, but are not required to report CO2
mass emissions. The new methodologies allow these sources to use their Part 75 heat input data
together with one of the CO2 emissions Calculation Methodologies in Part 75 to meet Part 98
C02 emissions reporting requirements.
Commenter Name: Janice Adair
Commenter Affiliation: Western Climate Initiative (WCI)
Document Control Number: EPA-HQ-OAR-2008-0508-0443.1
Comment Excerpt Number: 11
Comment: A minimum accuracy may also be needed for fuel flow meters when fuel
consumption is used to calculate GHG emissions. For quality-assurance purposes, U.S. EPA
proposes that liquid and gaseous fuel flow meters at facilities subject to the more advanced Tier
3 methods for stationary combustion would have to be calibrated prior to the first reporting year.
Meter accuracy is not prescribed, however, so meters with poor accuracy could remain in place
as long as they are calibrated to manufacturer specifications. WCI recommends that U.S. EPA
consider a documented minimum accuracy for meters that play a significant role in the
calculation of facility GHG emissions. At minimum, we recommend inclusion of a provision
that when new flow meters are installed that will be used to calculate facility GHG emissions,
the meters be specified as accurate to + 5 percent. In a future market system, accurate emissions
measurement will become especially important. With accurate metering and proper sampling,
fuel-based methods can be as effective as more costly continuous emissions monitoring systems.
Response: EPA concurs and has added a five percent accuracy specification to §98.3. This
specification must be met by March 31, 2010, except for flow meters described above that
qualify for deadline extensions; these meters must meet the specification at the time of their next
scheduled calibration.
376
-------
Commenter Name: Edward N. Saccoccia
Commenter Affiliation: Praxair Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-0977.1
Comment Excerpt Number: 7
Comment: The proposed rule requires all liquid and gaseous fuel flow meters to be calibrated
initially and annually, or at the meter manufacturer's specified frequency, thereafter. This
requirement fails to recognize that some fuel measurement device installations do not allow
calibration without taking the fuel line out of service, thereby forcing a shutdown of the
combustion/manufacturing process. In many instances, scheduled maintenance shutdowns for
such equipment/processes will not occur on this prescribed frequency. Unless provisions are
added to the proposed rule which provide relief from this required calibration frequency,
manufacturing processes will be required to shutdown solely to complete the required
calibration, resulting in significant cost, business disruption and, in many cases, increase
environmental impacts from the inefficiencies of the start-up/shutdown activity. This need is
comparable to provisions under many EPA rules regarding the repair of leaking VOC fugitive
emissions components where repair would require a process shutdown, and instead the repair
deadline is extended to the next scheduled maintenance shutdown. In most instances, the delay
in calibration of a flow meter requiring a process shutdown would not materially compromise the
annual emission estimate. This is particularly true for those combustion units using the simplest,
cleanest fuels - there is typically less "drift" in the calibration of flow measurement devices for
such clean fuels and such combustion units/processes often require less frequent maintenance
turnarounds, exacerbating the need for extension of the calibration frequency. The rule should
include provisions for an extension of the required flow meter calibration deadline (as well as the
initial calibration, if appropriate) where the calibration would require removing the fuel supply
from service. The calibration requirement should then be extended to the next scheduled
maintenance shutdown for the impacted unit/process.
Response: EPA acknowledges the concerns of the commenters. Section 98.34 of the final rule
clarifies that for units and processes that use a venturi, orifice, or nozzle meter and operate
continuously with infrequent outages, the owner or operator may postpone the initial calibration
or PEI (as applicable) until the next scheduled maintenance outage, and may similarly postpone
the subsequent recalibrations and PEIs.
Commenter Name: Paul R. Pike
Commenter Affiliation: Ameren Corporation
Document Control Number: EPA-HQ-OAR-2008-0508-0487.1
Comment Excerpt Number: 13
Comment: Proposed §§98.44 - 98.46 repeat requirements that are already set out either in Part
75 or in Subpart C. The CO2 data that were reported under Part 75 will either be Part 75 quality-
assured data, or data estimated using Part 75 missing data procedures. It also is not necessary to
require in this rule that such units "continue to monitor and report" CO2 emissions under Part 75,
as required under §98.43, or to specify under this subpart the meaning of terms, as stated in
§98.48. Ameren supports allowing ARP units to report using the cumulative CO2 mass
377
-------
emissions estimates reported under Part 75; however, we believe that §98.43 could be revised to
simplify Subpart D.
Response: EPA has included rule language that may appear to be redundant in order to provide
clarity concerning requirements under Part 75 and Part 98.
Commenter Name: Vince Brisini
Commenter Affiliation: RRI Energy Inc. (RRI)
Document Control Number: EPA-HQ-OAR-2008-0508-0618.1
Comment Excerpt Number: 7
Comment: U.S. EPA should allow companies to use the alternative monitoring methods found
in Appendices D and G of Part 75 both for EGUs subject to the Acid Rain Program (Part 75) and
those not subject to Part 75. Under its proposed GHG reporting rule, U.S. EPA proposes to
allow distillate oil and natural gas EGUs that are not subject to the Acid Rain Program to employ
the monitoring methods of Tier 4. However, Tier 4 specifies that CO2 or O2 concentrations must
be monitored through CEMS and quality assured in accordance with Part 75 requirements. The
main discrepancy between Part 75 and the current proposed GHG reporting rule is that Tier 4
methodology specified in the 0110 rule does not include the alternative monitoring methods
found in Appendices D and G of Part 75. If U.S. EPA allows alternative monitoring methods for
EGUs subject to Part 75 of the Acid Rain Program, it should also allow companies to apply all
Part 75 methodologies to non-acid rain affected units.
Response: EPA has added new methods for sources that are currently required to report heat
input data under Part 75, but are not required to report CO2 mass emissions. The methods allow
these sources to use their Part 75 heat input data together with one of the CO2 emissions
Calculation Methodologies in Part 75 to meet Part 98 CO2 emissions reporting requirements.
Commenter Name: Michael W. Stroben
Commenter Affiliation: Duke Energy Corporation
Document Control Number: EPA-HQ-OAR-2008-0508-0407.1
Comment Excerpt Number: 18
Comment: Under EPA's proposal, Subpart C facilities that burn landfill gas would be required
to perform daily sampling of the carbon content of the gas they receive when using the Tier 3
calculation method. In situations where the landfill is already sampling the carbon content of the
gas on a daily or continuous basis or will be doing so under this rule the downstream facility
should not be required to also perform sampling. The facility should be allowed to use the data
provided by the gas supplier. It makes no sense to have both the landfill gas supplier and the
facility using the gas to perform the same sampling.
Response: See the response to comment EPA-HQ-OAR-2008-0508-0540.1 excerpt 2, for an
explanation of additional flexibility for characterizing biogas. The Agency has revised the final
rule to clarify that fuel sampling and analysis data provided by the supplier may be used in the
emission calculations.
378
-------
Commenter Name: Stephen E. Woock
Commenter Affiliation: Weyerhaeuser Company
Document Control Number: EPA-HQ-OAR-2008-0508-0451.1
Comment Excerpt Number: 21
Comment: If EPA ultimately decides that the fuel factors (i.e., HHV and carbon content) must
be determined by periodic analytical testing, then these determinations can be accomplished in a
more appropriate timeframe rather than testing endlessly. Continuous monthly fuel testing will
not enhance the accuracy of the GHG calculations, and will impose an unnecessary level of
additional expense and burden on reporters. Because the properties of commonly used fuels,
such as natural gas, oil, gasoline, etc. do not change significantly, once an initial fuel
characterization is completed for a facility any re-testing should only be necessary infrequently.
For example, if a different supplier is used, re-testing could be imposed. In addition, forest
product industry specific fuel characteristics, such as pulping spent liquor and bark also do not
change significantly over time to warrant monthly testing. The following describes how the fuel
factors should be determined for the different fuels: 1. Natural gas: The HHV and carbon
content of natural gas does not change significantly over time. This is due to contractual fuel
guarantees with the supplier, who guarantees specific fuel properties, in particular the heating
value. Initial fuel characterization would be provided by the supplier, with review of the
supplier's fuel factors annually. 2. Oil: The HHV and carbon content of natural gas does not
significantly change over time. This is due to contractual fuel guarantees with the supplier, who
guarantees specific fuel properties. In addition, oil is typically purchased in large quantities and
stored onsite. The fuel properties of this blended, homogeneous mix of oil in these large storage
tanks will not change rapidly, and to continue to retest monthly out from the same storage tank is
unreasonable. Initial fuel characterization would be provided by the supplier, with review of the
supplier's fuel factors annually. 3. Coal: The HHV and carbon content of coal does not
significantly change over time. This is due to contractual fuel guarantees with the supplier, who
guarantees specific fuel properties. Coal is typically purchase in large quantities and stored
onsite. Continuous deliveries of coal are added to the storage pile. Initial fuel characterization
would be provided by the supplier, with review of the supplier's fuel factors annually. 4. Wood
residuals at Pulp Mills: Wood residuals, mostly bark from trees, are generated in large quantities
and stored onsite. Weyerhaeuser proposes an alternative GHG calculation approach, which will
not require any fuel testing. In our comment #7 below, we describe an accurate and reliable
methodology to calculate GHG emission from all solid fuels. This methodology is already
allowed in this proposed rule for municipal solid waste (MSW) combustion units. It also should
be allowed for the calculation of GHG emissions from wood residuals, which will eliminate an
unnecessary and costly fuel testing program. 5. Spent pulping liquor: Spent pulping liquor is
generated in large quantities and stored temporarily in large tanks before it is combusted for
inorganic chemical and biomass energy recovery. During this temporary storage the large
quantities of spent pulping liquor blend and homogenize the material's properties. Although
spent liquor properties may differ between facilities, the spent liquor at each site will exhibit
consistent properties. Therefore, after an initial fuel characterization is conducted the material
could be retested on a longer, more representative frequency schedule, such as annually or every
two years.
379
-------
Response: The mandatory monthly fuel sampling and analysis requirements for traditional
fossil fuels have been dropped from Tiers 2 and 3. Section 98.34 has been revised to require that
natural gas be sampled semiannually. For fuel oil and coal, a representative sampling is required
for each fuel lot, i.e., for each shipment or delivery. For other liquid fuels and biogas, quarterly
sampling is required. For other solid fuels, excluding municipal solid waste, weekly composite
sampling with monthly analysis is required. For other gaseous fuels, the daily sampling
requirement has been retained, but only for facilities with existing equipment in place that is
capable of providing the data. Otherwise, weekly sampling is required, which may be postponed
in favor of monthly sampling until 2011 if new equipment must be purchased or if existing
equipment must be upgraded to meet the weekly sampling and analysis requirements.
The final rule clarifies that fuel sampling and analysis data provided by the supplier may be used
in the emission calculations, and that fuel billing meters may be used to quantify fuel
consumption. To simplify the emission calculations in Tiers 2 and 3, averaging of HHV and
carbon content data is permitted if these data are obtained at least at the minimum frequency
specified in §98.34. If the results of fuel sampling are received monthly or more frequently, the
weighted annual average high heat value shall be calculated using Equation C-2b. If the results
of fuel sampling are received less frequently than monthly, then the annual average HHV shall
be calculated using the arithmetic average HHV for all valid samples for the year. However,
regardless of the sampling frequency, the owner or operator must use the results of all available
valid fuel analyses in the emissions calculations.
EPA appreciates your comment and has allowed the use of steam production and combustion
unit efficiency to calculate CO2 emissions to be extended to other solid fuels in addition to
municipal solid waste. These parameters may also be used to quantify the amount of biomass
combusted in a unit.
Spent pulping liquor is not subject to Subpart C, but is addressed in Subpart AA. See the
Preamble, Section III. AA., and separate Pulp and Paper response to comment document for
EPA's response on spent pulping liquor measurement requirements.
Commenter Name: Angela Burckhalter
Commenter Affiliation: Oklahoma Independent Petroleum Association (OIPA)
Document Control Number: EPA-HQ-OAR-2008-0508-0386.1
Comment Excerpt Number: 23
Comment: EPA proposes to require reporters determine the carbon content for natural gas
monthly. Natural gas produced at oil and gas production facilities is used to run many
combustion units, and its composition does not change appreciably over time. If the fuel source
does not change, why is this needed? EPA should include in the rule at most, a one-time testing
requirement if the fuel source does not change significantly.
Response: EPA acknowledges the commenters' concerns regarding natural gas sampling costs,
and has revised the §98.34 as follows: for natural gas, semiannual sampling and analysis is
required.
380
-------
Commenter Name: Angela Burckhalter
Commenter Affiliation: Oklahoma Independent Petroleum Association (OIPA)
Document Control Number: EPA-HQ-OAR-2008-0508-0386.1
Comment Excerpt Number: 24
Comment: Under Tier 2, EPA proposes that the high heat value of each fuel combusted be
measured monthly. If the fuel source does not change, why is this measurement needed? We
request EPA include in the rule at most, a one-time testing requirement if the fuel source does
not change.
Response: EPA agrees with the commenter and the mandatory monthly fuel sampling and
analysis requirements for traditional fossil fuels have been dropped from Tiers 2 and 3. Section
98.34 has been revised to require that natural gas be sampled semiannually. For fuel oil and
coal, a representative sampling is required for each fuel lot, i.e., for each shipment or delivery.
For other liquid fuels and biogas, quarterly sampling is required. For other solid fuels, excluding
municipal solid waste, weekly composite sampling with monthly analysis is required. For other
gaseous fuels, the daily sampling requirement has been retained, but only for facilities with
existing equipment in place that is capable of providing the data. Otherwise, weekly sampling is
required, which may be postponed in favor of monthly sampling until 2011 if new equipment
must be purchased or if existing equipment must be upgraded to meet the weekly sampling and
analysis requirements.
Commenter Name: Verne Shortell
Commenter Affiliation: NRG Energy, Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-0634.1
Comment Excerpt Number: 3
Comment: Reporting and monitoring rules (40 CFR Part 75) were developed to address the
Acid Rain Program allowance trading program, i.e. SO2 allowances. The rules were developed
at a time when emissions trading and markets were in their infancy, and there was little
experience with flow monitors. In addition, there are fundamental differences that exist between
SO2 and CO2 flue gas concentrations. The conservatism, previously acceptable when
monitoring SO2, becomes cost prohibitive under a CO2 monitoring and allowance trading
regime. Consideration should be given to changes of the Part 75 rules prior to carte blanche
application to a GHG trading program.
1. Part 75 SO2 methodology is neither necessary nor appropriate for CO2. The primary emphasis
in the Part 75 monitoring was to track SO2 emissions from coal-fired power plants. Because
there is significant variation in the sulfur content of coal and coal sampling techniques affect the
measurement of sulfur content, the rules do not allow data reporting based on anything other than
hourly CEMS data. However, it also became quickly apparent that for oil and gas fired units,
fuel sampling and measurement was an accurate way to calculate SO2 emissions for those
sources. As a result, optional approaches for SO2 reporting were allowed. The variation of
carbon content in coal is much more similar to the sulfur content in oil, so the variation in carbon
content is not as important when measuring and reporting CO2 emissions. The quantity of coal
burned is a financially important parameter, so facilities measure the amount of coal burned
accurately. In both cases even if there is hour-to-hour variation, the long-term results should
381
-------
even out and C02 is only a concern over longer periods. Therefore, if a facility can certify coal
quantity measurements then it should be allowed to calculate the CO2 emitted based on carbon
content measurements and the amount of fuel burned. In order to completely and accurately
track SO2 emissions via CEMS, the Part 75 rules include a data substitution methodology for
hourly data that encourages high monitor data availability. If data are missing, either because a
monitor or data acquisition and handling system (DAHS) is down or there is a validation issue,
data are substituted on a sliding scale based on monitor data availability [See DCN: EPA-HQ-
OAR-2008-0508-0634.1 for Table 1 - Missing Data Procedure for S02 CEMS, C02 CEMS,
Moisture CEMS, Hg CEMS, and diluent (C02 or 02) Monitors for Heat Input Determination
provided by the commenter]. As noted above this is appropriate for S02 where hourly data
could be variable. However, C02 hourly variation is not as significant; therefore, data
substitution for longer periods could be accomplished by using fuel consumption data.
2. EPA should allow alternative approaches to Part 75 to estimate heat input accurately. Various
factors such as C02 removed from the flue gas, the upward bias, and drift can lead to inaccurate
measurements of C02 under Part 75. Under 40 C.F.R. Part 75, Appendix F, heat input is
calculated using the unit stack gas flow, percentage of C02 and a fuel-specific factor set forth in
Appendix F representing the heat content of each fuel (known as an "F Factor"). If C02 in the
unit's flue gas is removed, a primary variable in the CEMS equation will no longer be reliable.
Therefore, additional methods will need to be available in the regulations to determine a unit's
hourly and annual heat input. These additional methods could include mass fuel flow
measurements and fuel heat content analysis. There is a known upward bias in current stack
flow measurement regulations. Under 40 C.F.R. Part 75, a "reference monitor" is introduced
each year and compared to an affected unit's stack flow monitor. A side-by-side comparison is
performed, and for any resulting difference, a bias adjustment factor must be applied. However,
the current rules prescribe that only a positive adjustment factor can be applied. Therefore, if the
reference monitor demonstrates a higher level of flow than the affected unit's monitor, then a bias
adjustment factor is added into the stack flow equation. If the reference monitor demonstrates a
lower level of flow, no bias adjustment can be made. Drift, caused naturally by changing air
currents and temperature, also compromises C02 CEMS measurements. Though allowable
under current regulations, it can lead to additional C02 mass emissions error. It is estimated that
the combination of measurement methods and data processing techniques can add a positive
(high) bias to actual emission levels, perhaps "on the order of two-ten percent". [See DCN:
EPA-HQ-OAR-2008-0508-0634.1 for table showing the impact of just a one percent overall high
bias on NRG (2008 emissions)]. Note the relative difference between S02 and C02.
Response: See the Preamble, Section III. C., the Subpart D comment response document
volume, and the response to comment EPA-HQ-OAR-2008-0508-0956.1 excerpt 20 for the
rationale for using substitute data reported under Part 75.
Under this rulemaking EPA is not revising Part 75 reporting requirements. EPA is keeping GHG
monitoring requirements consistent with current monitoring because the Agency does not want
to require two sets of data which would add cost and complexity.
Facilities that meet the requirements laid out in §98.33(b) can choose from a number of C02
reporting options, including those suggested by the commenter.
382
-------
Commenter Name: Thomas M. Ward
Commenter Affiliation: Novelis Corporation
Document Control Number: EPA-HQ-OAR-2008-0508-0561.1
Comment Excerpt Number: 4
Comment: Carbon Content Determinations. The complexity of the additional carbon content
measurements and heating value measurements will add recordkeeping burdens and sampling
and analytical costs that are incommensurate with the small potential increase in GHG emission
accuracy that could be obtained. This is especially true for gas and liquid fuels that have
relatively constant carbon contents. We propose revising to the proposed rule so that Tier 1
reporting as a default with reporting at the higher tier levels available to facilities as an opt-in
effort. Default Tier 1 reporting should apply at the very least to small and medium size facilities.
In addition, alternative means for measuring content also need to be addressed in the rule such as
in-line measurements by such devices as calorimeters.
Response: See the Preamble, Section II. L., on General Monitoring Requirements for the overall
rationale for methodologies required under this rule, and the response to comment EPA-HQ-
OAR-2008-0508-0909.1 excerpt 4 and EPA-HQ-OAR-2008-0508-0580 excerpt 10 for the
rationale for methodologies required under Subpart C.
EPA has significantly expanded the use of the Tier 2 Calculation Methodology. The 250
mmBtu/hr restriction on the use of Tier 2 has been lifted for units that combust natural gas and
distillate oil, in view of the homogeneous nature and low variability in the characteristics of these
fuels. However, the 250 mmBtu/hr unit size cutoff remains for units that combust residual oil
and solid fossil fuel.
EPA has also relaxed the frequency of the required sampling and analysis. First, the mandatory
monthly fuel sampling and analysis requirements for traditional fossil fuels have been dropped
from Tiers 2 and 3. Section 98.34 has been revised to require that natural gas be sampled
semiannually. For fuel oil and coal, a representative sampling is required for each fuel lot, i.e.,
for each shipment or delivery. For other liquid fuels and biogas, quarterly sampling is required.
For other solid fuels, excluding municipal solid waste, weekly composite sampling with monthly
analysis is required. For other gaseous fuels, the daily sampling requirement has been retained,
but only for facilities with existing equipment in place that is capable of providing the data.
Otherwise, weekly sampling is required, which may be postponed in favor of monthly sampling
until 2011 if new equipment must be purchased or if existing equipment must be upgraded to
meet the weekly sampling and analysis requirements.
Commenter Name: Edward N. Saccoccia
Commenter Affiliation: Praxair Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-0977.1
Comment Excerpt Number: 6
Comment: The proposed rule requires periodic sampling and analysis of fuels for HHV or
carbon content under §98.34(c)(1) and (2) and §98.34(d)(3). The rule implies this sampling and
analysis is to be done by the consumer of the fuel, the reporting source. The proposed rule
383
-------
further describes minimum sampling and analysis frequencies for each fuel type. The proposed
rule implies a need for characterization of standard commercial fuels to meet calculation method
Tier 2 and 3, when, in actuality, the HHV and carbon content of standard fuels are nearly
constant values and default values (e.g. Tier 1 calculation method) yield sufficiently accurate
emission estimates. Recognizing the objective of the reporting rule is to develop a reasonable
estimate of the annual emissions from a source:
1. Standard fuels of commerce (natural gas, LP gas, fuel oils, etc.) that are supplied to multiple
consumers are more efficiently characterized by their suppliers than by their consumers.
2. Standard fuels of commerce (excepting coal) have very consistent HHV and carbon contents,
requiring much lower characterization frequency. Monthly characterization, as required under
§98.34(c)(1) and §98.34(d)(3), of such consistent fuels is costly and does not materially improve
the annual estimate of emissions.
3. Process-specific fuel sources (e.g. refinery gas) vary over time, but requiring daily sampling
and analysis is very burdensome and costly for a degree of characterization that is intended to
yield an annual emission estimate. The characterization of standard fuels of commerce should
not be required since default values employed under the Tier 1 calculation method will yield a
sufficiently accurate emission estimate (per comments regarding §98.33(b)(1), (3), and (4),
above). Characterization of standard fuels of commerce should be optional, at the source's
discretion. When a source chooses (or is required) to provide a fuel characterization, the
characterization sampling and analysis should be the responsibility of the fuel supplier. Such
suppliers should then be required to provide the characterizations to any fuel consumers, upon
request. The agency should then accept these characterizations for use under Tier 2 and 3
calculation methods. The characterization frequency of standard fuels of commerce should be
reduced to annually. The characterization of process-specific fuels should be reduced to
monthly. Alternately, a source should be able to demonstrate that, after a period of required
characterization, the variability of the average fuel characteristic (HHV or carbon content) is
sufficiently small to justify a reduction in the sampling and analysis burden.
Response: EPA acknowledges the commenter's concerns, and has revised its required sampling
and analysis methods. First, the mandatory monthly fuel sampling and analysis requirements for
traditional fossil fuels have been dropped from Tiers 2 and 3. Section 98.34 has been revised to
require that natural gas be sampled semiannually. For fuel oil and coal, a representative
sampling is required for each fuel lot, i.e., for each shipment or delivery. For other liquid fuels
and biogas, quarterly sampling is required. For other solid fuels, excluding municipal solid
waste, weekly composite sampling with monthly analysis is required. For other gaseous fuels,
the daily sampling requirement has been retained, but only for facilities with existing equipment
in place that is capable of providing the data. Otherwise, weekly sampling is required, which
may be postponed in favor of monthly sampling until 2011 if new equipment must be purchased
or if existing equipment must be upgraded to meet the weekly sampling and analysis
requirements.
The final rule clarifies that fuel sampling and analysis data provided by the supplier may be used
in the emission calculations, and that fuel billing meters may be used to quantify fuel
consumption. To simplify the emission calculations in Tiers 2 and 3, averaging of HHV and
carbon content data is permitted if these data are obtained at least at the minimum frequency
specified in §98.34. If the results of fuel sampling are received monthly or more frequently, the
weighted annual average high heat value shall be calculated using Equation C-2b. If the results
of fuel sampling are received less frequently than monthly, then the annual average HHV shall
be calculated using the arithmetic average HHV for all valid samples for the year. However,
384
-------
regardless of the sampling frequency, the owner or operator must use the results of all available
valid fuel analyses in the emissions calculations.
EPA has not required fuel suppliers to provide HHV and carbon content data to facilities, as it is
the source's responsibility to determine emissions. Fuel suppliers have their own reporting
requirements in other subparts. Additionally, it is the role of private sector transactions to
specificy the terms of the information provided through fuel purchase contracts.
Subpart KK, Suppliers of Coal, has not been included in this final rule. Subpart MM, Suppliers
of Petroleum Products, and Subpart NN, Suppliers of Natural Gas, provide upstream reporters
with the option of using default HHV and carbon contents or site specific sampling. EPA has not
required fuel suppliers to provide HHV data to facilities, as provision of this type of information
is typically addressed in private sector purchase contracts.
Commenter Name: None
Commenter Affiliation: Vectren Corporation
Document Control Number: EPA-HQ-OAR-2008-0508-0597
Comment Excerpt Number: 6
Comment: Vectren supports the limiting provision in section 98.34(d)(1) which states that "All
oil and gas flow meters (except for gas billing meters) shall be calibrated prior to the first year
for which GHG emissions are reported under this part..." And Vectren strongly urges EPA insert
a similar parenthetical to exclude gas billing meters from annual calibration, as follows: "Fuel
flow meters (except for gas billing meters) shall be recalibrated either annually or at the
minimum frequency specified by the manufacturer."
Response: EPA acknowledges the concerns of the commenters. Section 98.34(d)(1) of the final
rule has been clarified to exempt fuel billing meters from the calibration requirement, "provided
that the supplier and the unit(s) combusting the fuel do not have any common owners and are not
owned by subsidiaries or affiliates of the same company."
Commenter Name: Thomas M. Ward
Commenter Affiliation: Novelis Corporation
Document Control Number: EPA-HQ-OAR-2008-0508-0561.1
Comment Excerpt Number: 7
Comment: Small Emission-Unit Data Reporting Requirements Should be Revised to Reduce
Fuel Monitoring- Requirements Section 98.36(c)(1) of the proposed rule restricts aggregation of
small units to a group "not to exceed 250 mmBTU/hr". Novelis believes that this aggregation
cutoff is arbitrary and unnecessary for reporting purposes. In addition, the requirement makes no
distinction for fuel type, such as natural gas vs. coal, and the monitoring issues that differ by fuel
type. As proposed, this provision would require the installation of fuel monitoring equipment at
many natural gas-fired manufacturing facilities resulting in no improvement in GHG data
quality. Many affected industrial facilities that use natural gas for process combustion and
building heat use more than 250 mmBTU/hr. These facilities may have numerous (10, 20 or
385
-------
more) stationary combustion units of different types and sizes, but have only a single monitor
(gas meter) where the amount of natural gas is metered by the natural gas supplier or utility. The
proposed rule would require these facilities to somehow subdivide the natural gas combustion
units into groups that use less than 250 mmBTU/hr, and then install and maintain additional
(internal) gas meters for the sole purpose of GHG emissions reporting. As written, the rule
unreasonably complicates a process where existing information could be used without the
increased costs. Specifically, existing site-wide gas meters at industrial facilities are already
properly maintained by the utility as a point of commercial sale. In addition, the fuel content of
natural gas is very consistent, and the fuel combustion efficiency of natural gas-fired processes is
maintained for emission control purposes. Therefore, adding additional meters to create
subgroups of combustion units less than 250 mmBTU/hr adds no value at considerably increased
cost in capital, monitoring and recordkeeping. Novelis objects to this provision and recommends
that the final rule allow aggregation of small units up to any total mmBTU/hr usage as long as all
of the fuel used by the aggregated units is metered or measured at a single point while retaining
the ability to use Tier 1 or Tier 2 reporting. This still serves the EPA rule's objectives.
Response: For units that use Tiers 1, 2, and 3 to calculate C02 mass emissions, the cumulative
250 mmBtu/hr heat input capacity limit on the aggregation of units into a group has been
dropped. Rather, the 250 mmBtu/hr restriction applies only to the individual units in the group.
Therefore, for reporting purposes, individual units with maximum rated heat input capacities of
250 mmBtu/hr or less may be aggregated without limit into a single group, provided that the Tier
4 methodology is not required for any of the units, and all units in the group use the same tier for
any common fuel(s) that they combust. Units with maximum rated heat inputs greater than 250
mmBtu/hr must report as individual units, unless they burn the same type of fuel (oil or gas)
provided by a common pipe or supply line; in that case, the owner or operator may opt to use the
highest tier required for a grouped unit for the calculation method with the common pipe
reporting provisions in §98.36. Units using Tier 4 must report as individual units unless they
share a monitored common stack; in that case, the common stack reporting provisions of §98.36
may be used.
Commenter Name: Lorraine Krupa Gershman
Commenter Affiliation: American Chemistry Council (ACC)
Document Control Number: EPA-HQ-OAR-2008-0508-0423.2
Comment Excerpt Number: 63
Comment: Further, in §98.34(d)(l,) a facility might be purchasing different components from
different manufacturers, e.g. the dP cell manufacturer might differ from the orifice manufacturer.
It might, therefore, be difficult to follow the manufacturer's recommendations because different
manufacturers might have recommendations in conflict with each other. Also in §98.34(d)(1),
some meter warranties may be voided if an attempt is made to calibrate them. In such a
situation, EPA should allow for a facility to follow the manufacturer's recommendations or
specifications. Based on all of the above constraints and concerns, ACC recommends that in
§98.34(d)(1), EPA require meter calibration at the lesser of the manufacturer's recommendations
or annually or, alternatively, to calibrate on an alternate frequency determined to be appropriate
through operating experience for the meter or based on other engineering analyses. This will
address facilities whose flow measurement device manufacturers do not recommend periodic
calibration and will also address other concerns noted in the proposed frequency.
386
-------
Response: EPA believes that the structure of the final rule mirrors this suggestion to a large
extent. In §98.34 for on-going QA, the Agency requires either a biannual (i.e., once every two
years) recalibration or at the minimum frequency specified by the manufacturer. However for
orifice, nozzle, and venturi meters, the transmitters will be required to recalibrate in-situ at least
annually, with a PEI performed at least once every three years. For continuously operating units
and processes, the recalibratons and, if necessary, the PEIs, may be postponed until the next
scheduled maintenance outage.
Commenter Name: Paul R. Pike
Commenter Affiliation: Ameren Corporation
Document Control Number: EPA-HQ-OAR-2008-0508-0487.1
Comment Excerpt Number: 12
Comment: Under §98.36(b) and §98.46(a), EPA proposes to require unit level reporting of
various pieces of information for Subpart C combustion sources, and for ARP units. Although
most of the information specified in §98.36(b) is not burdensome to report, the data required
under (b)(5) would be for some units. Proposed §98.36(b)(5) would require the reporting of
calculated C02, CH4, and N20 data for each fuel type combusted at the unit. Units using
continuous monitoring methods, like CO2/O2 CEMS and volumetric flow monitors (to calculate
heat input) generally do not employ instrumentation to record when a different fuel is being
combusted. For example, a coal-fired unit that uses oil to startup would monitor CO2/O2 and
volumetric flow all the way through the startup process and past the point when coal enters the
boiler without any recordation of when the change in fuel took place. Similarly, some oil and
gas-fired units may switch between the two fuels, or even co-fire oil and gas, without recording
which fuel or fuels was responsible for the emissions and flow. For such units, it simply is not
possible to provide estimates of emissions by fuel type without addition of what might be
complicated, expensive, and otherwise unnecessary instrumentation. EPA should remove the
provision or limit its application to units that already have the instrumentation or other means to
make the calculation. If EPA retains the requirement, the Agency must describe why the
information is needed, estimate the costs of gathering this information, and provide sufficient
time for installation of equipment.
Response: EPA acknowledges the commenter's concerns, and has addressed this issue in the
final rule. Section 98.36 of the final rule states that, for Tier 4 units, the annual CO2 emissions
will be reported for all fuels combined, and that any biogenic CO2 emissions will also be
reported separately. It also states that CH4 and N2O emissions are to be reported for each type of
fuel combusted, calculated in accordance with §98.33. In §98.33, EPA has specified that
reporters using Tier 4 are to use the best available estimates of the annual heat input from each
type of fuel combusted in the unit during the reporting year, excluding fuel used only for startup
or ignition. This can be from CEMS data or engineering calculations. Using this data they are to
calculate CH4 and N2O emissions for each fuel type.
In revising the final version of the rule, EPA has also added to §98.36 to define data reporting
requirements for units subject to Part 75, which requires total emissions by unit, not by fuel.
EPA believes that these provisions in the final rule effectively address the concerns of the
commenter.
387
-------
Commenter Name: Rich Raiders
Commenter Affiliation: Arkema Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-0511.1
Comment Excerpt Number: 41
Comment: Subpart C also requires pipeline gas meter calibrations. Arkema is not familiar with
any current requirement for users to calibrate gas meters. Typically, the supplier manages gas
flow meter calibration, and the customers are typically unaware of the pipeline companies'
calibration procedures. EPA should allow reporters to rely on pipeline-certified natural gas flow
measurement without any requirement to calibrate flow meters used for supplier billing
purposes. Natural gas flow meters used in-process to determine local gas flows should only be
calibrated at manufacturer specified intervals, if at all. If a reporter elects to purchase and install
natural gas flow meters that are manufactured to operate for several years between calibrations,
EPA should not impose unnecessary calibration schedules for known reliable meters.
Response: EPA acknowledges the concerns of the commenters. Section 98.34 of the final rule
has been clarified to exempt fuel billing meters from the calibration requirement, "provided that
the supplier and the unit(s) combusting the fuel do not have any common owners and are not
owned by subsidiaries or affiliates of the same company."
Commenter Name: Lorraine Krupa Gershman
Commenter Affiliation: American Chemistry Council (ACC)
Document Control Number: EPA-HQ-OAR-2008-0508-0423.2
Comment Excerpt Number: 60
Comment: Sections 98.34(c) and 98.34(d)(3) require routine measurement of the HHV and
carbon content of fuels, respectively. The reporter should be allowed to use fuel specifications
that include, but are not limited to, regulatory requirements, data provided by fuel suppliers, and
specifications set by the reporter to determine HHV and carbon content. The frequency for
determining HHV or carbon content from data obtained from a fuel supplier should be the same
frequency for obtaining the data from the supplier. Also similar to other Clean Air Act rules, the
final rule should include an option to decrease the frequency of sampling to annually if several
consecutive measurements show minimum variation in the HHV or carbon contents.
Response: EPA acknowledges the commenter's concerns, and has revised its required sampling
and analysis methods. First, the mandatory monthly fuel sampling and analysis requirements for
traditional fossil fuels have been dropped from Tiers 2 and 3. Section 98.34 has been revised to
require that natural gas be sampled semiannually. For fuel oil and coal, a representative
sampling is required for each fuel lot, i.e., for each shipment or delivery. For other liquid fuels
and biogas, quarterly sampling is required. For other solid fuels, excluding municipal solid
waste, weekly composite sampling with monthly analysis is required. For other gaseous fuels,
the daily sampling requirement has been retained, but only for facilities with existing equipment
in place that is capable of providing the data. Otherwise, weekly sampling is required, which
may be postponed in favor of monthly sampling until 2011 if new equipment must be purchased
388
-------
or if existing equipment must be upgraded to meet the weekly sampling and analysis
requirements.
The final rule clarifies that fuel sampling and analysis data provided by the supplier may be used
in the emission calculations, and that fuel billing meters may be used to quantify fuel
consumption. To simplify the emission calculations in Tiers 2 and 3, averaging of HHV and
carbon content data is permitted if these data are obtained at least at the minimum frequency
specified in §98.34. If the results of fuel sampling are received monthly or more frequently, the
weighted annual average high heat value shall be calculated using Equation C-2b. If the results
of fuel sampling are received less frequently than monthly, then the annual average HHV shall
be calculated using the arithmetic average HHV for all valid samples for the year. However,
regardless of the sampling frequency, the owner or operator must use the results of all available
valid fuel analyses in the emissions calculations.
The Agency is not opposed to alternative approaches for sampling frequency options, such as
decreasing sampling in certain cases with consistently homogenous results as described by the
commenter. However, the commenter did not provide any supplementary information, proposed
rule language, or cost analysis to explain how this proposed methodology could be implemented.
In view of this, EPA has not incorporated the commenter's suggested approach into the final rule,
but is willing to consider it in a future rulemaking, if the necessary technical details of the
method are provided for Agency review.
Commenter Name: Lauren E. Freeman
Commenter Affiliation: Hunton & Williams LLP
Document Control Number: EPA-HQ-OAR-2008-0508-0493.1
Comment Excerpt Number: 25
Comment: Proposed §§98.44 - 98.46 are largely superfluous in that they simply repeat
requirements that are already set out either in Part 75 or in Subpart C. For example, if a source is
using CO2 data reported under Part 75 to report under this program, it is not necessary to
separately specify that those data must be quality assured under Part 75 or that the missing data
provisions of Part 75 must be followed. The CO2 data that were reported under Part 75 will be
either Part 75 quality-assured data or data estimated using Part 75 missing data procedures. It
also is not necessary to require in this rule that such units "continue to monitor and report" CO2
emissions under Part 75, as required under proposed §98.43, or to specify under this subpart the
meaning of terms, as stated in proposed §98.48. Repeating requirements that are already set out
in Part 75 or in Subpart A to Part 98 is unnecessary, confusing, and inappropriate.
Response: EPA has included rule language that may appear to be redundant in order to provide
clarity that requirements under Part 75 continue to apply to Part 98 reporters.
389
-------
Commenter Name: Sarah B. King
Commenter Affiliation: DuPont Company
Document Control Number: EPA-HQ-OAR-2008-0508-0604.1
Comment Excerpt Number: 27
Comment: Regarding §98.34(c)(1) and (d)(3), the composition of natural gas does not change
often enough to warrant monthly sampling. DuPont recommends annual analysis at most for
natural gas. End user sampling and testing of fuels should be deleted to reduce the excessive
burden of each facility needing to sample and analyze the fuel when it could be more efficiently
sampled and analyzed only once by the supplier instead. Additionally, the sampling frequency
should be yearly or whenever the supplier changes the source of the fuel such that the fuel
composition may be likely to change.
Response: EPA acknowledges the commenters' concerns regarding natural gas sampling costs,
and has revised the §98.34 as follows: for natural gas, semiannual sampling and analysis is
required.
Commenter Name: Sarah B. King
Commenter Affiliation: DuPont Company
Document Control Number: EPA-HQ-OAR-2008-0508-0604.1
Comment Excerpt Number: 28
Comment: Sections 98.34(c) and 98.34(d)(3) require routine measurement of the HHV and
carbon content of fuels, respectively. The reporter should be allowed to use data provided by
fuel suppliers to determine HHV and carbon content. Also similar to other Clean Air Act rules,
the rule should include an option to decrease the frequency of sampling to annually if several
consecutive measurements show minimum variation in the HHV or carbon contents. EPA
should specify that analysis is to be on an "As-Received" basis for solid fuels.
Response: EPA acknowledges the commenter's concerns, and has revised its required sampling
and analysis methods. First, the mandatory monthly fuel sampling and analysis requirements for
traditional fossil fuels have been dropped from Tiers 2 and 3. Section 98.34 has been revised to
require that natural gas be sampled semiannually. For fuel oil and coal, a representative
sampling is required for each fuel lot, i.e., for each shipment or delivery. For other liquid fuels
and biogas, quarterly sampling is required. For other solid fuels, excluding municipal solid
waste, weekly composite sampling with monthly analysis is required. For other gaseous fuels,
the daily sampling requirement has been retained, but only for facilities with existing equipment
in place that is capable of providing the data. Otherwise, weekly sampling is required, which
may be postponed in favor of monthly sampling until 2011 if new equipment must be purchased
or if existing equipment must be upgraded to meet the weekly sampling and analysis
requirements.
The final rule clarifies that fuel sampling and analysis data provided by the supplier may be used
in the emission calculations, and that fuel billing meters may be used to quantify fuel
consumption. To simplify the emission calculations in Tiers 2 and 3, averaging of HHV and
carbon content data is permitted if these data are obtained at least at the minimum frequency
390
-------
specified in §98.34. If the results of fuel sampling are received monthly or more frequently, the
weighted annual average high heat value shall be calculated using Equation C-2b. If the results
of fuel sampling are received less frequently than monthly, then the annual average HHV shall
be calculated using the arithmetic average HHV for all valid samples for the year. However,
regardless of the sampling frequency, the owner or operator must use the results of all available
valid fuel analyses in the emissions calculations.
Commenter Name: Sarah B. King
Commenter Affiliation: DuPont Company
Document Control Number: EPA-HQ-OAR-2008-0508-0604.1
Comment Excerpt Number: 29
Comment: Regarding §98.34(d)(3), combustion of gaseous fuels other than natural gas (e.g.,
refinery gas, or process gas) needs to use Tier 3 unless a CEMS is used for Tier 4. This
paragraph indicates (and Preamble p 16484 also stipulates) that daily sampling and analysis is
required to determine carbon content and molecular weight of the fuel. The Preamble notes that
"The daily fuel sampling requirement for units that combust "other" gaseous fuels would likely
not be overly burdensome, because the types of facilities that burn these fuels are likely to have
equipment (e.g., on-line gas chromatographs) to continuously monitor the fuels' characteristics in
order to optimize process operation." While this is the case for some particular offgas streams, it
is definitely not the case for all process gases, and those with monitoring might require
considerable cost to upgrade for this purpose. This requirement could impose a significant and
unjustified cost on some facilities that wouldn't otherwise be required to use CEMs. If such
sampling and analytical equipment is not installed, it should be acceptable to use typical
analytical or engineering data to determine the process gas composition. Additionally, if a
process gas stream contains less than 25% carbon by weight as demonstrated by engineering or
model analysis, that initial demonstrated value should be considered adequate for ongoing
emissions determinations. CO2 emissions resulting from such low-carbon gas streams are
generally not material as these streams are typically not large volume. Moreover, following the
de minimis concepts explained above, if the process gas stream does not contain significant
carbon content (< 10% by weight), there should be no need for any reporting for those process
gas streams providing documentation is retained supporting that position.
Response: See the response to excerpt 28 from the same letter, EPA-HQ-OAR-2008-0508-0604
(directly preceding).
Commenter Name: Sarah B. King
Commenter Affiliation: DuPont Company
Document Control Number: EPA-HQ-OAR-2008-0508-0604.1
Comment Excerpt Number: 30
Comment: In §98.34, EPA does not provide a specified recommended methodology for
measuring solid fuels, but rather relies on company records. Requiring measurement of the fuel
rate instead of allowing calculation would be especially burdensome and unnecessarily costly,
and would require the installation of weighing equipment which simply cannot be installed in
391
-------
some cases due to required equipment configurations. Some sites currently calculate the amount
of solid fuel combusted based on, for example in the case of a boiler, the amount of steam
generated and the boiler efficiency. For example, the Tier 2 methodology for MSW fired units
allows for use of boiler steam output and the maximum rated heat input to design steam output
ratio to determine heat input. A similar approach could also be used for other solid fuel fired
units. Similarly, in cases where byproduct fuels are fired or co-fired, the covered entity should
have latitude to utilize any methods appropriate for the unit that provide representative
determination of CO2 emissions. EPA should continue to allow such engineering calculations
for solid fuel flow rate. Providing flexibility in fuel consumption determination methodology
will decrease the cost of the reporting program with an insignificant impact on overall emissions
accounting accuracy. It is assumed that this is EPA's intention based on the reference to relying
on company records.
Response: See the response to excerpt 28 from the same letter, EPA-HQ-OAR-2008-0508-0604
(preceding).
Commenter Name: Ron Downey
Commenter Affiliation: LWB Refractories
Document Control Number: EPA-HQ-OAR-2008-0508-0719.1
Comment Excerpt Number: 33
Comment: Sampling Requirements for Tier 2 and Tier 3 Facilities: The Preamble, 74 Fed.
Reg. at 16,484, and Table 8 in the Technical Support Documentation indicate that 40 CFR Part
98.34(d)(3) requires a Tier 3 facility using solid fuel to sample weekly and composite weekly
sample results into a monthly carbon content value that is reported. This is consistent with the
sampling requirements for Tier 2 facilities. See 40 C.F.R. 98.34(c)(2). However, 40 C.F.R. 98.7
incorporates by reference several ASTM standards, including ASTM D2234 (Standard Practice
for Collection of a Gross Sample of Coal). To the extent that the specific sampling procedures in
40 CFR Part 98.33(a)(3) conflict with the general reference to ASTM D2234, 40 C.F.R. Part
98.33(a)(3) should control. The Proposed Rule should clearly state that the incorporation by
reference of ASTM D2234 at 40 C.F.R. 98.7 does not supersede the sampling frequency
requirements in 40 C.F.R. 98.33(a)(3). Adherence to the sampling requirements in 40 C.F.R.
98.33(a)(3) will provide consistent sampling among Tier 3 facilities. ASTM D2234, in contrast,
allows sources to determine their own sampling frequency.
Response: EPA has revised §98.34 to clarify that only the methods listed in that section may be
used for fuel sampling and analysis for Tiers 2 and 3, regardless of any other methods that are
incorporated in §98.7. ASTM D2234, though incorporated by reference at §98.7, is not listed in
§98.34, and therefore may not be used for the purposes of Subpart C.
Commenter Name: Ron Downey
Commenter Affiliation: LWB Refractories
Document Control Number: EPA-HQ-OAR-2008-0508-0719.1
Comment Excerpt Number: 34
Comment: Determining High Heat Values: The Preamble provides that Tier 1 and Tier 2
facilities can rely on fuel supply vendors to supply the high heat value for the fuel combusted.
392
-------
Preamble at V.C.3a. 40 C.F.R. 98.33(a)(1) and (2) should be revised to reflect that high heat
value measurements for fuel combusted in a Tier 1 and Tier 2 facilities may be obtained from the
fuel supplier.
Response: The final rule clarifies that fuel sampling and analysis data provided by the supplier
may be used in the emission calculations, and that fuel billing meters may be used to quantify
fuel consumption. To simplify the emission calculations in Tiers 2 and 3, averaging of HHV and
carbon content data is permitted if these data are obtained at least at the minimum frequency
specified in §98.34. If the results of fuel sampling are received monthly or more frequently, the
weighted annual average high heat value shall be calculated using Equation C-2b. If the results
of fuel sampling are received less frequently than monthly, then the annual average HHV shall
be calculated using the arithmetic average HHV for all valid samples for the year. However,
regardless of the sampling frequency, the owner or operator must use the results of all available
valid fuel analyses in the emissions calculations.
Commenter Name: See Table 5
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0480.1
Comment Excerpt Number: 37
Comment: Accurate fuel measurement is inherent to natural gas transmission and storage
operations, and expertise within this industry for natural gas fuel rate measurement is
unsurpassed. For fuel metering, §98.34(d)(1) requires operators to follow methods in §98.7 or
vendor defined calibration procedures. Within the natural gas industry, flow measurement
quality control and quality assurance procedures have been developed and refined over years,
and common practices are in place to ensure metering QA/QC. §98.34(d)(1) should be revised
to provide the flexibility to use accepted operator-defined practices for fuel flow meter
calibration and other QA/QC measures. This ensures that natural gas operators can continue to
use accepted methodologies to ensure accurate fuel measurement.
Response: EPA believes that the language in §98.34 is clear, offers substantial flexibility, and
does not require the revision suggested by the commenter. EPA defines acceptable test methods
as those listed in §98.7 or the calibration procedures specified by the flow meter manufacturer.
Commenter Name: Robert Rouse
Commenter Affiliation: The Dow Chemical Company
Document Control Number: EPA-HQ-OAR-2008-0508-0533.1
Comment Excerpt Number: 24
Comment: EPA Should Revise the Requirements for Fuel Sampling for Natural Gas.
Referencing 98.34(c)(1) and (d)(3), the composition of natural gas does not change often enough
to warrant monthly sampling. Dow suggests that EPA consider semi-annual sampling at most
for natural gas. Requiring these fuels to be sampled twice per year would align with many
custom fuel sampling schedules for determining the sulfur content of natural gas that are driven
by other EPA regulations such as NSPS Subpart GG. In addition, Dow suggests that EPA
393
-------
consider limiting the source sampling and testing of fuels, including pipeline natural gas
supplies, to reduce the excessive burden of each facility needing to sample and analyze the fuel
when it could be more efficiently sampled and analyzed by the supplier instead. The sampling
frequency should be semi-annual or whenever the supplier changes the source of the fuel such
that the fuel composition may be likely to change. These fuels will not change so much in
composition from month to month. Therefore, the monthly sampling requirement is overly
burdensome, and reducing the frequency will not impact the total GHG emissions inventory.
Dow Suggests that EPA Allow the Use of Fuel Supplier Information for Tier 2 or 3
Methodologies. EPA requested comment on integrating fuel supplier requirement for HHVs and
carbon content for Tier 1 and Tier 2 methodologies. Dow comments that information provided
by the fuel supplier should be allowed to be used in Tier 2 and 3 methodologies. This method of
allowing the fuel supplier to provide this information instead of the fuel users eliminates
unnecessary duplication of analysis of the same fuel by multiple users. For example, one fuel
supplier might supply dozens or even more units within an industrial area, and requiring the fuel
supplier to provide the data would reduce the number of required analyses correspondingly. In
addition, when making this change, EPA should then alter the requirements in 98.34(c) and (d)
such that operators of stationary combustion devices do not need to obtain fuel analytical data
when it is provided by the fuel supplier. Dow Suggests Revisions to the Requirements for Daily
Sampling of Process Gas to Determine the Carbon Content. In 98.34(d)(3), facilities combusting
process gas should be provided with an option to perform a statistical analysis to determine a
sample and analytical frequency that is less often than daily based on the potential for variations
in process gas composition. Requiring daily sampling for all process fuels may be unnecessary
and is burdensome to the plant sites. At a minimum, facilities should be allowed the option of
initially sampling monthly and then using a different frequency if warranted by a statistical
analysis. In addition, sampling systems may not currently be present on all process gas/fuel
lines. EPA's final rule should allow additional time to install all required sample taps or
locations that are required to collect the samples for carbon analysis, molecular weight
determinations, and higher heating value. In some cases, it may be necessary to take a
combustion unit out of service in order to make these installations. Dow comments that
owner/operators should have until January 1, 2011 to make these installations, and that the rule
should have a mechanism for the owner/operator to request additional time on a case-by-case
basis, if needed. GHG emissions can still be determined to a high degree of accuracy by using
process knowledge and engineering calculations for the reporting year 2010 in these cases. EPA
Should Adjust the Requirements for Periodic and Initial Calibration of Gas Flow Meters. In
98.34(d)(1), some flow meters may not be calibrated without shutting down the process. For
example, in some cases, an orifice plate must be pulled out of the line to do a complete
calibration. This might be part of manufacturer's recommendations as a part of calibration
recommendations. It would not be practical to perform this yearly because equipment may not
be out of service on a frequency of more than one time in every several years. The annual
calibration should be limited to no more than would be required by Part 75 (electronic
transmitter calibration) less the visual inspection every three years. In addition, for the reasons
cited above regarding possible unit shutdown for a full calibration per manufacturer's
recommendations, it may not be practical or possible to complete all required calibrations
between now and January 1, 2010. Dow recommends that EPA allow owners/operators until the
next scheduled shutdown for the initial calibration, if it requires a process unit shutdown.
Therefore, Dow recommends that in 98.34(d)(1), EPA require meter calibration at the lesser
frequency of the manufacturer's recommendations or annually rather than the greater of or,
alternatively, to calibrate on an alternate frequency determined to be appropriate through
operating experience for the meter or based on other engineering analyses. This will address
394
-------
facilities whose flow measurement device manufacturers do not recommend periodic calibration
and will also address other concerns noted in the proposed frequency. EPA Should Adjust the
Requirements for Measuring the Carbon Content of Solid Fuel. EPA does not provide a
specified recommended methodology for measuring solid fuels in 98.34. Requiring
measurement of the fuel rate instead of allowing calculation would be especially burdensome
and unnecessarily costly, and would require the installation of weighing equipment. Some sites
currently calculate the amount of solid fuel combusted based on, for example in the case of a
boiler, the amount of steam generated each month and the boiler efficiency. EPA should
continue to allow such engineering calculations for solid fuel flow rate.
Response: EPA acknowledges the commenter's concerns, and has revised its required sampling
and analysis methods. First, the mandatory monthly fuel sampling and analysis requirements for
traditional fossil fuels have been dropped from Tiers 2 and 3. Section 98.34 has been revised to
require that natural gas be sampled semiannually. For fuel oil and coal, a representative
sampling is required for each fuel lot, i.e., for each shipment or delivery. For other liquid fuels
and biogas, quarterly sampling is required. For other solid fuels, excluding municipal solid
waste, weekly composite sampling with monthly analysis is required. For other gaseous fuels,
the daily sampling requirement has been retained, but only for facilities with existing equipment
in place that is capable of providing the data. Otherwise, weekly sampling is required, which
may be postponed in favor of monthly sampling until 2011 if new equipment must be purchased
or if existing equipment must be upgraded to meet the weekly sampling and analysis
requirements.
The final rule clarifies that fuel sampling and analysis data provided by the supplier may be used
in the emission calculations, and that fuel billing meters may be used to quantify fuel
consumption. To simplify the emission calculations in Tiers 2 and 3, averaging of HHV and
carbon content data is permitted if these data are obtained at least at the minimum frequency
specified in §98.34. If the results of fuel sampling are received monthly or more frequently, the
weighted annual average high heat value shall be calculated using Equation C-2b. If the results
of fuel sampling are received less frequently than monthly, then the annual average HHV shall
be calculated using the arithmetic average HHV for all valid samples for the year. However,
regardless of the sampling frequency, the owner or operator must use the results of all available
valid fuel analyses in the emissions calculations.
Section 98.34 of the final rule clarifies that for units and processes that operate continuously with
infrequent outages and use an orifice, nozzle, or venturi meter, the owner or operator may
postpone the initial calibration or PEI (as applicable) until the next scheduled maintenance
outage, and may similarly postpone the subsequent recalibrations and PEIs. In §98.34 for on-
going QA, the Agency requires either a biannual (i.e., once every two years) recalibration or at
the minimum frequency specified by the manufacturer. However for orifice, nozzle, and venturi
meters, the transmitters will be required to recalibrate in-situ at least annually, with a PEI
performed at least once every three years.
Also, EPA has extended the use of steam production and combustion unit efficiency to calculate
CO2 emissions to other solid fuels in addition to municipal solid waste. These parameters may
also be used to quantify the amount of biomass combusted in a unit.
395
-------
Commenter Name: See Table 5
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0480.1
Comment Excerpt Number: 39
Comment: Gas measurement and analysis methods continue to be revised and refined, and it is
likely that additional consensus methods are available but have not been specifically identified to
date. The process for accepting alternative methods into a final rule can be burdensome, time
consuming, and cumbersome for operators and EPA. Thus, a streamlined approach is warranted
to accept other consensus standards. To address ongoing improvements and evolution in gas
measurement methods, INGAA recommends that §98.34 add a provision that indicates that
consensus methods not listed in §98.7 but authored by organizations with methods already listed
in §98.7 be allowed for fuel flow, fuel carbon, and heating value analysis. In addition, EPA
should indicate that other methods accepted by the Administrator are also acceptable. To
facilitate approval under this authority, EPA should devise an approach (i.e., expert review
group) for expedited review and approval of additional methods that become available or are
identified.
Response: EPA disagrees with commenter's request to allow sources to determine the best
measurements to use, in order to ensure that consistent data is reported under this rule. EPA has,
however, expanded the use of the four tier system to be more significantly more flexible. See
§98.33. EPA does not believe that it is appropriate to include consensus methods not yet
reviewed and approved by EPA in this rule but will endeavor to expedite review of additional
methods which become available.
Commenter Name: Patrick J. Nugent
Commenter Affiliation: Texas Pipeline Association (TPA)
Document Control Number: EPA-HQ-OAR-2008-0508-0460.1
Comment Excerpt Number: 24
Comment: The monthly carbon content determination requirement in proposed §98.3-4(03)
should be deleted. Proposed §98.34(dX3) would provide that the carbon content of certain fuels
be determined monthly regardless of whether new fuel has been added to the tank. That
requirement should be eliminated or modified to provide that regulated entities should not be
required to resample tanks on a monthly basis if no additional fuel was added since the last
sample. The carbon content of the fuel should not change if additional fuel has not been added.
Response: Section 98.34 has been revised to require that natural gas be sampled semiannually
and to require a representative sampling for each fuel lot (i.e., for each shipment or delivery) for
fuel oil and coal. For other liquid fuels and biogas, quarterly sampling is required. For other
solid fuels, excluding municipal solid waste, weekly composite sampling with monthly analysis
is required. For other gaseous fuels, the daily sampling requirement has been retained, but only
for facilities with existing equipment in place that is capable of providing the data. Otherwise,
weekly sampling is required, which may be postponed in favor of monthly sampling until 2011 if
new equipment must be purchased or if existing equipment must be upgraded to meet the weekly
sampling and analysis requirements.
396
-------
The final rule clarifies that fuel sampling and analysis data provided by the supplier may be used
in the emission calculations, and that fuel billing meters may be used to quantify fuel
consumption. To simplify the emission calculations in Tiers 2 and 3, averaging of HHV and
carbon content data is permitted if these data are obtained at least at the minimum frequency
specified in §98.34, but less frequently than monthly (see Equation C-2b). However, regardless
of the sampling frequency, the owner or operator must use the results of all available valid fuel
analyses in the emissions calculations.
Commenter Name: Gregory A. Wilkins
Commenter Affiliation: Marathon Oil Corporation
Document Control Number: EPA-HQ-OAR-2008-0508-0712.1
Comment Excerpt Number: 49
Comment: Marathon opposes the current quality assurance and calibration requirements for
flow meters used to obtain daily readings of fuel gas. If the quality control failed when
calibrating a flow meter, it may require an inspection of the orifice plate of the meter. An
inspection (and hence removal) of this plate could require part of a facility to be shut down.
Marathon proposes language stating that due to any malfunctions, quality, or calibration issues,
inspections, replacements, and calibrations of flow meters that cannot he done on-line can be
delayed until the next scheduled shut down. Currently EPA states that annual calibration or
manufacturer specified calibration is required. This may not be feasible for the reasons stated
above. Additionally, Marathon proposes that if a critical meter malfunctions and cannot be
repaired while on-line, other meters or engineering estimates should be allowed in this situation
as long as is necessary (until the meter is replaced or repaired) as this rule isn't intended to affect
operations. There should be no mandated time for repair or replacement of this equipment as
there are many safety concerns with making repairs while equipment is running. Additionally,
shutting down and starting up equipment for compliance with this rule would actually create
more GHG emissions. The rule should state that the equipment should be replaced or repaired at
the next planned shut-down.
Response: EPA acknowledges the concerns of the commenters. Section 98.34 of the final rule
clarifies that for units and processes with orifice, nozzle, or venturi meters that operate
continuously with infrequent outages, the owner or operator may postpone the initial calibration
or PEI (as applicable) until the next scheduled maintenance outage, and may similarly postpone
the subsequent recalibrations and PEIs.
Commenter Name: Gregory A. Wilkins
Commenter Affiliation: Marathon Oil Corporation
Document Control Number: EPA-HQ-OAR-2008-0508-0712.1
Comment Excerpt Number: 52
Comment: Marathon supports the use of common pipe sampling if this final rule does require
direct sampling of fuel gas for Tier 3. The common pipe method allows a facility to combine
emission estimates for multiple units as a common pipe configuration if a common fuel source
397
-------
fed those multiple units and was metered and measured at the common source. This will
simplify emission estimates and monitoring and metering requirements for many facilities. By
using a common pipe for sampling, our facilities can reduce samples taken and still maintain
accurate estimations. Marathon interprets this rule to also mean that while a common sample
may be taken at the fuel drum, flow meters at individual combustion units sharing a common
source can be used to determine individual flow and hence emissions. Marathon requests
clarification be given in the regulatory language to address this as an option.
Response: EPA has revised §98.36 to clarify that emissions may be combined for units served
by the common supply line, provided that the total amount of fuel combusted by the units is
accurately measured at the common pipe or supply line using a calibrated fuel flow meter. In
addition, EPA has significantly revised §98.34, simplifying sampling and analysis requirements.
Commenter Name: Karen St. John
Commenter Affiliation: BP America Inc. (BP)
Document Control Number: EPA-HQ-OAR-2008-0508-0631.1
Comment Excerpt Number: 61
Comment: Where the Section 98.34 Tier 3 Calculation Methodology is used, EPA has required
reporters determine the carbon content of natural gas, biogas, liquid fuels, and solids fuels
monthly and of other gaseous fuels such as refinery gas and process gas on a daily basis. For
many refinery operations, the carbon content of gas streams does not vary significantly enough
to warrant daily determination. EPA should revise the requirement in Section 98.34(d)(3) to
specify the reporter must determine the content of gaseous fuels monthly. Daily sampling is
excessive for fuels that are fairly stable in composition. The natural gas factor in Table C-l
should be used, or where the gas stream does fluctuate with operational changes, allow the
reporter to determine a sampling frequency that is consistent with the variability of the stream.
Response: In preparation of the final rule, EPA has significantly revised §98.34 concerning
sampling and analysis requirements. Section 98.34 has been revised to require that natural gas
be sampled semiannually and biogas be sampled quarterly. For other gaseous fuels, the daily
sampling requirement has been retained, but only for facilities with existing equipment in place
that is capable of providing the data. Otherwise, weekly sampling is required, which may be
postponed in favor of monthly sampling until 2011 if new equipment must be purchased or if
existing equipment must be upgraded to meet the weekly sampling and analysis requirements.
Commenter Name: Karen St. John
Commenter Affiliation: BP America Inc. (BP)
Document Control Number: EPA-HQ-OAR-2008-0508-0631.1
Comment Excerpt Number: 62
Comment: Calibrated flow meters are not addressed for a Tier 1 or Tier 2 calculation approach.
If using Tiers 1 or 2, rated horsepower/operating hours etc should be acceptable as legitimate
"company records to quantify fuel consumption." Note that the equation definitions for Tiers 1
and 2 indicate fuel flow, but do not use the term "company records" and hence, the inconsistency
is vague and confusing. BP is assuming that Tiers 1 and 2 do not require fuel meters, and that
398
-------
the use of company records includes estimation methods as outlined in the API Compendium,
based on operating hours and ratings. Section 98.34(c) and section 98.34(d)(3) require routine
measurement of the higher heat value (HHV) and carbon content of fuels, respectively. BP
requests that EPA allow the use of HHVs obtained from the fuel provider. BP further requests
that EPA include an option to decrease the frequency of sampling to annually if several
consecutive measurements show minimum variation in the HHV or carbon contents.
Response: EPA acknowledges the commenters' concerns, and has defined the term "company
records" in §98.6 of the final rule. EPA believes that the revised definition provides appropriate
guidance as to what records a facility may use to determine fuel consumption.
The final rule clarifies that fuel sampling and analysis data provided by the supplier may be used
in the emission calculations, and that fuel billing meters may be used to quantify fuel
consumption. To simplify the emission calculations in Tiers 2 and 3, averaging of HHV and
carbon content data is permitted if these data are obtained at least at the minimum frequency
specified in §98.34. If the results of fuel sampling are received monthly or more frequently, the
weighted annual average high heat value shall be calculated using Equation C-2b. If the results
of fuel sampling are received less frequently than monthly, then the annual average HHV shall
be calculated using the arithmetic average HHV for all valid samples for the year. However,
regardless of the sampling frequency, the owner or operator must use the results of all available
valid fuel analyses in the emissions calculations.
Commenter Name: Karen St. John
Commenter Affiliation: BP America Inc. (BP)
Document Control Number: EPA-HQ-OAR-2008-0508-0631.1
Comment Excerpt Number: 67
Comment: Section 98.34(d)(1) Tier 3 Calculation Methodology require fuel flow meters be
recalibrated annually or at the minimum frequency specified by the manufacturer. Recalibration
and/or reverification should not be required on an arbitrary frequency (i.e. annually), but based
on manufacturer recommendations or an alternate frequency determined to be appropriate
through operating experience for the meter and good manufacturing practices. BP suggests the
following alternative text for Section 98.34(d): (1) All oil and gas flow meters (except for gas
billing meters) shall be calibrated or verified on a documented schedule consistent with good
industry practice, using an applicable industry standard method or the calibration procedures
specified by the flow meter manufacturer or developed and documented by the facility for the
device. Fuel flow meters shall be recalibrated or reverified either annually or following good
manufacturing practice. (2) Oil tank drop measurements (if applicable) shall be performed
according to one of the methods developed by a consensus standards organization. (3) The
carbon content of the fuels listed in paragraphs (c)(1) and (2) of this section shall be determined
monthly. For other gaseous fuels (e.g., refinery gas, or process gas), monthly sampling and
analysis is required to determine the carbon content and molecular weight of the fuel. If a
specific gravity or density analyzer is used to measure the properties of the gas, a correlation
with the carbon content must be demonstrated by periodic sampling. An applicable method
listed in Sec. 98.7 shall be used to determine the carbon content and (if applicable) molecular
weight of the fuel.
399
-------
Response: Section 98.34 has been revised to require facilities to retain the daily sampling
requirement for other gaseous fuels, but only for facilities with existing equipment in place that
is capable of providing the data. Otherwise, weekly sampling is required, which may be
postponed in favor of monthly sampling until 2011 if new equipment must be purchased or if
existing equipment must be upgraded to meet the weekly sampling and analysis requirements.
The more frequent sampling for process gas is due to its variability.
EPA believes that the language in §98.34 is clear, offers substantial flexibility, and does not
require the revision suggested by the commenter.
EPA defines acceptable test methods as those listed in §98.7 or the calibration procedures
specified by the flow meter manufacturer.
Commenter Name: See Table 6
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0679.1
Comment Excerpt Number: 107
Comment: §98.34. Calibrated flow meters are not addressed for a Tier 1 or Tier 2 calculation
approach. If using Tiers 1 or 2, rated horsepower/operating hours etc should be acceptable as
legitimate "company records to quantify fuel consumption." Note, equation definitions for Tiers
1 and 2 indicates fuel flow, but do not use the term "company records." The inconsistency is
vague and confusing. API is assuming that Tiers 1 and 2 do not require fuel meters, and that the
use of company records includes estimation methods as outlined in the Compendium, based on
operating hours and ratings.
Response: EPA acknowledges the commenters' concerns, and has defined the term "company
records" in §98.6 of the final rule. EPA believes that the revised definition provides appropriate
guidance as to what records a facility may use to determine fuel consumption.
Commenter Name: See Table 6
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0679.1
Comment Excerpt Number: 108
Comment: §98.34(c) and §98.34(d)(3) require routine measurement of the higher heat value
(HHV) and carbon content of fuels, respectively. The reporter should be allowed to use fuel
specifications that include, but are not limited to, regulatory requirements, data provided by fuel
suppliers, and specifications set by the reporter to determine HHV and carbon content. The
frequency for determining HHV or carbon content from data obtained from a fuel supplier
should be the same frequency for obtaining the data from the supplier. Also, similar to other
CAA rules, the rule should include an option to decrease the frequency of sampling to annually if
several consecutive measurements show minimum variation in the HHV or carbon contents.
400
-------
Response: The final rule clarifies that fuel sampling and analysis data provided by the supplier
may be used in the emission calculations, and that fuel billing meters may be used to quantify
fuel consumption. To simplify the emission calculations in Tiers 2 and 3, averaging of HHV and
carbon content data is permitted if these data are obtained at least at the minimum frequency
specified in §98.34. If the results of fuel sampling are received monthly or more frequently, the
weighted annual average high heat value shall be calculated using Equation C-2b. If the results
of fuel sampling are received less frequently than monthly, then the annual average HHV shall
be calculated using the arithmetic average HHV for all valid samples for the year. However,
regardless of the sampling frequency, the owner or operator must use the results of all available
valid fuel analyses in the emissions calculations.
Commenter Name: See Table 6
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0679.1
Comment Excerpt Number: 109
Comment: §98.34. Where monthly fuel analyses are required, characterizations performed by
the fuel supplier should be acceptable. It is noted in the Preamble (p. 16484) that "EPA
considered allowing affected facilities to rely exclusively on the results of fuel sampling and
analysis provided by fuel suppliers, rather than performing periodic on-site sampling for all
variables [but EPA] decided not to propose this because in most instances, only the fuel heating
value, not the carbon content, is routinely provided by fuel suppliers." If a fuel supplier provides
carbon content, this data should be permitted in Tier 3 calculations. Note that the implication of
this finding is not limited to subpart C, but has implications for other subparts (P, Y, etc.)
Allowing a facility to substitute carbon contents specified by the fuel supplier will assist in
reducing the overall reporting burden. API suggests one annual value from the supplier should
be acceptable as the carbon content of these fuels is very stable.
Response: The final rule clarifies that fuel sampling and analysis data provided by the supplier
may be used in the emission calculations, and that fuel billing meters may be used to quantify
fuel consumption. To simplify the emission calculations in Tiers 2 and 3, averaging of HHV and
carbon content data is permitted if these data are obtained at least at the minimum frequency
specified in §98.34. If the results of fuel sampling are received monthly or more frequently, the
weighted annual average high heat value shall be calculated using Equation C-2b. If the results
of fuel sampling are received less frequently than monthly, then the annual average HHV shall
be calculated using the arithmetic average HHV for all valid samples for the year. However,
regardless of the sampling frequency, the owner or operator must use the results of all available
valid fuel analyses in the emissions calculations.
401
-------
Commenter Name: See Table 6
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0679.1
Comment Excerpt Number: 110
Comment: §98.34(d)(1). The statement "All oil and gas flow meters" should be revised to "All
liquid and gas flow meters".
Response: EPA has revised the language in §98.34 of the final rule to read as follows: "Each
oil and gas flow meter that provides fuel usage data for the GHG emissions reported under this
part..." While this does not explicitly specify liquid flow meters, the Agency believes the
provisions for liquid flow meters are implied.
Commenter Name: See Table 6
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0679.1
Comment Excerpt Number: 111
Comment: §98.34(d)(3). Where the Tier 3 Calculation Methodology is used, reporters are
required to determine the carbon content of natural gas, biogas, liquid fuels, and solids fuels
monthly and of other gaseous fuels such as refinery gas and process gas on a daily basis. For
many refinery and natural gas operations, the carbon content of gas streams does not vary
significantly enough to warrant daily determination. EPA acknowledges in the definition of
natural gas provided in §98.6 that the composition of fuel gas and process gas are similar to
natural gas. Thus, EPA should revise the requirement in §98.34(d)(3) to specify that the reporter
must determine the content of gaseous fuels monthly. Daily sampling is excessive for fuels that
are fairly stable in composition. API recommends the use of the natural gas factor in Table C-l
or where the gas stream does fluctuate with operational changes, to determine a sampling
frequency that is consistent with the variability of the stream. In addition, engineering analysis
should be allowed to estimate carbon content instead of sampling for streams where there are
safety concerns such as process gases that are maintained at high temperature to avoid liquid
accumulation. The oil and gas flow meters used for this category have been installed and are
operated following a wide variety of procedures. The reporter should maintain them in an
appropriate manner, but specifying the exact appropriate methods would be very difficult for
EPA. API recommends that reporters be allowed to determine the best methods and necessary
frequencies for calibration and/or verifying flow measurement devices. API offers the following
revised language for §98.34(d) [Page 16636]: Sec. 98.34 Monitoring and QA/QC requirements,
(d) For the Tier 3 Calculation Methodology: (1) All oil and gas flow meters (except for gas
billing meters) shall be calibrated or verified on a documented schedule consistent with good
industry practice, using an applicable industry standard method or the calibration procedures
specified by the flow meter manufacturer or developed and documented by the facility for the
device. Fuel flow meters shall be recalibrated/reverified either annually or following good
industry practice. (2) Oil tank drop measurements (if applicable) shall be performed according
to one of the methods developed by a consensus standards organization. (3) The carbon content
of the fuels listed in paragraphs (c)(1) and (2) of this section shall be determined monthly. For
other gaseous fuels (e.g., refinery gas, or process gas), monthly sampling and analysis is required
402
-------
to determine the carbon content and molecular weight of the fuel. If a specific gravity or density
analyzer is used to measure the properties of the gas, a correlation with the carbon content must
be demonstrated by periodic sampling. An applicable method listed in Sec. 98.7 shall be used to
determine the carbon content and (if applicable) molecular weight of the fuel.
Response: Section 98.34 has been revised to require facilities to retain the daily sampling
requirement, but only for facilities with existing equipment in place that is capable of providing
the data. Otherwise, weekly sampling is required, which may be postponed in favor of monthly
sampling until 2011 if new equipment must be purchased or if existing equipment must be
upgraded to meet the weekly sampling and analysis requirements.
EPA believes that the methods, derived from §98.7 and listed in §98.34(d) of the final rule,
provide operators adequate flexibility for best practices concerning calibration and/or verifying
flow measurement devices. Operators may also use the calibration procedures specified by the
flow meter manufacturer. In the case of oil tank drop measurements, those shall be performed
according to methods listed in §98.34.
The Agency is not opposed to alternative approaches for estimating carbon contents of fuels,
such as with appropriate engineering analysis as described by the commenter. However, the
commenter did not provide any supplementary information, proposed rule language, or cost
analysis to explain how this proposed methodology could be implemented. In view of this, EPA
has not incorporated the commenter's suggested approach into the final rule, but is willing to
consider it in a future rulemaking, if the necessary technical details of the method are provided
for Agency review.
Commenter Name: See Table 5
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0480.1
Comment Excerpt Number: 38
Comment: INGAA recommends including additional fuel rate measurement methods and
adding a streamlined approach for accepting additional methods. Proposed Section §98.7
includes a long list of accepted consensus method for measurement of fuel rate, gas quality
(carbon content), fuel heating value, etc. INGAA has identified additional methods that should
be included. In addition, as evident by the long list of methods already identified, there are many
accepted methods for measuring fuel rate, heating value, etc. and method refinements and
advances continue. Because of the breadth of coverage of the Proposed Rule, there needs to be a
streamlined approach for accepting additional methods to address Subpart C measurement
requirements for fuel flow, fuel carbon analysis, and heating value. Many of the ASTM
standards referenced in §98.7 are not generally recognized as measurement standards for natural
gas sector operations. To date, INGAA has identified the following additional methods that
should be added to §98.7: AGA Report No. 3: Orifice Metering of Natural Gas Part 1: General
Equations & Uncertainty Guidelines (1990). AGA Report No. 3: Orifice Metering of Natural
Gas Part 3: Natural Gas Applications (1992). AGA Report No. 3: Orifice Metering of Natural
Gas Part 4: Background, Development Implementation Procedure (1992). AGA Report No. 5:
Natural Gas Energy Measurement. AGA Report No. 7: Measurement of Natural Gas by
Turbine Meter (2006). AGA Report No. 8: Compressibility Factor of Natural Gas and Related
403
-------
Hydrocarbon Gases (1994) AGA Report No. 9: Measurement of Gas by Multipath Ultrasonic
Meters (2007) AGA Report No. 10: Speed of Sound in Natural Gas and Other Related
Hydrocarbon Gases AGA Report No. 11: Measurement of Natural Gas by Coriolis Meter (2003)
ANSI B 109.3: Rotary-Type Gas Displacement Meters (2000) GPA 21 45-09: Table of Physical
Properties for Hydrocarbons and Other Compounds of Interest to the Natural Gas Industry. GPA
21 72-09: Calculation of Gross Heating Value, Relative Density, Compressibility and
Theoretical Hydrocarbon Liquid Content for Natural Gas Mixtures for Custody Transfer GPA
2261-00: Analysis of Natural Gas and Similar Gaseous Mixtures by Gas Chromatography API
21.1: Manual of Petroleum Measurement Standards Chapter 21 - Flow Measurement Using
Electronic Metering Systems Section 1 - Electronic Gas Measurement.
Response: EPA acknowledges the commenter's concerns, and has significantly revised §98.34
concerning fuel sampling and analysis. In addition, EPA has revised §98.34(c)(2)(i) to require
semiannual sampling and analysis for natural gas. The Agency believes these changes should
alleviate some of the commenter's concerns.
Commenter Name: Sean M, O'Keefe
Commenter Affiliation: Hawaiian Commercial and Sugar Company (HC&S)
Document Control Number: EPA-HQ-OAR-2008-0508-1138.1
Comment Excerpt Number: 11
Comment: EPA requests comment on ways to ensure that the feed rate of solid fuel to a
combustion device is accurately measured. Typically, sugar mill boilers do not employ weighing
equipment or other metering devices to directly determine the feed rate of sugarcane bagasse into
the boiler; instead, a variety of methods may be used to estimate the quantity of bagasse
combusted in a particular unit each year. These methods may not lend themselves to producing
scientifically-based estimates of accuracy. In Hawaii, the total tonnage of bagasse produced by a
sugar mill is determined on an ongoing basis and annually based upon the amount of cane
processed; generally, all of the bagasse is assumed to have been burned for fuel by the end of the
grinding season with the exception of a small percentage that is used for filter cake. For facilities
with multiple boilers, facility-wide bagasse consumption is apportioned to individual boilers
based upon boiler operating data (e.g., steam production or bagasse feeder operation). Such
methods have been accepted as sufficiently accurate for determining and reporting annual
emissions of criteria pollutants, and should therefore also be acceptable for the purposes of
estimating annual GHG emissions. Moreover, because GHG emissions are estimated based upon
fuel-specific factors rather than on boiler-specific factors (unlike criteria pollutant emission
factors which may vary considerably depending upon the particular unit in which a fuel is
burned), obtaining an accurate estimate of the total amount of fuel burned at a facility is
sufficient to determine the facility's GHG emissions; it is not necessary to know precisely how
much of that fuel was burned in individual units. EPA should recognize that for many industries
available means of measuring solid fuel consumption, particularly for biomass fuels combusted
as part of an integrated production process, while limited, are adequate to provide reasonably
accurate estimates of annual GHG emissions. EPA should not unnecessarily restrict a facility's
ability to continue to utilize existing methods of monitoring fuel consumption.
Response: EPA acknowledges the commenter's concerns, and has significantly revised §98.34
concerning fuel sampling and analysis. In particular, the revised rule allows "company records"
404
-------
as defined in §98.6 to be used to quantify fuel consumption. In addition, EPA has extended the
use of steam production and combustion unit efficiency to calculate CO2 emissions to other solid
fuels in addition to municipal solid waste. These parameters may also be used to quantify the
amount of biomass combusted in a unit.
Commenter Name: See Table 6
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0679.1
Comment Excerpt Number: 112
Comment: §98.34(d)(1) and (3) (Page 16636): The continuous monitoring of flow rate and
daily sampling for carbon content proposed in §98.34(d)(1) and (3) for process gases assumes
the vents are continuous. Some process gas vents, however, are intermittent or are only
generated during emergency situation. Quantification of such process gases should be handled
under a de minimis threshold or calculated using engineering analysis.
Response: Although the Agency does not agree that there should be a de minimis emissions
exclusion, EPA has expanded the list of exempted source categories in §98.30 to include flares.
The commenter should also consider §98.34 for revised methods to determine the carbon content
of gaseous fuel.
Commenter Name: Lorraine Krupa Gershman
Commenter Affiliation: American Chemistry Council (ACC)
Document Control Number: EPA-HQ-OAR-2008-0508-0423.2
Comment Excerpt Number: 64
Comment: In §98.34(d)(3), facilities using process gas should be provided with an option to
perform a statistical analysis to determine a sample and analytical frequency that is less often
than daily, based on the potential for variations in process gas composition. Requiring daily
sampling for all process fuels may be unnecessary. At a minimum, facilities should be allowed
the option of initially sampling monthly and then using a different frequency if warranted by a
statistical analysis.
Response: EPA acknowledges the commenter's concerns, and has significantly revised §98.34
concerning fuel sampling and analysis. Section 98.34 provides specific instructions concerning
sampling and analysis of gaseous fuels. In addition, EPA has revised §98.34 of the rule, defining
multiple methods for determining the carbon content for gaseous fuels. The Agency believes
that these revisions should address the commenter's concerns.
405
-------
Commenter Name: Lorraine Krupa Gershman
Commenter Affiliation: American Chemistry Council (ACC)
Document Control Number: EPA-HQ-OAR-2008-0508-0423.2
Comment Excerpt Number: 65
Comment: In §98.34(e)(l)(i), (ii), and (iii), the terms are redundant if it is presumed they are
connected by "and" EPA should clarify this by connecting each of the terms (i), (ii), and (iii) by
"or."
Response: EPA agrees that the proposed language could be confusing, and has added language
to the final rule to clarify that any one of the alternate initial certification procedures for CO2
CEMS is acceptable.
Commenter Name: Lorraine Krupa Gershman
Commenter Affiliation: American Chemistry Council (ACC)
Document Control Number: EPA-HQ-OAR-2008-0508-0423.2
Comment Excerpt Number: 66
Comment: No place in §98.34 does EPA provide a specified recommended methodology for
measuring solid fuels. Requiring measurement of the fuel rate instead of allowing calculation
would be especially burdensome and unnecessarily costly, and would require the installation of
weighing equipment. Some sites currently calculate the amount of solid fuel combusted based
on, for example in the case of a boiler, the amount of steam generated each month and the boiler
efficiency. EPA should continue to allow such engineering calculations for solid fuel flow rate.
Response: EPA acknowledges the commenter's concerns, and has significantly revised §98.34
concerning fuel sampling and analysis. In particular, the revised rule allows "company records"
as defined in §98.6 to be used to quantify fuel consumption. In addition, revised §98.34 refers to
the calculations using steam produced as the basis for determining solid fuel combusted. The
Agency believes that these revisions should address the commenter's concerns. Also, EPA has
extended the use of steam production and combustion unit efficiency to calculate CO2 emissions
to other solid fuels in addition to municipal solid waste. These parameters may also be used to
quantify the amount of biomass combusted in a unit.
Commenter Name: J. P. Blackford
Commenter Affiliation: American Public Power Association (APPA)
Document Control Number: EPA-HQ-OAR-2008-0508-0661.1
Comment Excerpt Number: 6
Comment: EPA, on page 16483 of the Preamble, is "allowing a January 1, 2011 compliance
date to install CEMS to meet the Tier 4 requirements, if either a diluent gas monitor, flow
monitor, or both, must be added. The January 1, 2011 deadline would allow sufficient time to
purchase, install, and certify any additional monitor(s) needed to quantify CO2 mass emissions."
While APPA supports the extension of time to purchase, install, and certify the additional
monitors, we are concerned that the extension is not sufficient for the following reasons: 1.
406
-------
Some municipal utilities are on a July fiscal year with those budgets already virtually locked in
for a period of 7/1/09 - 6/30/10. If they are forced to wait for the following budget year
beginning 7/1/10, it will allow utilities only six months to purchase, install and certify the
monitors. Some state legislatures' budgetary cycles do not allow additional expenditures without
authorization during the first half of a calendar year. 2. The installation and calibration of CEMS
may not be an easy task. APPA has utility members who have been required to make structural
modifications to their stacks in order to get accurate flow measurements. In addition, some have
cited concerns about the accuracy of the CEMS, potentially caused by air leakage and other
operational parameters and the degradation of the EGU. 3. Consideration must also be given to
the scheduled outages which are the most reasonable time for utilities to install the necessary
CEMS. A later installation deadline is needed to enable this activity to occur during planned
outages that are often scheduled years in advance. 4. Another issue for EPA to consider is
whether industry has ample capacity to manufacture, install and certify these monitors within the
originally suggested timeframe. In addition, as APPA utility members are part of their municipal
government, they are required to follow standard procurement procedures when soliciting
proposals for work. This will usually require multiple bids and may require more time to choose
a contractor than would be required for a non-municipal utility. Given these issues, APPA
requests that EPA extend the deadline to no earlier than July 1, 2011 for the installation of
CEMS to meet the Tier 4 requirements. Units could use Tier 3 reporting methodologies until
this time and this would allow EPA to collect GHG emissions data while allowing utilities ample
time to install the required CEMS and have them certified as required in the proposed rule.
Response: EPA appreciates the commenter's concerns. Any CEMS that would be used to
quantify CO2 emissions would also have to be certified and undergo ongoing quality assurance
testing according to the procedures specified in either: (1) 40 CFR Part 75; or (2) 40 CFR Part
60, Appendix B; or (3) a State monitoring program. Sources that have all of the necessary
CEMS installed and certified by January 1, 2010 are required to use Tier 4 in 2010. However,
for sources that need additional time to upgrade their CEMS, the monitor certification deadline is
extended to January 1, 2011, and Tier 2 or Tier 3 methodology may be used in 2010.
See the response to comment EPA-HQ-OAR-2008-0508-1142.1, excerpt 26, for additional
information on flexibility provided for the year 2010.
Commenter Name: William C. Herz
Commenter Affiliation: The Fertilizer Institute (TFI)
Document Control Number: EPA-HQ-OAR-2008-0508-0952.1
Comment Excerpt Number: 6
Comment: The language proposed in 40 C.F.R. §98.34(d)(3) states that "[f]or other gaseous
fuels, daily sampling and analysis is required to determine the carbon content and molecular
weight of the fuel." 74 Fed. Reg. at 16,636. For some combustion processes, such as an
ammonia manufacturing facility, the composition of the fuel gas provided by the inert purge of
the process does not vary in carbon content. In light of this, TFI proposes that quarterly
sampling is sufficient for representative carbon content. Specifically for ammonia
manufacturing units, the carbon content of the supplemental fuel is already accounted for, and
should be excluded from the combustion calculation, as this would be double counting of the
carbon. Weekly sampling would add approximately $20,000 per plant per year to comply with.
407
-------
Response: EPA acknowledges the commenter's concerns, and has significantly revised §98.34
concerning fuel sampling and analysis. Section 98.34 provides specific instructions concerning
sampling and analysis of gaseous fuels. In addition, EPA has revised §98.34 of the rule, defining
multiple methods for determining the carbon content for gaseous fuels.
EPA intends that the stationary combustion source category include any device that meets the
definition included in §98.30 for which emissions are not accounted for in the report through a
separate subpart of the rule. Per the requirements in 40 CFR Part 98, Subpart A, facilities have
to report GHG emissions from all source categories located at their facility, including stationary
combustion and process emissions. EPA does not intend that emissions be double reported, and
has revised the various subparts of the final rule to clarify the intent of the stationary combustion
source category. EPA understands that if process and combustion emissions are not easily or
logically separated, that combustion emissions may be reported in combination with process
emissions, as may be the case with ammonia manufacturing.
Commenter Name: H. Allen Faulkner
Commenter Affiliation: Ascend Performance Materials, LLC, Decatur Plant
Document Control Number: EPA-HQ-OAR-2008-0508-1578
Comment Excerpt Number: 6
Comment: Ascend Decatur Alabama Plant uses Coriolis-based mass flow meters on some
natural gas lines. The current requirements of 98.34(d)(1), state that gas flow meters must be
recalibrated annually. There is no method for calibrating these meters on-line. Therefore,
annual calibration would require the meter to be removed from service and shipped to a flow lab
for calibration. This would require purchase of additional meters to ensure continuous operation
during calibration down time. Ascend requests further guidance on the calibration of Coriolis-
based mass flow meters. In addition, Ascend uses various other types of flow meters (i.e. orifice
plates) which would be subject to annual recalibration requirement in 98.34(d)(1). Is it sufficient
to check the transmitter calibration to meet this requirement or does the primary element and
transmitter have to be tested together? If the primary element and transmitter have to be tested
together, the procedure would require redundant meters be installed because the entire unit
would have to be removed for testing.
Response: EPA acknowledges the concerns of the commenters. Section 98.34 of the final rule
clarifies that for units and processes that use an orifice, nozzle, or venturi meter and operate
continuously with infrequent outages, the owner or operator may postpone the initial calibration
or PEI (as applicable) until the next scheduled maintenance outage. Therefore, an online
calibration method will not be needed. For ongoing quality assurance, each flow meter shall be
recalibrated either biannually (i.e., once every two years) or at the minimum frequency specified
by the manufacturer. For the continuously-operating units and processes described in §98.34, the
required flow meter and PEI recalibrations may be postponed until the next scheduled
maintenance outage.
408
-------
Commenter Name: Rhea Hale
Commenter Affiliation: American Forest & Paper Association (AF&PA)
Document Control Number: EPA-HQ-OAR-2008-0508-0909.1
Comment Excerpt Number: 8
Comment: AF&PA agrees with EPA's approach in 98.34(a) to allow sources latitude in
determining fuel input and to maintain records of its methodologies. Facilities should be allowed
to back-calculate fuel combustion quantities based on boiler steam generation quantities and
boiler steam generation efficiencies, as discussed in EPA's Technical Support Document (TSD)
for the Pulp and Paper Sector. As presented in Section 6.1 of the TSD, these back-calculated
biomass fuel consumption quantities should then be used in conjunction with default emission
factors for biomass fuels to calculate biogenic C02 emissions. This option should be explicitly
allowed for combustion units burning only biomass, and for combustion units that burn a
combination of biomass and fossil fuels. This option (determining fuel consumption quantities
from steam production data and boiler efficiency) should also be allowed for determining
biogenic C02 from combustion of spent pulping liquors in recovery furnaces.
Response: In response to comments, EPA has added a provision in §98.33(e)(6) specifically
allowing facilities to back-calculate the quantity of solid fuel combusted using steam generation
and boiler efficiency. EPA has provided an example calculation method, and has allowed
facilities to use other similar methods, provided that they are documented and kept in the
company's records as required by §98.3(g)(4).
Commenter Name: See Table 8
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0709.1
Comment Excerpt Number: 8
Comment: We appreciate the provision in section 98.34(d)(1) which states that "All oil and gas
flow meters (except for gas billing meters) shall be calibrated prior to the first year for which
GHG emissions are reported under this part..." We strongly urge EPA insert a similar
parenthetical to exclude gas billing meters from annual calibration, as follows: "Fuel flow
meters (except for gas billing meters) shall be recalibrated either annually or at the minimum
frequency specified by the manufacturer."
Response: EPA acknowledges the concerns of the commenters. Section 98.34 of the final rule
has been clarified to exempt fuel billing meters from the calibration requirement, "provided that
the supplier and the unit(s) combusting the fuel do not have any common owners and are not
owned by subsidiaries or affiliates of the same company."
409
-------
Commenter Name: Marc J. Meteyer
Commenter Affiliation: Compressed Gas Association (CGA)
Document Control Number: EPA-HQ-OAR-2008-0508-0981.1
Comment Excerpt Number: 24
Comment: The proposed rule defines the alternate initial certifications for C02 CEMS systems
under §98.34(e)(l)(i), (ii), and (iii). The propose rule language is not clear that any one of the
certifications described in §98.34(e)(l)(i), (ii), and (iii) is acceptable. CGA Comment: Clarify
that any one of the alternate initial certifications under §98.34(e)(l)(i), (ii), and (iii) is acceptable
by separating the (i), (ii), and (iii) options with "or".
Response: EPA agrees that the proposed language could be confusing, and has added language
to the final rule to clarify that any one of the alternate initial certification procedures for CO2
CEMS is acceptable.
Commenter Name: Renae Schmidt
Commenter Affiliation: CITGO Petroleum Corporation
Document Control Number: EPA-HQ-OAR-2008-0508-0726.1
Comment Excerpt Number: 11
Comment: CITGO recommends that EPA clarifies key QA/QC requirements in the Preamble to
help owners and operators better understand calibration expectations. For example, orifice flow
meters are commonly used for measuring refinery fuel gas to heaters and boilers. Orifice meters
are typically "calibrated" by checking differential pressure (DP) cell. Direct calibration of the
primary element (orifice plate) is not feasible and can not be field verified unless the fuel line is
taken out of service which can be up to 8 years for some process heaters.
Response: EPA acknowledges the concerns of the commenters regarding the unique nature of
orifice flow meters, and has clarified the final rule in §98.34. The initial quality assurance of an
orifice meter requires only an in-situ calibration of the transmitters. For ongoing QA, the in-situ
transmitter calibration shall be repeated at least annually, and the primary element inspection
(PEI) shall be performed at least once every three years.
Commenter Name: Lorraine Krupa Gershman
Commenter Affiliation: American Chemistry Council (ACC)
Document Control Number: EPA-HQ-OAR-2008-0508-0423.2
Comment Excerpt Number: 62
Comment: In §98.34(d)(1), some flow meters may not be calibrated without shutting down the
process. For example, in some cases, an orifice plate must be pulled out of the line to do a
complete calibration. This might be part of manufacturer's recommendations as a part of
calibration recommendations. It would not be practical to perform this yearly because equipment
may not be out of service on a frequency of more than one time in every several years. The
annual calibration should be limited to no more than would be required by Part 75 (electronic
410
-------
transmitter calibration) less the visual inspection every three years. In addition, for the reasons
cited above regarding possible unit shutdown for a full calibration per manufacturer's
recommendations, it may not be practical or possible to complete all required calibrations
between now and January 1, 2010. ACC recommends that EPA allow owners/operators to
continue utilizing existing flow meters until the next scheduled shutdown for calibration, if it
requires a process unit shutdown.
Response: See the Preamble and separate comment response document volume for the response
on Monitoring and QA/QC Requirements.
See the response to comment EPA-HQ-OAR-2008-0508-1142.1, excerpt 26, for more
information on additional flexibility for 2010.
EPA acknowledges the concerns of the commenters regarding the unique nature of orifice flow
meters, and has clarified the final rule in §98.34. The initial quality assurance of an orifice meter
requires only an in-situ calibration of the transmitters. For ongoing QA, the in-situ transmitter
calibration shall be repeated at least annually, and the primary element inspection (PEI) shall be
performed at least once every three years. For the continuously-operating units and processes
described in §98.34, the required flow meter and PEI recalibrations may be postponed until the
next scheduled maintenance outage.
Commenter Name: Craig S. Campbell
Commenter Affiliation: Lafarge North America
Document Control Number: EPA-HQ-OAR-2008-0508-0674.1
Comment Excerpt Number: 12
Comment: When Subpart C Tier 3 is used, proposed 40 CFR §98.34(d)(3) requires: "The
carbon content of the fuels listed in paragraphs (c)(1) and (2) of this section shall be determined
monthly." Paragraph (c)(1) refers to monthly sampling of natural gas, biogas, and liquid fuels,
and paragraph (c)(2) refers to weekly samples which are composited and analyzed monthly for
coal and other solid fuels. Lafarge recommends that EPA amend the fuel sampling frequency
requirements by adding a provision allowing gradual reduction in sampling frequency over time
if the facility is able to make a showing that carbon content values remain within a statistically-
appropriate range of variability. In addition, Lafarge wishes to point out that EPA's proposed
weekly sampling with compositing for monthly analysis is not appropriate for all solid fuels used
at cement plants. One example is solid tires ("tire-derived fuel"), which as a practical matter
cannot be sampled for carbon content testing on a weekly basis. Construction of a typical
passenger vehicle tire includes numerous components. A constructed tire has these various
components placed at specific locations per the design requirements of the tire, and is therefore
entirely non-homogeneous. Components include various synthetic rubbers, natural rubber,
carbon black, nylon ply's, steel belts and beads, and other components. In light of its non-
homogeneity, representative sampling of a tire is a complex labor-intensive exercise that cannot
reasonably be done on a weekly basis. The more practical method is to characterize tire carbon
content by using a "database average value" based upon representative sampling efforts
conducted over a much longer time span. A reasonable database average approach would be
annual sampling and use of a 5-year average. Lafarge also wishes to emphasize that the tire-
derived-fuel is just one example which supports use of a "database average approach" as opposed
411
-------
to weekly/monthly sampling and analysis. EPA should provide flexibility in the rule language to
address the wide variety of possible alternative fuels warranting use of the database average
approach. A somewhat different need for flexibility arises with some types of alternative fuels
derived from other distinct manufactured products. For example, some cement plants use a
particular alternative fuel derived from one particular product such as discarded CD cases, off-
spec diapers, or another distinct product. As a rule, the composition and carbon content remains
constant for any alternative fuel derived from any one distinct manufactured product. In this
situation an initial characterization, and less frequent (e.g., annual) confirmation testing would be
appropriate. Weekly/monthly sampling and analysis of these types of alternatives fuels would be
excessive and should not be required under the regulation. Overall, we believe it is important
that EPA provide more flexibility in terms of sampling method and frequency for all types of
solid fuels other than coal and petroleum coke. Lafarge recommends that EPA at least add
specific provisions to allow: A.) use of long-term database averages for mixed alternative fuels
and non-heterogeneous alternative fuels (e.g., tire-derived fuel), and B.) initial characterization
with less-frequent confirmation sampling for a solid fuel derived from a distinct manufactured
product (e.g., CD cases, diapers, etc.).
Response: EPA acknowledges and appreciates the commenter's concerns. Section 98.34 has
been revised to require that natural gas be sampled semiannually and to require a representative
sampling for each fuel lot (i.e., for each shipment or delivery) for fuel oil and coal. For other
liquid fuels and biogas, quarterly sampling is required. For other solid fuels, excluding
municipal solid waste, weekly composite sampling with monthly analysis is required. For other
gaseous fuels, the daily sampling requirement has been retained, but only for facilities with
existing equipment in place that is capable of providing the data. Otherwise, weekly sampling is
required, which may be postponed in favor of monthly sampling until 2011 if new equipment
must be purchased or if existing equipment must be upgraded to meet the weekly sampling and
analysis requirements.
The final rule clarifies that fuel sampling and analysis data provided by the supplier may be used
in the emission calculations, and that fuel billing meters may be used to quantify fuel
consumption. To simplify the emission calculations in Tiers 2 and 3, averaging of HHV and
carbon content data is permitted if these data are obtained at least at the minimum frequency
specified in §98.34. If the results of fuel sampling are received monthly or more frequently, the
weighted annual average high heat value shall be calculated using Equation C-2b. If the results
of fuel sampling are received less frequently than monthly, then the annual average HHV shall
be calculated using the arithmetic average HHV for all valid samples for the year. However,
regardless of the sampling frequency, the owner or operator must use the results of all available
valid fuel analyses in the emissions calculations.
EPA has revised the use of Tier 3 in §98.33(b)(3) of Subpart C to be required only when a unit
with a maximum rated heat input capacity greater than 250 mmBtu/hr that combusts any type of
fuel listed in Table C-l of this subpart (except MSW), unless the use of Tier 1 or 2 is permitted
or Tier 4 is required. Tier 3 is also required for a unit with a maximum rated heat input capacity
greater than 250 mmBtu/hr that combusts a fuel that is not listed in Table C-l of this subpart
provided that the use of Tier 4 is not required and the fuels provide ten percent or more of the
annual heat input to the unit or to a group of units served by common supply pipe, as described
in §98.36(c)(3).
412
-------
It is also noted that Tier 1 may be used for any fuel listed in Table C-l that is combusted in a unit
with a maximum rated heat input capacity of 250 mmBtu/hr or less.
The Agency is not opposed to alternative approaches for fuel sampling, such as specific
allowances for annual sampling and use of a 5-year average as described by the commenter.
However, the commenter did not provide any supplementary information, proposed rule
language, or cost analysis to explain how this proposed methodology could be implemented. In
view of this, EPA has not incorporated the commenter's suggested approach into the final rule,
but is willing to consider it in a future rulemaking, if the necessary technical details of the
method are provided for Agency review.
Commenter Name: Renae Schmidt
Commenter Affiliation: CITGO Petroleum Corporation
Document Control Number: EPA-HQ-OAR-2008-0508-0726.1
Comment Excerpt Number: 12
Comment: Performance specifications are already in place for the continuous monitoring of
CO2, flow measurement devices and other monitoring and measuring devices specified in the
Inventory Rule. Calibration, Testing, Certification and QA/QC for these devices are well
established and time tested. Requiring additional procedures around these monitors is expensive
and burdensome, not to mention leading to additional downtime on monitors that serve for both
the GHG Reporting Rule and other rules. EPA should refer to and rely upon the existing
standards for monitoring equipment and adopt them by reference in the Rule.
Response: EPA believes that the methods listed in §98.34 of the final rule, derived from §98.7,
provide operators adequate flexibility for best practices. Operators may also use the calibration
procedures specified by the flow meter manufacturer. In the case of oil tank drop measurements,
those shall be performed according to any consensus based standard.
Commenter Name: Kathy G. Beckett
Commenter Affiliation: West Virginia Chamber of Commerce
Document Control Number: EPA-HQ-OAR-2008-0508-0956.1
Comment Excerpt Number: 16
Comment: Proposed §98.34(c)(2), specifies weekly sampling to develop a composite for
monthly analysis of for coal, and other solid fuels. EPA should clarify its description and
equation to reflect the more specific provisions in §98.34(c). Carbon content is measured
monthly for natural gas, biogas, and liquid fuels, monthly for coal and other solid fuel (based on
a weekly composite), and daily for other gaseous fuel (e.g., refinery gas or process gas).
Proposed §98.34(d)(3). EPA assumes that daily measurements would be made with in-line gas
chromatographs that are already in place for process purposes. 74 Fed. Reg. 16484. All oil and
gas flow meters (except for gas billing meters) must be calibrated prior to the first reporting year
using either a test method listed in §98.7 or "the calibration procedures specified by the flow
meter manufacturer," and must be recalibrated either annually or "at the minimum frequency
specified by the manufacturer." Proposed §98.34(d)(1). For both Tier 2 and Tier 3
413
-------
methodologies, only those sampling and analysis methods incorporated under proposed §98.7
can be used. Proposed §98.34(c) and (d). To ensure that this list is complete and that the
methods provided are up to date, the Chamber requests that EPA also allow use of any applicable
method incorporated under 40 C.F.R. §75.6.
Response: EPA has incorporated by reference all methods deemed appropriate into Part 98, and
therefore does not believe it is necessary to allow the use of methods listed under 40 C.F.R
§75.6. The commenter should note that the EPA has substantially revised §98.34(c). According
to the final rule, at least one representative sample from each lot of coal must be sampled. For
other solid fuels (other than municipal solid waste), the final rule retains the original provision to
sample weekly and analyze a monthly composite sample. EPA has also revised §98.33(a)(2),
concerning the Tier 2 Methodology, to clarify the calculations required depending on the
frequency of fuel sampling.
Commenter Name: Kathy G. Beckett
Commenter Affiliation: West Virginia Chamber of Commerce
Document Control Number: EPA-HQ-OAR-2008-0508-0956.1
Comment Excerpt Number: 17
Comment: Of concern is the need to ensure that units that do not already have required
monitoring installed have sufficient time to order, install, and perform any necessary testing on
that equipment prior to the start of the program. EPA has attempted to address that sort of
concern in proposed §98.33(b)(6), which provides that if the monitors needed to report under
Tier 4 have not been installed and certified by January 1, 2010, the unit may use Tier 3 in 2010.
While the Chamber believes that the relief provided by this provision is necessary, it is
incomplete. Reporting under Tier 3 also requires monitoring equipment for gaseous fuels — fuel
flow meters and, for some fuels, gas chromatographs — that need to be installed and calibrated.
In finalizing the rule, EPA must ensure that sufficient time and resources are available for
installation and calibration of this equipment.
Response: See the response to comment EPA-HQ-OAR-2008-0508-1142.1, excerpt 26, for
more information on flexibility for 2010. EPA agrees that there was not sufficient time given for
installation and calibrations of fuel flow meters, and has revised §98.34(d) concerning
installation and calibration, such that the deadline has been extended one year, to January 1,
2011. For flow monitors previously calibrated using the manufacturer's recommended methods,
an additional calibration is not required by January 1, 2011 if the calibration is still active, but a
calibration must be performed before the time interval recommended by the manufacturer
elapses.
414
-------
Commenter Name: See Table 3
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0433.2
Comment Excerpt Number: 18
Comment: NPRA recommends that a source consuming common commercial fuels may, at the
source's option: 1. Use the standard GHG emission factors provided in the rule; or 2. Use an
annual average heat value or carbon content determination performed by the supplier of the
common commercial fuel; or 3. Perform a single, annual sampling and analysis for heat value or
carbon content; and 4. Exclude mandatory sampling and characterization of a fuel stream that
accounts for less than 1% of the facility's GHG emissions. As part of the proposed rule,
§98.33(b) defines which calculation Tier can be used for different size/fuel sources:
§98.34(c)(1) requires natural gas to be sampled and tested for heat value monthly, §98.34(d)(3)
requires natural gas to be sampled and tested for carbon content monthly but requires other
gaseous fuels to be sampled and tested for carbon content and molecular weight daily, and
§98.164(c) requires gaseous feedstocks to be sampled and tested for carbon content monthly. In
some cases, a reasonable approach (method, frequency, responsibility, and alternate methods) to
characterizing fuels and feedstocks is allowed; in other cases excessive approaches are required.
In addition, comparably accurate methods for estimating emissions from common fuels (e.g.,
standard emission factors) are restricted to smaller combustion units, potentially increasing the
burden on the regulated source with no resultant improvement in the quality of the emissions
data. Many combustion-related sources utilize common fuels of commerce, which are well
characterized and must meet specific industry standards for commercial sale. For such fuels, use
of standard emissions factors is a suitable approach to determine an estimate of GHG emissions,
as it is within the margin of error of all the other relevant measured/estimated values. A
particularly clear example is utility-supplied natural gas, regarding which even the Preamble
cites that the average carbon content is within 1% for all common gas supplies. Furthermore,
under Subpart NN applicable to this source category responsible for emissions of 1,115 million
metric tons or 16.4% of the national total, the Preamble states (74 FR 68, p 16577) that the
proposed rule will not require the local gas distribution companies to sample and analyze natural
gas periodically. The proposed rule itself (74 FR 68, pp 16721 - 16722) requires the use of one
of two simple equations that rely on EPA default emission factors. If the agency is committed to
monthly characterizations of these common fuels, the agency should accept analysis performed
by the fuel supplier. While use of supplier-generated data is suggested in the Preamble, it is not
clearly articulated as an allowed approach in the proposed rule itself. Allowing supplier
generated characterization data to be used would significantly reduce the amount of redundant
sampling and analysis, in many cases by sources that have no experience in such sampling or
analysis, in favor of centralized fuel characterization by entities who are already conducting such
sampling and analysis on a regular basis. To ensure the benefit of such an approach NPRA
recommends the agency make the characterization of common commercial fuels by the suppliers
a requirement under the mandatory reporting rule. Likewise, on the basis that the source is
striving to calculate an annual emission estimate, NPRA believes daily characterization of fuel
gases (e.g., refinery fuel gas) creates excessive costs and risks in sampling and analysis of such
flammable gas streams. NPRA recommends the source conduct monthly sampling and analysis
and apply the average of the 12 monthly samples to the annual fuel consumption to yield the
annual emission estimate. NPRA understands that EPA seeks an accurate characterization of all
fuel gases, and acknowledges that some sources of fuel gas (e.g., refinery fuel gas) can vary with
time. However, NPRA recommends that agency at a minimum should adopt an approach that
415
-------
allows a source to establish the average characteristics (heat value or carbon content, as
appropriate for the Tier calculation method employed) of the fuel gas through multiple
measurements (minimum 4 per month) and, if the variation between measurements falls within a
5% control limit, weekly characterization can be reduced to monthly. If a monthly sample falls
outside the 5% limit, the source must return to daily characterization until the 5% control limit
can be restored. This approach allows the significant cost associated with sampling and analysis
to be reduced when it can be demonstrated that the accuracy of the accounting method meets the
program objectives. Tier 1 and 2 methods which allow the use of the default emission factors for
calculating combustion emissions are restricted to combustion sources less than 250 MM
BTU/hr. For many common fuels, natural gas in particular, the carbon content and heat content
are very consistent, allowing standard emission factors to be reliable estimates. Combined with
an appropriately accurate flow measurement of fuel consumption, these can be used to provide
an accurate and cost effective determination of the resultant GHG emissions. The hydrogen
production section (specifically, §98.164(c) requires gaseous feedstocks to be only sampled and
tested for carbon content monthly, regardless of the type of feedstock (e.g., natural gas or
refinery fuel gas), while the stationary combustion section requires all gaseous fuel sources,
other than natural gas, to be characterized on a daily basis. For the reasons noted above, and to
be consistent with the approach provided in §98.164(c), NPRA recommends EPA require all
gaseous fuels to be characterized no more frequently than monthly (modify §98.34(d)(3)) and in
all cases, allow the characterization to be provided by the supplier of the fuel/feedstock (modify
§98.34(c), §98/34(d)(3), and §98.164(c)), consistent with the intent described in the Preamble.
Response: EPA acknowledges and appreciates the commenter's concerns. EPA has revised the
rule to allow large (greater than 250 mmBtu/hr) units that burn only natural gas or distillate oil to
use Tier 2. EPA has also revised sampling frequencies, and now requires that natural gas be
sampled semiannually and to require a representative sampling for each fuel lot (i.e., for each
shipment or delivery) for fuel oil and coal. For other liquid fuels and biogas, quarterly sampling
is required. For other solid fuels, excluding municipal solid waste, weekly composite sampling
with monthly analysis is required. For other gaseous fuels, the daily sampling requirement has
been retained, but only for facilities with existing equipment in place that is capable of providing
the data. Otherwise, weekly sampling is required, which may be postponed in favor of monthly
sampling until 2011 if new equipment must be purchased or if existing equipment must be
upgraded to meet the weekly sampling and analysis requirements.
The final rule clarifies that fuel sampling and analysis data provided by the supplier may be used
in the emission calculations, and that fuel billing meters may be used to quantify fuel
consumption. To simplify the emission calculations in Tiers 2 and 3, averaging of HHV and
carbon content data is permitted if these data are obtained at least at the minimum frequency
specified in §98.34. If the results of fuel sampling are received monthly or more frequently, the
weighted annual average high heat value shall be calculated using Equation C-2b. If the results
of fuel sampling are received less frequently than monthly, then the annual average HHV shall
be calculated using the arithmetic average HHV for all valid samples for the year. However,
regardless of the sampling frequency, the owner or operator must use the results of all available
valid fuel analyses in the emissions calculations.
416
-------
Commenter Name: Michael Carlson
Commenter Affiliation: MEC Environmental Consulting
Document Control Number: EPA-HQ-OAR-2008-0508-0615
Comment Excerpt Number: 19
Comment: The proposed requirement of a description of the quality assurance procedures used
(e.g., calibration of instrumentation) as part of the Tier 1 or Tier 2 emissions calculation
methodology (16486) is inappropriate for many facilities which rely on metering devices owned,
operated, and controlled by the fuel supplier or utility, which is completely separate and
independent entity. This requirement would unnecessarily burden industrial and commercial
facilities which would need to contact the fuel suppliers and utilities for this information. The
requirement would also create an undue burden on fuel suppliers and utilities which would have
to respond to facility requests for information on meter specifications and calibration data.
Response: EPA acknowledges the concerns of the commenters. Section 98.34 of the final rule
has been clarified to exempt fuel billing meters from the calibration requirement, "provided that
the supplier and the unit(s) combusting the fuel do not have any common owners and are not
owned by subsidiaries or affiliates of the same company."
Commenter Name: Ronald H. Strube
Commenter Affiliation: Veolia ES Solid Waste
Document Control Number: EPA-HQ-OAR-2008-0508-0690.1
Comment Excerpt Number: 20
Comment: The NSPS JJJJ requires performance testing on stationary electrical generation
engines every 8760 hours or 3 years of operation. This testing should be sufficient for electrical
generation equipment.
Response: EPA does not understand the comment, and is unclear on how the performance
testing relates to calculation and reporting of GHG emissions. See the Preamble, Section III, for
a general description of the approach and response to comments for Subpart D Electricity
Generation.
Commenter Name: Marc J. Meteyer
Commenter Affiliation: Compressed Gas Association (CGA)
Document Control Number: EPA-HQ-OAR-2008-0508-0981.1
Comment Excerpt Number: 22
Comment: The proposed rule requires periodic sampling and analysis of fuels for HHV or
carbon content under §98.34(c)(1) and (2) and §98.34(d)(3). The rule implies this sampling and
analysis is to be done by the consumer of the fuel, the reporting source. The proposed rule
further describes minimum sampling and analysis frequencies for each fuel type. The proposed
rule implies a need for characterization of standard commercial fuels to meet calculation method
Tier 2 and 3, when, in actuality, the HHV and carbon content of standard fuels are nearly
constant values and default values (e.g. Tier 1 calculation method) yield sufficiently accurate
417
-------
emission estimates. Recognizing the objective of the reporting rule is to develop a reasonable
estimate of the annual emissions from a source: Standard fuels of commerce (natural gas, LP
gas, fuel oils, etc.) that are supplied to multiple consumers are more efficiently characterized by
their suppliers than by their consumers. Standard fuels of commerce (excepting coal) have very
consistent HHV and carbon contents, requiring much lower characterization frequency. Monthly
characterization, as required under §98.34(c)(1) and §98.34(d)(3), of such consistent fuels is
costly and does not materially improve the annual estimate of emissions. Process-specific fuel
sources (e.g. refinery gas) vary over time, but requiring daily sampling and analysis is very
burdensome and costly for a degree of characterization that is intended to yield an annual
emission estimate. CGA Comment: The characterization of standard fuels of commerce should
not be required since default values employed under the Tier 1 calculation method will yield a
sufficiently accurate emission estimate (per comments regarding §98.33(b)(1), (3), and (4),
above). If a fuel characterization is required, the characterization sampling and analysis should
be the responsibility of the fuel supplier. Such suppliers should then be required to provide the
characterizations to any fuel consumers, upon request. The agency should then accept these
characterizations for use under Tier 2 and 3 calculation methods. The characterization frequency
of standard fuels of commerce should be reduced to annually. The characterization of process-
specific fuels should be reduced to monthly. Alternately, a source should be able to demonstrate
that, after a period of required characterization, the variability of the average fuel characteristic
(HHV or carbon content) is sufficiently small to justify a reduction in the sampling and analysis
burden.
Response: EPA acknowledges and appreciates the commenter's concerns. In the final rule,
§98.34 has been revised to require that natural gas be sampled semiannually and to require a
representative sampling for each fuel lot (i.e., for each shipment or delivery) for fuel oil and coal.
For other liquid fuels and biogas, quarterly sampling is required. For other solid fuels, excluding
municipal solid waste, weekly composite sampling with monthly analysis is required. For other
gaseous fuels, the daily sampling requirement has been retained, but only for facilities with
existing equipment in place that is capable of providing the data. Otherwise, weekly sampling is
required, which may be postponed in favor of monthly sampling until 2011 if new equipment
must be purchased or if existing equipment must be upgraded to meet the weekly sampling and
analysis requirements.
In addition, the final rule clarifies that fuel sampling and analysis data provided by the supplier
may be used in the emission calculations, and that fuel billing meters may be used to quantify
fuel consumption. To simplify the emission calculations in Tiers 2 and 3, averaging of HHV and
carbon content data is permitted if these data are obtained at least at the minimum frequency
specified in §98.34. If the results of fuel sampling are received monthly or more frequently, the
weighted annual average high heat value shall be calculated using Equation C-2b. If the results
of fuel sampling are received less frequently than monthly, then the annual average HHV shall
be calculated using the arithmetic average HHV for all valid samples for the year. However,
regardless of the sampling frequency, the owner or operator must use the results of all available
valid fuel analyses in the emissions calculations.
EPA has not required fuel suppliers to provide HHV and carbon content data to facilities, as it is
the source's responsibility to determine emissions. Fuel suppliers have their own reporting
requirements in other subparts. Addtionally, private sector contracts typically specify the terms
of fuel related information provided by suppliers to purchasers.
418
-------
Subpart KK, Suppliers of Coal, has not been included in this final rule. Subpart MM, Suppliers
of Petroleum Products, and Subpart NN, Suppliers of Natural Gas, provide upstream reporters
with the option of using default HHV and carbon contents or site specific sampling. EPA has not
required fuel suppliers to provide HHV data to facilities, as provision of this type of information
is typically addressed in private sector purchase contracts.
Commenter Name: Marc J. Meteyer
Commenter Affiliation: Compressed Gas Association (CGA)
Document Control Number: EPA-HQ-OAR-2008-0508-0981.1
Comment Excerpt Number: 23
Comment: The proposed rule requires all liquid and gaseous fuel flow meters to be calibrated
initially and annually, or at the meter manufacturer's specified frequency, thereafter. This
requirement fails to recognize that some fuel measurement device installations do not allow
calibration without taking the fuel line out of service, thereby forcing a shutdown of the
combustion/manufacturing process. In many instances, scheduled maintenance shutdowns for
such equipment/processes will not occur on this prescribed frequency. Unless provisions are
added to the proposed rule which provide relief from this required calibration frequency,
manufacturing processes will be required to shutdown solely to complete the required
calibration, resulting in significant cost, business disruption and, in many cases, increase
environmental impacts from the inefficiencies of the start-up/shutdown activity. This need is
comparable to provisions under many EPA rules regarding the repair of leaking VOC fugitive
emissions components where repair would require a process shutdown, and instead the repair
deadline is extended to the next scheduled maintenance shutdown. In most instances, the delay
in calibration of a flow meter requiring a process shutdown would not materially compromise the
annual emission estimate. This is particularly true for those combustion units using the simplest,
cleanest fuels - there is typically less "drift" in the calibration of flow measurement devices for
such clean fuels and such combustion units/processes often require less frequent maintenance
turnarounds, exacerbating the need for extension of the calibration frequency. CGA Comment:
The rule should include provisions for an extension of the required flow meter calibration
deadline (as well as the initial calibration, if appropriate) where the calibration would require
removing the fuel supply from service. The calibration requirement should then be extended to
the next scheduled maintenance shutdown for the impacted unit/process.
Response: See the response to comment EPA-HQ-OAR-2008-0508-1142.1 excerpt 26, for
more information on flexibility provided for 2010 reporting.
EPA acknowledges the concerns of the commenters. Section 98.34 of the final rule clarifies that
for units and processes that use an orifice, nozzle, or venturi meter and operate continuously
with infrequent outages, the owner or operator may postpone the initial calibration or PEI (as
applicable) until the next scheduled maintenance outage, and may similarly postpone the
subsequent recalibrations and PEIs."
419
-------
Commenter Name: Ron Downey
Commenter Affiliation: LWB Refractories
Document Control Number: EPA-HQ-OAR-2008-0508-0719.1
Comment Excerpt Number: 24
Comment: 40 C.F.R. 98.34(e)(1) specifies procedures for the initial certification of a CEMS.
As the Proposed Rule is currently written, it appears that all procedures identified must be
followed to initially certify a CEMS. Based on our May 14, conference call, only one of the
listed procedures must be followed to initially certify a CEMS. NLA proposes that 40 C.F.R.
98.34(e)(1) be revised to state that "For initial certification, use one of the following procedures:"
Response: EPA agrees that the proposed language could be confusing, and has added language
to the final rule to clarify that any one of the alternate initial certification procedures for CO2
CEMS is acceptable.
Commenter Name: J. P. Blackford
Commenter Affiliation: American Public Power Association (APPA)
Document Control Number: EPA-HQ-OAR-2008-0508-0661.1
Comment Excerpt Number: 10
Comment: APPA has concerns about the sampling requirements in the Proposed Rule for
gaseous fuels other than natural gas. The daily carbon content sampling requirement seems
overly onerous and it is recommended that sampling requirements for these fuels be required
monthly, consistent with requirements for other fuels. APPA is concerned that a daily sampling
requirement could discourage the use of landfill gas a co-fire fuel within an existing natural gas
fired plant. Many times these projects have been marginal in the past, and additional regulatory
barriers can discourage innovation. A further concern is that the monthly sampling for other fuel
types might not provide any additional information to EPA. Some of the units operated by
APPA member utilities are utilized as peaking units and as such may not operate often, therefore,
monthly analysis would not be practical and overly burdensome. Many of our member utilities
receive fuel shipments less frequently than monthly, so it serves little purpose to require them to
sample fuel which will have the identical composition to the fuel that was sampled the previous
month since no new fuel was delivered. APPA also believes that the carbon content in the fuel
will have minimal variation from delivery to delivery thus minimizing the increase in accuracy
gained by requiring monthly sampling. APPA recommends that EPA lower the requirement for
sampling non-gaseous fuels to new deliveries rather than monthly in order to pinpoint the onset
of fuel parameter variations.
Response: EPA acknowledges the commenter's concerns. Large units burning natural gas or
distillate oil may not use Tier 2 instead of Tier 3. Section 98.34 has been revised to require that
natural gas be sampled semiannually and, for other gaseous fuels, the daily sampling requirement
has been retained, but only for facilities with existing equipment in place that is capable of
providing the data. Otherwise, weekly sampling is required, which may be postponed in favor of
monthly sampling until 2011 if new equipment must be purchased or if existing equipment must
be upgraded to meet the weekly sampling and analysis requirements. CO2 emissions from
420
-------
landfill gas (biogas or captured methane) may be calculated using Tier 1, and default factors for
biogas has been added to Table C-2.
In addition, §98.34 has been revised for fuel oil and coal, such that a representative sampling is
required for each fuel lot, i.e., for each shipment or delivery. For other liquid fuels and biogas,
quarterly sampling is required. For other solid fuels, excluding municipal solid waste, weekly
composite sampling with monthly analysis is required.
The final rule clarifies that fuel sampling and analysis data provided by the supplier may be used
in the emission calculations, and that fuel billing meters may be used to quantify fuel
consumption. To simplify the emission calculations in Tiers 2 and 3, averaging of HHV and
carbon content data is permitted if these data are obtained at least at the minimum frequency
specified in §98.34. If the results of fuel sampling are received monthly or more frequently, the
weighted annual average high heat value shall be calculated using Equation C-2b. If the results
of fuel sampling are received less frequently than monthly, then the annual average HHV shall
be calculated using the arithmetic average HHV for all valid samples for the year. However,
regardless of the sampling frequency, the owner or operator must use the results of all available
valid fuel analyses in the emissions calculations.
Commenter Name: Robert D. Bessette
Commenter Affiliation: The Council of Industrial Boiler Owners (CIBO).
Document Control Number: EPA-HQ-OAR-2008-0508-0513.1
Comment Excerpt Number: 36
Comment: The requirements in §98.34, Monitoring and QA/QC, should be modified to provide
flexibility by allowing use of site specific fuel analysis values that would be more representative
of fuels combusted than the default values. Those site specific values could be available from
site samples and analyses or from supplier provided analyses on some frequency that is less
frequent than monthly.
Response: EPA has revised §98.34 to clarify that only the methods listed in that section may be
used for fuel sampling and analysis for Tiers 2 and 3, regardless of any other methods that are
incorporated in §98.7. The Agency believes that the methods listed in §98.34 of the final rule,
derived from §98.7, provide operators adequate flexibility for best practices.
Commenter Name: Robert D. Bessette
Commenter Affiliation: The Council of Industrial Boiler Owners (CIBO).
Document Control Number: EPA-HQ-OAR-2008-0508-0513.1
Comment Excerpt Number: 37
Comment: In §98.34(d)(3), combustion of gaseous fuels other than natural gas (e.g., refinery
gas, or process gas) needs to use Tier 3 unless a CEMS is used for Tier 4. This paragraph
indicates (as does the Preamble at 16484) that daily sampling and analysis is required to
determine carbon content and molecular weight of the fuel. The Preamble notes that "The daily
fuel sampling requirement for units that combust 'other' gaseous fuels would likely not be overly
burdensome, because the types of facilities that burn these fuels are likely to have equipment
421
-------
(e.g., on-line gas chromatographs) to continuously monitor the fuels' characteristics in order to
optimize process operation." 74 FR 16484. While this is the case for some particular off-gas
streams, it is definitely not the case for all process gases, and those with monitoring might
require considerable cost to upgrade for this purpose. This requirement could impose an
exorbitant and totally unjustified cost on facilities.
If such sampling and analytical equipment is not installed, it should be acceptable to use typical
analytical or engineering data to determine the analysis. Additionally, if a process gas stream
contains less than 25% carbon by weight as demonstrated by engineering or model analysis, that
initial demonstrated value should be considered adequate for ongoing emissions determinations.
Moreover, if the process gas stream does not contain significant carbon content (< 10% by
weight), there should be no need for any reporting for those process gas streams providing
documentation is retained supporting that position.
Response: EPA acknowledges and appreciates the commenter's concerns. In the final rule
concerning other gaseous fuels, §98.34 has been revised to retain the daily sampling requirement,
but only for facilities with existing equipment in place that is capable of providing the data.
Otherwise, weekly sampling is required, which may be postponed in favor of monthly sampling
until 2011 if new equipment must be purchased or if existing equipment must be upgraded to
meet the weekly sampling and analysis requirements.
In addition, the final rule clarifies that fuel sampling and analysis data provided by the supplier
may be used in the emission calculations, and that fuel billing meters may be used to quantify
fuel consumption. To simplify the emission calculations in Tiers 2 and 3, averaging of HHV and
carbon content data is permitted if these data are obtained at least at the minimum frequency
specified in §98.34. If the results of fuel sampling are received monthly or more frequently, the
weighted annual average high heat value shall be calculated using Equation C-2b. If the results
of fuel sampling are received less frequently than monthly, then the annual average HHV shall
be calculated using the arithmetic average HHV for all valid samples for the year. However,
regardless of the sampling frequency, the owner or operator must use the results of all available
valid fuel analyses in the emissions calculations.
Commenter Name: Burl Ackerman
Commenter Affiliation: J. R. Simplot Company
Document Control Number: EPA-HQ-OAR-2008-0508-1641
Comment Excerpt Number: 14
Comment: The rule requires periodic on-site sampling and analysis of fuels. We recommend
requiring fuel suppliers perform the analysis and provide individual sources the required
information on billing statements, rather than having every individual source performing the
same analysis on the same fuel.
Response: Though EPA has not required fuel suppliers to provide fuel analysis data to
customers, the final rule clarifies that fuel sampling and analysis data provided by the supplier
may be used in the Subpart C emission calculations. Subpart KK, Suppliers of Coal, has not
been included in this final rule. Subpart MM, Suppliers of Petroleum Products, and Subpart NN,
Suppliers of Natural Gas, provide upstream reporters with the option of using default HHV and
carbon contents or site specific sampling. EPA has not required fuel suppliers to provide HHV
422
-------
data to facilities, as provision of this type of information is typically addressed in private sector
purchase contracts.
Commenter Name: Steven J. Rowlan
Commenter Affiliation: Nucor Corporation (Nucor)
Document Control Number: EPA-HQ-OAR-2008-0508-0605.1
Comment Excerpt Number: 45
Comment: In 98.34(a), the term "detailed explanation" should be left out. The documents
should show how the calculations are made.
Response: EPA has revised the final rule, and now in §98.34(e) requires an "explanation" when
requested, and also requires "sufficient" data for emission verification. EPA believes that it is
appropriate to require reporters to retain records containing an explanation of how company
records are used to estimate fuel consumption, sorbent usage, and/or quantity of steam generated.
EPA expects that an explanation of how company records are used to estimate these parameters
would show how the relevant calculations are made.
Commenter Name: Steven J. Rowlan
Commenter Affiliation: Nucor Corporation (Nucor)
Document Control Number: EPA-HQ-OAR-2008-0508-0605.1
Comment Excerpt Number: 46
Comment: In 98.34(b), Most sources, particularly smaller sources, will have no capability of
explaining the "technical basis" for estimated accuracy statements, but must simply rely upon the
manufacturer's or calibrator's statement. It is not clear why EPA would need more.
Response: EPA refers commenter to §98.34(g) where the final text describing this requirement
appears. As described, the GHG Monitoring Plan required under §98.3(g)(5) must document the
procedures used to ensure the accuracy of the parameters used to quantify emissions (e.g., fuel
usage, steam production, etc.). EPA believes it is appropriate to require reporters to document
the technical basis for the estimated accuracy of measurements, and has retained this requirement
in the final rule as described in this section.
Commenter Name: Steven J. Rowlan
Commenter Affiliation: Nucor Corporation (Nucor)
Document Control Number: EPA-HQ-OAR-2008-0508-0605.1
Comment Excerpt Number: 47
Comment: Section 98.34(d)(1) should provide an allowance for replacement as well as
recalibration.
Response: EPA does not believe that any further language is necessary to clarify that fuel flow
meters may be replaced, so long as the replacement meter is calibrated according to the
specifications of the rule.
423
-------
Commenter Name: Sarah E. Amick
Commenter Affiliation: The Rubber Manufacturers Association (RMA)
Document Control Number: EPA-HQ-OAR-2008-0508-0647.1
Comment Excerpt Number: 12
Comment: RMA recommends that the greenhouse gas emission factors utilized in the proposed
rule be consistent with the factors used by the World Business Council for Sustainable
Development (WBCSD) and in congressional legislation. Currently, the proposed rule uses
different methods for calculating greenhouse gas emissions than the method used by the World
Business Council. (See Table 1 in DCN:EPA-HQ-OAR-2008-0508-0647.1) Because
greenhouse gas emissions are a global issue, we support consistency in the emission factors and
methods that are used in all U.S. greenhouse gas regulations. As global companies, RMA
member companies, particularly in the tire industry, utilize the international greenhouse gas
emission factors as established by the WBCSD to report GHG emissions from facilities
corporate-wide. Since greenhouse gas emissions are a global issue, it is important for companies
and governments to be able to compare data and track progress across different geographic
regions. Without a single, unified set of emission factors, data reported under different reporting
requirements would not be comparable and would not be appropriately used to establish trends or
benchmark progress globally. Since global companies already use WBCSD emission factors
successfully to calculate and report GHG emissions, we recommend that all data collected prior
to congressional legislation should be calculated based on the WBCSD emission factors. We
understand that pending legislation also provides GHG emission factors. While outside the
scope of this NPRM, RMA also supports the use of the WBCSD emission factors in the
legislative context. [See DCN:EPA-HQ-OAR-2008-0508-0647.1 for table showing Examples of
differences between the NPRM and the World Business Council Emissions Factors]
Response: EPA is not aware of pending legislation that has emission factors for unit-level
reporting of greenhouse gas emission. Additionally, EPA can not consider detailed data in
specific pieces of draft legislation as the requirements may change if and when bills are passed
by Congress and signed into law by the President. EPA does not agree that there should be a
single unified set of emission factors across all reporting programs because the legal foundation
and policy goals of programs differ, particularly across regions and countries. Nevertheless,
EPA has extensively reviewed the default emission factors and high heat values provided in
Subpart C of the final rule, and believes that they are appropriate and, to the extent possible,
consistent with those used in other programs. Please see the Technical Support Document for
Subpart C.
Commenter Name: Rich Raiders
Commenter Affiliation: Arkema Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-0511.1
Comment Excerpt Number: 33
Comment: EPA should add language to Subpart C of Part 98 to add the appropriate language to
address regulatory overlaps with any 40 CFR 63 Subpart including performance test monitoring
verification plans, site-specific monitoring plans, and precompliance reports. This section should
424
-------
specify that the specific MACT-required monitoring provisions override Part 98, as approved by
the appropriate permitting authority. EPA correctly limited the applicability of the proposed Part
98 to those regulations requiring compliance with 40 CFR 60.13(a)(2), 61.14(a)(2), and
63.8(a)(2). EPA should clarify that the potential applicability to the proposed 40 CFR 63
Subpart SS modifications in this proposal conforms to the intent shown in Tables 1 and 2 of the
proposal preamble. Arkema recognizes that, in December 2008, the District of Columbia Court
of Appeals has vacated the MACT startup, shutdown, and malfunction program in 40 CFR 63.
The entire concept of how facilities manage process upsets, breakdowns, and equipment failures
with the MACT program is currently in flux. EPA should await further developments in this
litigation and coordinate this rule with the agency's next steps to manage the ongoing litigation
response. Many of the process units that will become subject to Part 98 already comply with
CAM, and others comply with one or more MACT standards described above. Instead of EPA
promulgating subpart-by-subpart data handling provisions in Part 98, EPA should, as a Part 98
general provision, require that regulated entities either utilize the MACT missing data approach
in 40 CFR 63 Subpart SS, the CAM data management approach at 40 CFR 64, comply with a
streamlined Part 98-specific approach, or provide a site-specific precompliance report described
next, as the facility's data management approach. As some units may fall under different
portions of this analysis, a reporter could use missing data approaches including one or all of
these methods.
Response: The commenters statement that "EPA correctly limited the applicability of the
proposed Part 98 to those regulations requiring compliance with 40 CFR 60.13(a)(2),
61.14(a)(2), and 63.8(a)(2)" is not correct.
EPA appreciates the comment, though EPA's approach makes use of existing data and
methodologies to the extent feasible, and is consistent with the types of methods contained in
other GHG reporting programs (e.g., the California mandatory reporting rule, WCI, RGGI, TCR,
and Climate Leaders). It is also noted that MACT does not measure GHG emissions and, unlike
the GHG reporting rule which is focused on collecting information on GHG emissions, the
MACT program is a compliance program aimed to meet specific emission limits for toxic air
pollutants.
Commenter Name: Karen St. John
Commenter Affiliation: BP America Inc. (BP)
Document Control Number: EPA-HQ-OAR-2008-0508-0631.1
Comment Excerpt Number: 66
Comment: Section 98.34(d)(1) of Subpart C, Section 98.254(a) of Subpart Y, and elsewhere
through out the monitoring and QA/QC requirements of the proposed rule states flow meters
would have to be calibrated by January 1, 2010. This requirement is technically impossible to
meet due to the number of flow meters at facilities, coupled with the projected finalization of the
reporting rule in November of 2009. Also, some instrumentation may require maintenance that
prevents calibration, where such maintenance cannot be conducted until a shutdown. BP does
not believe EPA would or should require a shutdown of a facility to calibrate these instruments.
For meters and instrumentation which cannot be calibrated or verified without a facility or unit
shut-down, BP requests an exemption from a calibration compliance date and a provision for
425
-------
them to be calibrated or verified during the next scheduled turn around using good
manufacturing practices.
Response: See the response to comment EPA-HQ-OAR-2008-0508-1142.1 excerpt 26 for
information on additional flexibility provided for 2010. The commenter should refer to §98.3 of
the final rule for calibration procedures required under the rule. Per this section, flow meters
measuring data used to calculate emissions shall be calibrated prior to April 1, 2010 using
procedures specified in the section. For the continuously-operating units and processes
described in §98.34, the required flow meter and PEI recalibrations may be postponed until the
next scheduled maintenance outage.
426
-------
7.
PROCEDURES FOR ESTIMATING MISSING DATA
Commenter Name: Lorraine Krupa Gershman
Commenter Affiliation: American Chemistry Council (ACC)
Document Control Number: EPA-HQ-OAR-2008-0508-0423.2
Comment Excerpt Number: 67
Comment: We recommend that EPA modify §98.35 to allow the 3best available estimate'
method of §98.35(2) to be available for all parameters including those listed in §98.35(1), not
just the limited parameters listed in §98.35(2), if the owner or operator can justify using it based
on process or operating knowledge. There may be times when the arithmetic averaging method
does not yield an appropriate result, given variations in operating conditions.
Response: See the Preamble, Section III. C., for the response on Procedures for Estimating
Missing Data.
EPA believes that the missing data substitution procedures discussed in detail in §98.35(b) of the
final rule have been simplified. Revisions to §98.35(b)(1) limit the requirement of using the
"before and after" average for substitute data to three parameters, i.e., fuel, carbon content, and
molecular weight. If the "after" value is not yet available when the GHG emissions report is due,
the "before" value may be used for missing data substitution. For all other parameters, the
substitute data values are the best available estimates, based on all available process information.
EPA has determined that this additional flexibility allows for the use of the "best available
estimate" method for missing data substitution for all appropriate parameters and yields the most
accurate results for the purposes of substituting missing data under Part 98.
Commenter Name: Lloyd Stone
Commenter Affiliation: Westlake Chemical Corporation
Document Control Number: EPA-HQ-OAR-2008-0508-0442.1
Comment Excerpt Number: 7
Comment: Are there potential penalties for missing data? The missing data substitution
requirements in §98.35 are prescriptive and are not always consistent with the design of many
existing CEMS installations. Westlake has facilities that are subject to NSPS requirements that
only require collection of valid data for a specified percentage of the facility operating hours.
The NSPS standards do not impose substitution requirements for missing data, and neither
should this rule.
Response: See the Preamble, Section II. O., for the response on the relationship of this rule to
other programs.
Please see Preamble Sections II. L. and VI. and response to comments documents "Approach to
Verification and Missing Data" and "Compliance and Enforcement" for more information about
EPA's missing data requirements and approach to compliance and enforcement.
The substitution requirements discussed in detail in §98.35 have been simplified in the final rule
for all units that are not subject to the requirements of the Acid Rain Program. First, revisions to
427
-------
§98.35(b)(1) limit the use of the "before and after" average for substitute data to three
parameters, i.e., fuel HHV, carbon content, and molecular weight. If the "after" value is not yet
available when the GHG emissions report is due, the "before" value may be used for missing
data substitution. For all other parameters, the substitute data values are the best available
estimates, based on all available process information. EPA believes that the provisions for
estimating missing data in the final rule will yield the appropriate results without imposing
excessive financial burdens.
Commenter Name: Janice Adair
Commenter Affiliation: Western Climate Initiative (WCI)
Document Control Number: EPA-HQ-OAR-2008-0508-0443.1
Comment Excerpt Number: 12
Comment: WCI recommends that the reporting rule include a provision for minimum data
collection and procedures for approving interim data collection during equipment breakdowns at
general stationary fuel combustion sources. The proposed rule would require the reporter to
document and keep record of the procedures used to determine the appropriate substitute data
values. However, it does not appear to provide an acceptable limit for missing fuel analytical or
direct measurement data. A potentially very significant percentage of required data might be
declared "missing" and replaced with questionable data. A regulatory incentive to limit missing
data is needed. We agree that the accuracy of an emissions data set is important.
Response: See the individual source category section(s) of the Preamble and the source
category comment response document(s) for the response on the source category-specific
monitoring and reporting requirements.
EPA has not included a specific limit for missing fuel analytical or direct measurement data
because the Clean Air Act already provides avenues for enforcement, and provides EPA some
discretion in working with facilities that have difficulty complying with the provisions of the
rule. Please see Preamble Sections II. L., and VI. and response to comments documents
"Approach to Verification and Missing Data" and "Compliance and Enforcement" for more
information about EPA's missing data requirements and approach to compliance and
enforcement.
Commenter Name: Stephen E. Woock
Commenter Affiliation: Weyerhaeuser Company
Document Control Number: EPA-HQ-OAR-2008-0508-0451.1
Comment Excerpt Number: 13
Comment: Weyerhaeuser agrees with and supports EPA's proposed approach at §98.35 to
handle missing data. Missing data is the use of substitute data whenever a quality assured value
of a parameter that is used to calculate GHG emissions is unavailable. Weyerhaeuser agrees it is
important to have missing data procedures to ensure a complete and accurate report of emissions.
For units using the CO2 calculation methodologies in Tiers 2 and 3, when Higher Heating Value
(HHV), fuel carbon content, or fuel usage data are missing, EPA proposes the substitute data
428
-------
value would be the average of the quality-assured values of the parameter immediately before
and immediately after the missing data period. When Tier 3 or Tier 4 is used and fuel flow rate
or stack gas flow rate data is missing, the substitute data values would be the best available
estimates of these parameters, based on process and operating data (e.g., production rate, load,
unit operating time, etc.). Using the data before and after the missing data event represents the
most accurate, statistically sound and representative approach to estimating this missing data.
Response: EPA appreciates the commenter's input regarding the missing data substitution
procedures in §98.35, which have been clarified and simplified in the final rule.
Commenter Name: Paul R. Pike
Commenter Affiliation: Ameren Corporation
Document Control Number: EPA-HQ-OAR-2008-0508-0487.1
Comment Excerpt Number: 15
Comment: Part 75 missing data procedures become increasingly more conservative based on
the length of the missing data period and the overall data availability in the prior year (or since
certification of the monitoring system). When significant amounts of data are declared "invalid"
under Part 75, the procedure can require substitution of "maximum potential" values that may
have little or no relationship to actual values. This most often occurs when a source discovers
(usually as a result of a self-audit) long after a test was performed, or was due, that the test result
was in error or that the test was not performed. In such cases, use of missing data procedures
may not be the best estimate of actual emissions. EPA should allow the use of procedures like
those provided for other stationary combustion units under proposed §98.35 when Part 75
missing data procedures become overly conservative or punitive. We suggest the addition of a
new section that provides for reporting of cumulative CO2 emissions based on data reported
under §75.64, with the exception that the procedures in §98.35(b) may be used to substitute for
missing data whenever data availability falls below 90 percent as calculated under §75.32, or
whenever the Part 75 procedures call for use of a "maximum" or "maximum potential" value.
Response: See the Preamble, Section II. L., for EPA's response to comments on estimating
missing data.
Nearly all Part 75 sources maintain very high monitor data availability (95 percent or better) and
use very little substitute data. Only when the data availability drops below 80 percent (which
very seldom occurs) are the substitute data values significantly higher than the true CO2
concentrations. In response to the comments, the Agency believes that the potential bias in
existing Part 75 methods based on data availability is acceptable versus the complexity of having
Acid Rain Program EGUs calculate two different sets of CO2 emissions data based on different
missing data routines. Also, because data availability in the Acid Rain Program is very high,
over reporting due to data substitution will be minimal, and not at a level that would warrant
requiring all Acid Rain Program sources to prepare, record, and report two sets of missing data
calculations. Therefore, sources that monitor CO2 emissions according to Part 75 should
continue to use the standard Part 75 missing data provisions, and no adjustments to these
substitute data values are deemed necessary for Part 98 reporting purposes.
429
-------
Commenter Name: Angela Burckhalter
Commenter Affiliation: Oklahoma Independent Petroleum Association (OIPA)
Document Control Number: EPA-HQ-OAR-2008-0508-0386.1
Comment Excerpt Number: 18
Comment: EPA proposes that within 7 days of receipt of written request (e.g., a request by
electronic mail) from the EPA or applicable State or local air pollution control agency, the owner
or operator shall submit calculation methodologies and documents that ensure the accuracy of
the data. Company personnel may be on vacation, sick or other types of leave that would
prevent a company from responding within 7 days. This is too short a time frame. Reporting
entities should have at least 30 days to respond. In addition, the request should also be sent to
the company in the form of a formal letter sent in the mail.
Response: EPA acknowledges the commenter's concerns. In §98.36(e)(3) of the final rule, EPA
has allowed owners or operators 30 days from receipt of a written request for information to
respond to that request.
EPA does not believe that it is necessary to specify that requests for data submissions be made
via hard copy mail. EPA believes that electronic requests are sufficiently reliable.
Commenter Name: Robert P. Strieter
Commenter Affiliation: The Aluminum Association
Document Control Number: EPA-HQ-OAR-2008-0508-0350.1
Comment Excerpt Number: 5
Comment: Section 98.35 of the proposed rule outlines reporting requirements for missing data,
such as during continuous emission monitor system (CEMS) malfunction or missing fuel
samples, whereby substitute data are used. The approach proposed includes some criteria related
to facilities currently regulated under the Acid Rain Program and thereby applicable in general
only to electric utilities. The rest of the criteria are for a short list of relevant sources and
categories of reporting information that is deficient in scope and is unclear. We recommend that
the proposal be revised to incorporate existing missing data methods included under current
Clean Air Act programs such as for the Title V permitting and reporting program. Facilities
would then follow existing procedures included in their respective permitting provisions to
provide missing data.
Response: See the Preamble, Section II. O., for the response on the relationship of this rule to
other programs.
EPA acknowledges the concerns of the commenters. Section 98.35(a) has been revised to add
flexibility and to simplify the missing data substitution procedures for units that use the Tier 1,
Tier 2, Tier 3, and Tier 4 Calculation Methodologies. In response to the comment, all relevant
reporting programs were considered in the development of this rule, and the approach selected
was based on balancing data accuracy and cost for the facilities subject to these requirements.
The use of existing data and methodologies was incorporated to the extent feasible to achieve the
intended purpose of this rule, as discussed in detail in the Preamble. The source category-
430
-------
specific reporting requirements and methodologies for calculating substitute data values, as
applicable, for each source category are addressed in the appropriate subpart.
Commenter Name: Paul L. Carpinone
Commenter Affiliation: Tampa Electric Company (TECO)
Document Control Number: EPA-HQ-OAR-2008-0508-0717.1
Comment Excerpt Number: 11
Comment: Tampa Electric agrees with the EPA's decision that over conservative missing data
procedures are inappropriate because they could result in significant overestimation of GHG
emissions. Thus, Tampa Electric supports EPA's proposal methods for determining substitute
data values previously mentioned in Subpart C.
Response: EPA appreciates the commenter's input regarding the missing data substitution
procedures for Subpart C in §98.35, which have been clarified and simplified in the final rule.
Commenter Name: See Table 6
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0679.1
Comment Excerpt Number: 114
Comment: §98.37. References to §98.35(a)(1) and §98.35(a)(4) should be changed to §98.35,
as §98.35(a) does not have subdivisions.
Response: EPA has corrected this error. Section 98.37 now refers to §98.35(b).
Commenter Name: Robbie LaBorde
Commenter Affiliation: CLECO Corporation (CLECO)
Document Control Number: EPA-HQ-OAR-2008-0508-1566
Comment Excerpt Number: 6
Comment: In Subpart D, section 98.45 of MRGG, under the title of Procedures for Estimating
Missing Data, it is required that electrical generating units subject to the Acid Rain Program use
missing data substitution procedures in 40 CFR Part 75. This is a conservative missing data
substitution procedure and was intended to insure that SO2 emissions were not under-reported.
Cleco does not feel that such conservative SC>2-based procedures are appropriate for CO2
emission calculations. In that program, if CEMS data is missing, data is substituted on a sliding
scale based on monitor data availability and is appropriate where hourly SO2 emissions could be
variable. However, this method is not necessary for CO2 emissions where hourly variation is not
significant. In addition, assuming that MRGG might some day be used in an allowance trading
program, the high bias that would result from the conservative Part 75 data substitution methods
for calculating CO2 emissions would be significantly more costly than the overestimation of SO2
emissions. Therefore, EPA should adopt data substitution procedures for acid rain affected units
431
-------
that are more appropriate for C02 emissions. For instance, EPA is urged to allow the option of
use of data substitution procedures under Subpart D that are similar to those required under
Subpart C of MRGG. Also, it is recommended that the Agency allow for acid rain affected units
the option to use fuel consumption data to estimate missing data for longer time periods. For
example, since there is limited variability in the carbon content of coal, a facility could be
allowed to calculate CO2 emissions based on carbon content measurements and the amount of
fuel burned.
Response: As stated in the Preamble, Section III. C., EPA does not agree that the substitute data
procedures in Part 75 are too conservative. Nearly all Part 75 sources maintain very high
monitor data availability (95 percent or better) and use very little substitute data. Only when
data availability drops below 80 percent (which seldom occurs) are the substitute data values
significantly higher than the true C02 concentrations. Therefore, the Agency believes that the
potential for bias in the Part 75 CO2 data is very small. It is vastly preferable for Acid Rain
Program EGUs to calculate and report C02 emissions in a consistent manner, rather than having
them report two different sets of CO2 emissions data based on different missing data routines.
Sources that monitor C02 emissions according to Part 75 should continue to use standard Part 75
missing data provisions, and no adjustments to these substitute data values are deemed necessary
for Part 98 reporting purposes.
Commenter Name: Renae Schmidt
Commenter Affiliation: CITGO Petroleum Corporation
Document Control Number: EPA-HQ-OAR-2008-0508-0726.1
Comment Excerpt Number: 13
Comment: CITGO agrees that for missing flow rate records, the substitute value should be the
best available estimate based on available process data or on the arithmetic average of the
parameter immediately preceding and immediately following the missing data.
Response: EPA appreciates the commenter's input regarding the missing data substitution
procedures in §98.35, which have been clarified and simplified in the final rule.
Commenter Name: See Table 3
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0433.2
Comment Excerpt Number: 22
Comment: The missing data substitution requirements of the proposed rule at §98.35 are
prescriptive and are not always consistent with the design of many existing CEMs installations.
For facilities subject to 40 CFR part 75 requirements, this requirement is generally consistent
with that regulation. However, numerous other EPA requirements that mandate the use of CEMs
systems require collection of valid data only for a specified percentage of the facility operating
hours. These CEMs, typically required by NSPS, do not impose substitution requirements for
missing data. Therefore, the owners of many of these CEMs installations that become subject to
these proposed rules, including most of those in petroleum refineries, will be required to upgrade
432
-------
the data processing software for each CEMs unit in order to implement the specified data
substitution procedures. This upgrade is often not a trivial matter, because these software
packages are usually highly customized to each source and the associated permit and regulatory
reporting requirements. In some cases, making this change to the data processing procedures in
order to implement the missing data substitution requirements of proposed part 98 could require
purchase and installation of a completely new data processing system at a cost far exceeding the
estimated facility costs to comply. Therefore, installation of CEMs should be at the discretion of
each company.
Response: EPA disagrees with the commenter's proposal that installation of CEMs should be at
the discretion of each company. See the Preamble, Section II. L., for the response on the general
monitoring approach, and Preamble, Section II. C., for additional information on the
applicability of Tiers.
See the Preamble, Section II. O., for the response on the relationship of this rule to other
programs. See the individual source category section(s) of the Preamble and the source category
comment response document(s) for the response on source category-specific reporting
requirements in Subparts C through PP.
EPA acknowledges the concerns of the commenters and agrees that upgrading data processing
software solely for the purposes of obtaining substitute values for missing data would be unduly
burdensome. However, for this mandatory GHG reporting program, the Agency concluded that
provisions for missing data procedures are necessary in order to ensure there is a complete report
of emissions from a particular facility. The substitution requirements discussed in detail in
§98.35 have been simplified in the final rule for all units that are not subject to the requirements
of the Acid Rain Program. First, revisions to §98.35(b)(1) limit the use of the "before and after"
average for substitute data to three parameters, i.e., fuel HHV, carbon content, and molecular
weight. If the "after" value is not yet available when the GHG emissions report is due, the
"before" value may be used for missing data substitution. For all other parameters, the substitute
data values are the best available estimates, based on all available process information. EPA
believes that the provisions for estimating missing data in the final rule will yield the appropriate
results without imposing excessive financial burdens.
Commenter Name: Robert Rouse
Commenter Affiliation: The Dow Chemical Company
Document Control Number: EPA-HQ-OAR-2008-0508-0533.1
Comment Excerpt Number: 25
Comment: EPA Should Provide Additional Flexibility for Procedures for Estimating Missing
Data. EPA should modify 98.35 to allow the "best available estimate" method in 98.35(b)(2) to
be available for all parameters including the parameters listed in 98.35(b)(1), not just the limited
parameters listed in 98.35(b)(2), if the owner or operator can justify using it based on process or
operating knowledge. There may be times when the arithmetic averaging method does not yield
an appropriate result, given variations in operating conditions.
Response: See the Preamble and Procedures for Estimating Missing Data section of the
Preamble.
433
-------
EPA has simplified the missing data substitution procedures discussed in detail in §98.35(b) of
the final in a way that addresses the concerns raised by the commenter. Revisions to
§98.35(b)(1) limit the requirement of using the "before and after" average for substitute data to
three parameters, i.e., fuel, carbon content, and molecular weight. If the "after" value is not yet
available when the GHG emissions report is due, the "before" value may be used for missing
data substitution. For all other parameters, the substitute data values are the best available
estimates, based on all available process information. EPA has determined that this additional
flexibility allows for the use of the "best available estimate" method for missing data substitution
for all appropriate parameters and yields the most accurate results for the purposes of substituting
missing data under Part 98.
Commenter Name: Lauren E. Freeman
Commenter Affiliation: Hunton & Williams LLP
Document Control Number: EPA-HQ-OAR-2008-0508-0493.1
Comment Excerpt Number: 28
Comment: Although UARG also generally does not object to a rule that allows ARP affected
sources to use Part 75 missing data provisions to report C02, there are some circumstances under
which use of those procedures may not be appropriate. In order to create incentives for high data
availability, Part 75 missing data procedures become increasingly conservative based on the
length of the missing data period and the overall data availability in the prior year (or since
certification of the monitoring system). See, e.g., 40 C.F.R. §§75.35 - 75.36 and Appendix D
§2.4.2 (heat input). In cases where significant amounts of data are declared "invalid" under Part
75, the procedure can require substitution of "maximum potential" values that may have little or
no relationship to actual values. This most often occurs when a source discovers (usually as a
result of a self-audit) long after a test was performed, or was due, that the test result was in error
or that the test was not performed. In such cases, use of missing data procedures may not be the
best estimate of actual emissions. To make the CO2 reporting requirements for EGUs more
consistent with the reporting requirements for other sources, EPA should allow the use of
procedures like those provided for other stationary combustion sources under proposed §98.35
when Part 75 missing data procedures become overly conservative or punitive. UARG does not
believe it is reasonable to require Part 75 sources to report dramatically overstated emissions
when other source categories, including stationary combustion sources, are not required to do so.
To implement this concept, UARG suggests addition of a new section that provides for reporting
of cumulative CO2 emissions based on data reported under §75.64, with the exception that the
procedures in §98.35(b) may be used to substitute for missing data whenever monitor data
availability calculated under Part 75 falls below 90 percent as calculated under §75.32, or
whenever the Part 75 procedures call for use of a "maximum" or "maximum potential" value.
Response: See the Preamble, Section III. C., the Subpart D comment response document
volume, and the response to comment EPA-HQ-OAR-2008-0508-0956.1 excerpt 20 for the
rationale for using substitute data reported under Part 75.
Part 75 missing data procedures are designed to provide conservatively high substitute data
values, to ensure that emissions are not underestimated during monitor outages. The missing
data algorithms also become increasingly conservative (biased towards higher emissions) as
434
-------
monitor downtime increases, so that sources have an incentive to maintain high data availability.
Nearly all Part 75 sources maintain very high monitor data availability (95 percent or better) and
use very little substitute data. Only when the data availability drops below 80 percent (which
very seldom occurs) are the substitute data values significantly higher than the true CO2
concentrations. Therefore, the Agency believes that the potential for bias in the Part 75 C02 data
is very small. It is vastly preferable for Acid Rain Program EGUs to calculate and report CO2
emissions in a consistent manner, rather than having them report two different sets of C02
emissions data based on different missing data routines. Sources that monitor CO2 emissions
according to Part 75 should continue to use the standard Part 75 missing data provisions, and no
adjustments to these substitute data values are deemed necessary for Part 98 reporting purposes.
Commenter Name: See Table 6
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0679.1
Comment Excerpt Number: 113
Comment: [Page 16637] Sec. 98.35 Procedures for estimating missing data. API offers the
following revised language for this section's paragraph (b) at this time, (b) For all units that are
not subject to the requirements of the Acid Rain Program, when the Tier 1, Tier 2, Tier 3, or Tier
4 calculation is used, perform missing data substitution as follows for each parameter: (1) For
each missing value of the heat content, carbon content, or molecular weight of the fuel, and for
each missing value of C02 concentration and percent moisture, the substitute data value shall be
the quality-assured value of that parameter immediately preceding the missing data incident. If
the quality assured value immediately following the missing data incident is different by more
than ten percent of the preceding value, the arithmetic average of the quality-assured values of
that parameter immediately preceding and immediately following the missing data incident, shall
be used. If, for a particular parameter, no quality-assured data are available prior to the missing
data incident, the substitute data value shall be the first quality-assured value obtained after the
missing data period. (2) For missing records of stack gas flow rate, fuel usage, and sorbent
usage, the substitute data value shall be the best available estimate of the flow rate, fuel usage, or
sorbent consumption, based on all available process data (e.g., steam production, electrical load,
and operating hours). The owner or operator shall document and keep records of the procedures
used for all such estimates.
Response: See the Preamble, Section III. C., for EPA's response on estimating missing data.
EPA believes that the missing data substitution procedures discussed in detail in §98.35(b) of the
final rule have been simplified in a way largely consistent with the approach suggested by the
commenter. Revisions to §98.35(b)(1) limit the requirement of using the "before and after"
average for substitute data to three parameters, i.e., fuel HHV, carbon content, and molecular
weight. If the "after" value is not yet available when the GHG emissions report is due, the
"before" value may be used for missing data substitution. For all other parameters, the substitute
data values are the best available estimates, based on all available process information. EPA has
determined that this additional flexibility allows for the use of the "best available estimate"
method for missing data substitution for all appropriate parameters and yields the most accurate
results for the purposes of substituting missing data under Part 98.
435
-------
Commenter Name: See Table 4
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0455.1
Comment Excerpt Number: 20
Comment: Under Subpart C of the Proposal, stationary fuel combustion sources would be
required to use substitute data whenever a quality-assured value of a parameter that is used to
calculate GHG emissions is unavailable. The Class of'85 supports the Agency's proposed
methods for determining substitute data values under Subpart C of the Proposal. Specifically,
the Group agrees with EPA's decision that more conservative missing data procedures are
inappropriate because they could result in significant overestimation of GHG emissions. Further,
the Group believes that the Agency should consider using fuel consumption data as a data
substitution method when data is missing over longer periods of time.
Response: EPA appreciates the commenter's input regarding the missing data substitution
procedures in §98.35, which have been clarified and simplified in the final rule.
Commenter Name: Robert D. Bessette
Commenter Affiliation: The Council of Industrial Boiler Owners (CIBO)
Document Control Number: EPA-HQ-OAR-2008-0508-0513.1
Comment Excerpt Number: 48
Comment: There are missing data substitution requirements in the rule, however, there are no
data substitution requirements for industrial source CEMS, under Part 60, not Part 75. If EPA
wants data substitution, CIBO recommends use of emission factors as an alternative to the
proposed methods.
Response: See the Preamble, Section III. C., for EPA's response on estimating missing data.
EPA disagrees with the suggestion that emission factors be used for estimating missing data.
The missing data substitution procedures in §98.35, which have been clarified and simplified in
the final rule, would involve substituting just the missing values needed for Tier 4 rather than a
wholesale change in the methodology to an emission factor approach. This approach simplifies
EPA verification and provides for the minimal amount of substitute data. Additionally, The
NSPS monitoring does not specify substitute data in the same way as Part 75.
436
-------
8. DATA REPORTING REQUIREMENTS
Commenter Name: Keith Adams
Commenter Affiliation: Air Products and Chemicals, Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-1142.1
Comment Excerpt Number: 32
Comment: The proposed rule appears to require the source report its CEM S relative accuracy
test audit (RATA) results. It is not clear if EPA would be satisfied by a singular statement that
the CEMS passed or failed the RATA, or if the intent is to submit the entire RATA report which,
in addition to being many pages in length, often contains confidential business information. Air
Products Comment: Clarify that EPA does not want a source to submit its entire RATA report
and instead, will be satisfied with a singular statement that the RATA was conducted (by whom
and on what date) and the results of the RATA, as a pass/fail designation.
Response: EPA acknowledges the commenter's concerns, and has added additional language to
§98.36(e)(2)(iv)(E) and (F), clarifying that reporters are required to submit the dates and
summarized results of the QA tests (e.g., RATAs) performed during the reporting year. The rule
does not require facilities to submit detailed test run information or hard copy test reports.
Commenter Name: Lorraine Krupa Gershman
Commenter Affiliation: American Chemistry Council (ACC)
Document Control Number: EPA-HQ-OAR-2008-0508-0423.2
Comment Excerpt Number: 74
Comment: In §98.36(d)(l)(iv)(F), reporting RATA results is also overly burdensome. At most,
EPA should only require reporting the RATA as a pass/fail result. RATA results will need to be
reported for some other regulatory requirement for which the CEMS was installed, so the
additional reporting here is redundant. These reports will be available onsite in the records as a
result of other regulation, so there is no need to report or collect as part of this effort. Other
CEMS requirements do not require transmitting the RATA report, only to verify that the RATA
was done.
Response: EPA acknowledges the commenter's concerns, and has added additional language to
§98.36(e)(2)(iv)(E) and (F), clarifying that reporters are required to submit the dates and
summarized results of the QA tests (e.g., RATAs) performed during the reporting year. The rule
does not require facilities to submit detailed test run information or hard copy test reports.
437
-------
Commenter Name: Linda Farrington
Commenter Affiliation: Eli Lilly and Company (Lilly)
Document Control Number: EPA-HQ-OAR-2008-0508-0680.1
Comment Excerpt Number: 23
Comment: While we agree that C02, CH4, and N20 should be included in the calculation of
greenhouse gas emissions from the combustion of fossil fuels in boilers and generators, we
question the increased reporting burden required by reporting these separately. Only C02e
should be required to be reported. Additional calculations and fields will need to be included in
EPA's electronic reporting software, resulting in additional complexity and an increased
opportunity for data entry errors. Existing registries such as EPA Climate Leaders and Climate
Registry require reporting of only C02e; separate reporting of other individual Kyoto Protocol
gasses or additional global warming gasses is not required. Lilly recommends the EPA strive for
consistency with these other programs by requiring affected facilities to report GHG emissions
as C02e only.
Response: See the Preamble, Section II. O., for the response on the relationship of this rule to
other programs.
EPA has decided to retain in the final rule the requirement to report CH4 and N20 from
stationary combustion sources. Reporting of gases individually increases transparency, provides
EPA information on the emissions of specific gases within and across industries that may have
different mitigation approaches, provides researchers with needed information on the location of
emissions of specific gases that is essential for determining actual radiative forcing, and provides
overall transparency for the public. EPA's approach is consistent with other mandatory
programs, including CARB, the EU ETS, in addition to UNFCCC reporting.
Commenter Name: Keith A. Nagel
Commenter Affiliation: ArcelorMittal USA and Severstal North America
Document Control Number: EPA-HQ-OAR-2008-0508-0496.1
Comment Excerpt Number: 27
Comment: The ability to report for multiple units by measuring fuel throughput at a common
supply line under §98.36(c)(3) has particular potential to simplify reporting at complex facilities.
However, one minor adjustment would greatly enhance the (already substantial) value of this
alternative. As written, the common pipe approach assumes that all of the fuel transported will
be combusted. That is not always the case, particularly at complex steelmaking facilities. For
example, the ultimate common pipe for natural gas is the metered primary supply line where
natural gas is transferred from the selling utility to a steel plant. Ideally, the throughput at that
ultimate common pipe could be used to accurately determine C02 emissions by simple
multiplication using the published combustion factors for natural gas. However, not all of that
natural gas is combusted. Rather, a portion of that natural gas is added directly to blast furnaces
as a process reactant. C02 emissions from the portion of the total natural gas supply that is used
as an input to the steelmaking process will be separately measured as required by Subpart Q.
Thus, presuming this natural gas was combusted as part of common pipe reporting would lead to
double counting. This creates an obvious "catch 22": steel plants would be forced to choose
438
-------
between forgoing the most effective (utility meter) use of the common pipe rule or over-
reporting GHG emissions. That problem has a simple solution. EPA can expand the utility of
the common pipe rule by allowing sources to "deduct" properly metered amounts of fuel sent via
common pipe which are not combusted. That minor adjustment would reduce the compliance
burden substantially by allowing sources to move the common pipe location further upstream. At
the same time, this change would increase the accuracy of emissions reporting by eliminating
double counting. Similarly, sources should be allowed to deduct emissions associated with
combustion sources that use a different reporting methodology. For example, we are evaluating
use of the common pipe approach to aggregate the emissions associated with a variety of units
that combust coke oven gas. The ideal common pipe location for calculating coke oven gas
emissions would be immediately downstream of the coke plant, where coke oven gas is
generated. That approach, however, would pose a double counting concern analogous to the one
described above. For example, the sintering operation at ArcelorMittal's Burns Harbor facility
combusts coke oven gas. To comply with Subpart Q at the sinter plant, ArcelorMittal is
evaluating the potential installation of a C02 CEMS. Using the common pipe approach to coke
oven gas combustion and a CO2 CEMS at the sintering plant would cause Burns Harbor to report
the C02 created from sintering coke oven gas combustion twice. As above, this inaccuracy can
be corrected by simply allowing sources to deduct emissions covered under any alternate
reporting approach from their common pipe numbers.
Response: See the Preamble, Section II. L., for the response on the general monitoring
approach.
EPA acknowledges the commenter's concerns, and has addressed this issue in the final rule.
Section 98.36(c)(3) states: If a portion of the fuel measured at the common pipe is diverted to a
chemical or industrial process where it is used but not combusted, provided that the amount of
fuel diverted is also measured with a calibrated flow meter, you may subtract out the diverted
fuel from the fuel measured at the common pipe prior to performing the GHG emissions
calculations."
Commenter Name: Leslie Bellas
Commenter Affiliation: National Lime Association (NLA)
Document Control Number: EPA-HQ-OAR-2008-0508-0520.1
Comment Excerpt Number: 28
Comment: Because lime plants typically do not generate steam, they cannot report steam
generated from MSW combustion or the design rated steam output capacity, as required by 40
C.F.R. §98.36(d)( 1 )(ii)(F). Revise 40 C.F.R. §98.36(d)(l)(ii)(F) to apply only to those facilities
that generate steam from MSW combustion.
Response: EPA has revised the rule so that Tier 1 may be used for a unit burning municipal
solid waste that does not produce steam, provided that Tier 4 is not required. A default CO2
emission factor and heat content for municipal solid waste has been added to Table C-l for this
purpose. Also in the final rule, you are to report CH4 and N2O emissions only for the
combustion of fuels for which appropriate default emission factors are provided in Table C-2
(formerly C-3). Default factors for municipal solid waste are not provided in the revised Table
C-2, therefore reporting of CH4 and N2O emissions is not required.
439
-------
Commenter Name: Keith Adams
Commenter Affiliation: Air Products and Chemicals, Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-1142.1
Comment Excerpt Number: 28
Comment: The proposed rule requires calculation and reporting of GHG emissions at the "unit-
level" (unless the aggregation options of §98.36(c) are employed). Reporting emissions at the
unit-level goes beyond the policy development intention of the reporting rule and increases the
risk that confidential business information (operating rates, fuel choices, operating efficiencies)
could be revealed in reports accessible to domestic and international competitors and customers
of the regulated source. Air Products Comment: Emission reporting should be required at the
facility-level only by source type. Reporting at the unit-level should not be required.
Additionally, provisions to protect the confidentiality of all process, production and business-
related information required under the rule should be strengthened. While Air Products accepts
that facility-level emissions cannot be protected from public disclosure, it strongly requests all
other information should, by default, be considered confidential business information and
afforded the utmost protection from public disclosure.
Response: See the Preamble, Section II. R., for EPA's response on CBI.
See the Preamble and the response to comment EPA-HQ-OAR-2008-0508-0520.1 excerpt 16 for
the rationale for the level of reporting and the additional flexibility provided to reporters,
particularly for common pipe and aggregated unit circumstances.
Some potential programs under the Clean Air Act including NSPS, are applied at more
disaggregated level than the overall facility. Because the main purpose of the rule is to collect
information for climate policy development under the CAA, EPA views unit level reporting as
appropriate. Additionally, EPA has decided to serve the role as verifier rather than require third-
party verification. In view of this, additional unit-level information is deemed necessary to
provide assurance that the reported facility-wide GHG emissions data are both credible and
accurate.
Commenter Name: Keith A. Nagel
Commenter Affiliation: ArcelorMittal USA and Severstal North America
Document Control Number: EPA-HQ-OAR-2008-0508-0496.1
Comment Excerpt Number: 28
Comment: Section 98.36(c)(1) allows the aggregation of "two or more units" for reporting
purposes but limits aggregation to sources with a "combined maximum rated heat input capacity
of 250 mmBtu/hr or less." That 250 mmBtu/hr limit may be suitable for small facilities which
have a limited number of small units to aggregate. However, it is not suitable for large, complex
sources with many small sources that can be efficiently aggregated for reporting. Two promising
alternatives would avoid imposing unnecessary additional burdens on large facilities. First, EPA
could establish a tiered threshold for aggregation of small sources that adjusts with the size of the
440
-------
reporting facility. For example, sources with 25 units or fewer could have a 250 mmBtu/hr
aggregation limit, sources with between 25 and 50 units could have a 500 mmBtu/hr aggregation
limit, etc. Alternately, EPA could augment the current 250 mmBtu limit/hr by also allowing the
unlimited aggregation of units that fall below a certain minimum size (e.g., 10 mmBtu). These
alternatives would have no significant impact on the amount of emissions reported by large
facilities and would result in only a very modest loss of reporting detail (and only for the
smallest units) while increasing flexibility and reducing costs.
Response: EPA has made a number of significant adjustments in the final rule to the data
reporting requirements of §98.36, both to clarify those requirements and to reduce the reporting
burden. These adjustments are similar in effect to those suggested by the commenter.
For units that use Tiers 1, 2, and 3 to calculate C02 mass emissions, the cumulative 250
mmBtu/hr heat input capacity limit on the aggregation of units into a group has been dropped.
Rather, the 250 mmBtu/hr restriction applies only to the individual units in the group. Therefore,
for reporting purposes, individual units with maximum rated heat input capacities of 250
mmBtu/hr or less may be aggregated without limit into a single group, provided that the Tier 4
methodology is not required for any of the units, and all units in the group use the same Tier for
any common fuel(s) that they combust. Units with maximum rated heat inputs greater than 250
mmBtu/hr using Tiers 1, 2, and 3 must report as individual units, unless they burn the same type
of fuel provided by a common pipe or supply line; in that case, the owner or operator may opt to
use the highest Tier required for a grouped unit for the calculation method with the common pipe
reporting provisions in §98.36(c)(3). Units using Tier 4 must report as individual units unless
they share a monitored common stack; in that case, the common stack reporting provisions of
§98.36(c)(2) may be used.
Commenter Name: Keith Adams
Commenter Affiliation: Air Products and Chemicals, Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-1142.1
Comment Excerpt Number: 29
Comment: The proposed rule requires reporting of GHG emissions for each type of fuel
combusted. It is not clear if the expectation is discrete, or combined, reporting of the GHG
emissions for each/all fuel types. Separate reporting of GHG emissions from the combustion of
each discrete fuel type increases the risk that confidential business information (operating rates,
fuel choices, operating efficiencies) could be revealed in reports accessible to domestic and
international competitors and customers of the regulated source. Further, when CO2 emissions
are calculated using the Tier 4 method, there is no way to distinguish which CO2 emissions come
from each individual fuels. Air Products Comment: EPA should clarify that emission reporting
is required only for the combined emissions from all fuels combusted. Reporting emissions for
each fuel separately should not be required. Additionally, provisions to protect the
confidentiality of all process, production and business- related information required under the
rule should be strengthened. While Air Products accepts that facility-level emissions cannot be
protected from public disclosure, it strongly requests all other information should, by default, be
considered confidential business information and afforded the utmost protection from public
disclosure.
441
-------
Response: See the Preamble, Section II. R., and the response to comment EPA-HQ-OAR-2008-
0508-1142.1 excerpt 28 for the response on CBI.
Units that calculate emissions using Tier 1, Tier 2, or Tier 3 must report emissions separately for
each fuel type. However, §98.36(b)(7) of the final rule states that, for Tier 4 units, the annual
CO2 emissions will be reported for all fuels combined, and that any biogenic CO2 emissions will
also be reported separately. It also states that CH4 and N20 emissions are to be reported for each
type of fuel combusted, calculated in accordance with §98.33(c). In §98.33(c)(3), EPA has
specified that reporters using Tier 4 are to use the best available estimates of the annual heat
input from each type of fuel combusted in the unit during the reporting year, excluding fuel used
only for startup or ignition. This can be from CEMS data or engineering calculations. Using this
data they are to calculate CH4 and N2O emissions for each fuel type.
In revising the final version of the rule, EPA has also added §98.36(d) to define data reporting
requirements for units subject to Part 75, which requires total emissions by unit, not by fuel.
EPA believes that these provisions in the final rule effectively address the concerns of the
commenters.
Commenter Name: Leslie Bellas
Commenter Affiliation: National Lime Association (NLA)
Document Control Number: EPA-HQ-OAR-2008-0508-0520.1
Comment Excerpt Number: 19
Comment: 40 C.F.R. §98.36(b)(3) also requires sources to report the maximum rated heat input
capacity of "process heaters." NLA requests EPA to confirm a statement made by EPA staff
during a May 14 conference call that "process heaters" refers to all combustion equipment that
has a nameplate capacity and is used to provide heat for the process.
Response: The commenter can find clear language in the final rule with regard to the definition
of maximum rated heat input capacity in §98.6: "Maximum rated heat input capacity means the
hourly heat input to a unit (in mmBtu/hr), when it combusts the maximum amount of fuel per
hour that it is capable of combusting on a steady state basis, as of the initial installation of the
unit, as specified by the manufacturer."
EPA uses the term "process heaters" to refer to a wide variety of devices in which heat is
transferred indirectly to a process material. Nameplate capacity is not one of the necessary
criteria for a combustion source to be included in this category.
Commenter Name: Keith Adams
Commenter Affiliation: Air Products and Chemicals, Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-1142.1
Comment Excerpt Number: 31
Comment: The proposed rule describes in detail all the information required to be reported in
order to verify the reported GHG emissions. The data compilation for all the information EPA
442
-------
seeks under §98.36(d) is extremely burdensome for regulated sources. While some of this
information is used in order to develop, and assure the accuracy of, the emissions estimate,
reporting all of this information is not necessary. In many cases, the necessity of this
information is questionable, based on the rule's intention to develop an annual emissions
estimate. Examples include §98.36(d)(l)(iv)(A) - number of operating hours per day of a
particular emission source and §98.36(d)(l)(iv)(C) - daily CO2 emissions (when an annual total
is the rule's objective). Reporting at this level of detail also increases the risk that confidential
business information could be revealed in reports accessible to domestic and international
competitors and customers of the regulated source. Regulated sources should only be required to
maintain the appropriate information that supports the emissions calculations and reporting basis,
and make this information available upon request of EPA. Reporting of any information
unrelated to emissions should not be required. All process, production and business-related
information required to be reported under provisions to insure the veracity of the reported
emissions should be afforded the maximum confidentiality protections.
Response: See the Preamble, Section II. R., and response to comment EPA-HQ-OAR-2008-
0508-1142.1 excerpt 28 for the response on CBI.
EPA does not agree with the commenter's assertion that the amount of unit-level data and
verification information to be reported electronically is excessive, burdensome or unnecessary.
EPA has required the reporting of additional supporting data that are not directly used to
calculate emissions but are nevertheless related to emissions and supportive of centralized
verification efforts. For this mandatory GHG emissions reporting rule, two main approaches to
data verification were considered, i.e., EPA verification and third-party verification. EPA
decided on the former approach. In view of this, additional, unit-level information is deemed
necessary to provide assurance that the reported facility-wide GHG emissions data are both
credible and accurate. However, EPA has made a number of significant adjustments in the final
rule to the data reporting requirements of §98.36, both to clarify those requirements and to
reduce the reporting burden. EPA has also allowed facilities to keep more detailed QA records
on-site, and submit them within 30 days of a written request from the Administrator or from the
applicable state or local air pollution control agency (see §98.36(e)(3)).
EPA believes that it is appropriate to require submission of the total number of operating hours
during the reporting year, and has retained this provision in the final rule. However, EPA has not
finalized the requirements to report daily CO2 emissions or the number of unit operating days.
Sections 98.36(e)(2)(vi)(A) and (B) require facilities to report only the number of annual unit
operating hours and the cumulative CO2 mass emissions in each quarter of the reporting year.
EPA believes that these revisions appropriately balance the need for quality assured GHG
emission data with the need to reduce the burden on reporters.
Commenter Name: Leslie Bellas
Commenter Affiliation: National Lime Association (NLA)
Document Control Number: EPA-HQ-OAR-2008-0508-0520.1
Comment Excerpt Number: 16
Comment: 40 C.F.R. §98.36 requires unit or process-specific reporting of combustion
emissions. The physical configuration of some lime plants precludes unit-specific emissions
443
-------
calculations because one fuel feed system may support multiple kilns. The Proposed Rulfe's
objective to collect facility-level data is not undermined by permitting facility-wide reporting of
combustion fuel emissions. As with lime process emissions, reporting combustion emissions by
unit (kiln) does not improve the accuracy of the data. The Proposed Rule should follow the
Western Climate Initiative's Final Draft of Essential Requirements of Mandatory Reporting,
which permits facility-wide reporting of combustion fuel emissions. In accordance with 40
C.F.R. §98.37, a source can retain any unit-specific emissions information in company records
and make it available to EPA for review. Facility-wide reporting of combustion emissions
satisfies EPA's objective of developing facility-wide emissions information, without requiring
businesses in highly competitive industries to disclose highly sensitive confidential business
information.
Response: See the Preamble, Section II. R., for EPA's response on CBI.
EPA does not agree with the commenter's assertion that facility-wide information in itself
satisfies EPA's objectives for the rule. Some potential programs under the Clean Air Act
including NSPS, are applied at more disaggregated level than the overall facility. Because the
main purpose of the rule is to collect information for climate policy development under the CAA,
EPA views unit level reporting as appropriate. Additionally, to ensure high quality verified data,
EPA has decided to serve the role as verifier rather than require third-party verification. In view
of this, additional unit-level information is deemed necessary to provide assurance that the
reported facility-wide GHG emissions data are both credible and accurate. The need for unit-
level data is more pronounced for large units (i.e., greater than 250 mmBtu/hr) because of the
overall share of emissions represented by these larger units at facilities, and the overall share of
national emissions represented by these larger units collectively. However, as explained in the
paragraphs below, EPA has made a number of significant adjustments in the final rule to the data
reporting requirements of §98.36, both to clarify those requirements and to reduce the reporting
burden.
For units that use Tiers 1, 2, and 3 to calculate CO2 mass emissions, the cumulative 250
mmBtu/hr heat input capacity limit on the aggregation of units into a group has been dropped.
Rather, the 250 mmBtu/hr restriction applies only to the individual units in the group. Therefore,
for reporting purposes, individual units with maximum rated heat input capacities of 250
mmBtu/hr or less may be aggregated without limit into a single group, provided that the Tier 4
methodology is not required for any of the units, and all units in the group use the same Tier for
any common fuel(s) that they combust. Units with maximum rated heat inputs greater than 250
mmBtu/hr using Tiers 1, 2, and 3 must report as individual units, unless they burn the same type
of fuel provided by a common pipe or supply line; in that case, the owner or operator may opt to
use the common pipe reporting provisions in §98.36(c)(3). This common pipe provision may be
suitable for fuel lines that feed multiple lime kilns. Units using Tier 4 must report as individual
units unless they share a monitored common stack; in that case, the common stack reporting
provisions of §98.36(c)(2) may be used.
The supplementary verification information requirements of §98.36(e) have been clarified and,
in some cases, differ substantively from the proposed rule. Paragraph (e)(1) in §98.36 clearly
states that no additional verification information is required for sources that monitor and report
emissions and heat input data using Part 75. This includes sources that elect to use the new
§98.33(a)(5) alternative calculation methodologies for units not subject to the Acid Rain
Program that report data to EPA according to Part 75. For sources using Tiers 1, 2, 3, and 4, the
444
-------
final rule streamlines some of the reporting. Sources using Tier 3 are required to report only
monthly averages of the fuel carbon content and molecular weight rather than the proposed
requirement to submit the results of each individual determination.
Commenter Name: Leslie Bellas
Commenter Affiliation: National Lime Association (NLA)
Document Control Number: EPA-HQ-OAR-2008-0508-0520.1
Comment Excerpt Number: 37
Comment: 40 C.F.R. §§98.36(d)(l)(iii) and (iv) require Tier 3 and Tier 4 facilities to report
monthly data for the quantity of each type of fuel combusted per unit and the carbon content.
Unit specific data may not be available because of the integrated nature of a lime plant and plant
configuration. In addition, reporting fuel use data may allow competitors to more precisely
determine the efficiency and capacity of kilns. 40 C.F.R. §98.36(d)(l)(iv) should be revised to
require annual data for quantity of each type of fuel combusted at the facility. This is consistent
with the Rule's intent to collect facility-level data and the Western Climate Initiative's reporting
rule. Moreover, public reporting of this sensitive business information will not add substantive
value to the annual report.
Response: See the Preamble, Section II. R., and the response to comment EPA-HQ-OAR-2008-
0508-0520.1 excerpt 16 for EPA's response on CBI. Also see the response to the same comment,
comment EPA-HQ-OAR-2008-0508-0520.1, excerpt 16 for the response on the need for unit-
level data, and additional flexibility EPA has provided for reporting, such as aggregation and
common pipe configurations at facilities that may be suitable for lime plants.
Commenter Name: Leslie Bellas
Commenter Affiliation: National Lime Association (NLA)
Document Control Number: EPA-HQ-OAR-2008-0508-0520.1
Comment Excerpt Number: 38
Comment: 40 C.F.R. §98.36(d)(l)(iv) requires Tier 4 facilities to report daily CO2 emission
rates from CEMS and the hours of operation and operating days. 40 C.F.R. §98.36(d)(l)(iv)(A)
should be revised to delete the requirement to report operating days and operating hours. Given
the intent of the Rule, which is to report GHG emissions, there is little value in requiring source
to report operating days or hours. The requirement to report daily CO2 emission rates (40 C.F.R.
§98.36(d)(l)(iv)(C)) for Tier 4 should be deleted. EPA is requiring electronic reporting, so this
level of detailed reporting will require sources to enter a significant amount of data. Hourly CO2
emission rates as generated by the CEMS can be retained in company records and made
available for review in accordance with 40 C.F.R. §98.37. Public disclosure of this information
does not further the objectives of the Proposed Rule.
Response: EPA believes that it is appropriate to require submission of the total number of
operating hours during the reporting year, and has retained this provision in the final rule.
However, EPA has not finalized the requirements to report daily CO2 emissions or the number of
unit operating days. Sections 98.36(e)(2)(vi)(A) and (B) require facilities to report only the
445
-------
number of annual unit operating hours and the cumulative C02 mass emissions in each quarter
of the reporting year. EPA believes that these revisions appropriately balance the need for
quality assured GHG emission data with the need to reduce the burden on reporters.
See the Preamble, Section II. R., and the response to comment EPA-HQ-OAR-2008-0508-
0520.1 excerpt 16 for EPA's response on CBI.
Commenter Name: Lorraine Krupa Gershman
Commenter Affiliation: American Chemistry Council (ACC)
Document Control Number: EPA-HQ-OAR-2008-0508-0423.2
Comment Excerpt Number: 68
Comment: In §98.36(b) and (c), EPA should modify these sections to allow a facility to report
only the total C02 for a facility instead of unit-specific calculation and reporting. This is
advantageous to EPA as an inventory calculation tool because it will capture smaller sources and
make the total inventory more complete. Many facilities do not have the meters required to do
unit-by-unit calculations. Such calculations would be burdensome and excessive and would not
add to the overall use of the information to develop a greenhouse gas inventory. Examples
illustrating this concern include: (1) Natural gas is only metered where it enters the site.
Therefore, EPA should allow calculation and reporting of site wide C02e. Although combustion
unit specific emissions would not be reported, the inventory of CO2 emissions from natural gas
combustion at the site would be more complete and thorough than as currently proposed in
Subpart C. (2) The only record of fuel oil usage may be the amount delivered to the site. Some
fuel oil is used in emergency engines. Since emergency engine use cannot be readily separated
from the total consumption, the inventory of C02 emissions from fuel oil combustion at the site
would be more complete and thorough than as currently proposed in Subpart C.
Response: Regarding the situation where natural gas is only metered "at the gate," the common
pipe or unit aggregation options in §98.36(c) could be used to substantially reduce the reporting
burden. Regarding the issue of quantifying fuel usage by emergency generators (which are
exempt from GHG emissions reporting), this only becomes an issue when the generators are fed
from a common fuel pipe or supply tank that also serves affected units. EPA has included a
definition of "company records" in §98.6 that applies to Tiers 1 and 2. The definition (see
below) provides a great deal of flexibility in determining fuel usage.
"Company records" means a complete record of the methods used, the measurements made, and
the calculations performed to quantify fuel usage. Company records may include, but are not
limited to, direct measurements of fuel consumption by gravimetric or volumetric means, tank
drop measurements, and calculated values of fuel usage obtained by measuring auxiliary
parameters such as steam generation or unit operating hours. Fuel billing records obtained from
the fuel supplier qualify as company records."
Thus, where a group of units that includes emergency generators is fed by a common supply line,
a best available estimate of the fuel used by the emergency generators can be made using
"company records," and then the result can be subtracted out from the total amount of fuel
consumed by the group, prior to calculating the GHG emissions for the affected units.
446
-------
See the Preamble, Section II. R., and the response to comment EPA-HQ-OAR-2008-0508-
0520.1 excerpt 16 for EPA's response on CBI. Also, see the response to the same comment,
comment EPA-HQ-OAR-2008-0508-0520.1, excerpt 16 for the response to the need for unit-
level data, including additional flexibility EPA has provided for aggregation and common pipe
configurations at facilities.
Commenter Name: Lorraine Krupa Gershman
Commenter Affiliation: American Chemistry Council (ACC)
Document Control Number: EPA-HQ-OAR-2008-0508-0423.2
Comment Excerpt Number: 69
Comment: For §98.36(b) and (c), there are situations when the fuel-type might be CBI. In
these instances, facilities will not want to report their fuel type, and EPA should not require it to
be reported. This is especially true for §98.36(b)(5) for hydrogen production. As an alternate to
requiring each individual fuel type to be reported, ACC recommends limiting the reporting to the
following categories: liquid, other solid fuels, MSW, biomass, natural gas, and other gaseous
fuels [see Table C-l in Preamble],
Response: See the Preamble, Section II. R., and response to comment EPA-HQ-OAR-2008-
0508-0520.1 excerpt 16 for EPA's response on CBI. Reporting of fuel type is critical for
verification of emissions estimates.
Commenter Name: Lorraine Krupa Gershman
Commenter Affiliation: American Chemistry Council (ACC)
Document Control Number: EPA-HQ-OAR-2008-0508-0423.2
Comment Excerpt Number: 70
Comment: In §98.36(c), ACC supports all of the alternative calculation methods allowing unit
aggregation that EPA has provided. In §98.36(c)(3), there are certain situations where using the
common pipe method will severely overstate the greenhouse gas emissions such as when natural
gas is used as a feedstock for manufacturing processes instead of as a fuel. In these cases, EPA
should allow the use of engineering calculations in lieu of measured flow rates within the
common pipe method.
Response: EPA acknowledges the commenter's concerns, and has addressed this issue in the
final rule. Section 98.36(c)(3) states: If a portion of the fuel measured at the common pipe is
diverted to a chemical or industrial process where it is used but not combusted, provided that the
amount of fuel diverted is also measured with a calibrated flow meter, you may subtract out the
diverted fuel from the fuel measured at the common pipe prior to performing the GHG emissions
calculations."
447
-------
Commenter Name: Lorraine Krupa Gershman
Commenter Affiliation: American Chemistry Council (ACC)
Document Control Number: EPA-HQ-OAR-2008-0508-0423.2
Comment Excerpt Number: 71
Comment: The Acid Rain regulation does not require reporting C02 by fuel if a CEMS is
present, and this rule should not require CO2 by fuels in any part of §98.36.
Response: EPA acknowledges the commenter's concerns, and has addressed this issue in the
final rule. Units calculating emissions using Tiers 1, 2, or 3 must report emissions by fuel type.
However, §98.36(b)(7) of the final rule states that, for Tier 4 units, the annual CO2 emissions
will be reported for all fuels combined, and that any biogenic C02 emissions will also be
reported separately. It also states that CH4 and N2O emissions are to be reported for each type of
fuel combusted, calculated in accordance with §98.33(c). In §98.33(c)(3), EPA has specified
that reporters using Tier 4 are to use the best available estimates of the annual heat input from
each type of fuel combusted in the unit during the reporting year, excluding fuel used only for
startup or ignition. This can be from CEMS data or engineering calculations. Using this data
they are to calculate CH4 and N20 emissions for each fuel type.
In revising the final version of the rule, EPA has also added §98.36(d) to define data reporting
requirements for units subject to Part 75, which requires total emissions by unit, not by fuel.
EPA believes that these provisions in the final rule effectively address the concerns of the
commenters.
Commenter Name: Lorraine Krupa Gershman
Commenter Affiliation: American Chemistry Council (ACC)
Document Control Number: EPA-HQ-OAR-2008-0508-0423.2
Comment Excerpt Number: 72
Comment: In §98.36, EPA does not appear to have limited the reporting by fuel type, even with
CEMS being used. However, EPA must do so by changing the rule to allow aggregating fuel
types at least when CEMS are used, because CEMS do not allow separating CO2 emissions by
fuel type if different fuels are burned at the same time. An example would be process gas fuel
that is supplemented with natural gas.
Response: EPA acknowledges the commenter's concerns, and has addressed this issue in the
final rule. Section 98.36(b)(7) of the final rule states that, for Tier 4 units, the annual CO2
emissions will be reported for all fuels combined, and that any biogenic CO2 emissions will also
be reported separately. It also states that CH4 and N2O emissions are to be reported for each
type of fuel combusted, calculated in accordance with §98.33(c). In §98.33(c)(3), EPA has
specified that reporters using Tier 4 are to use the best available estimates of the annual heat
input from each type of fuel combusted in the unit during the reporting year, excluding fuel used
only for startup or ignition. This can be from CEMS data or engineering calculations. Using this
data they are to calculate CH4 and N2O emissions for each fuel type.
In revising the final version of the rule, EPA has also added §98.36(d) to define data reporting
requirements for units subject to Part 75, which requires total emissions by unit, not by fuel.
448
-------
EPA believes that these provisions in the final rule effectively address the concerns of the
commenters.
Commenter Name: Randal G. Oswald
Commenter Affiliation: Integrys Energy Group, Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-0569.1
Comment Excerpt Number: 4
Comment: Subpart C, unit level reporting requirement in 98.36(b)(5) is inconsistent with Tier 4
and 40 CFR Part 75 monitoring methods. This section requires that annual GHG emissions are
reported for each fuel type, but Tier 4 and Part 75 monitoring methods do not monitor and report
emissions by each fuel type. Section 98.36(b)(5) reads, "The calculated CO2, CH4, and N2O
emissions for each type of fuel combusted, expressed in metric tons of each gas and in metric
tons of CC^e". Tier 4 and 40 CFR Part 75 monitoring methods calculate CO2 mass emissions
and heat input from all fuels combusted in a unit. The proposed rule should clarify that Tier 4
and 40 CFR Part 75 emissions are not required to report GHG emissions by type of fuel.
Response: EPA acknowledges the commenter's concerns, and has addressed this issue in the
final rule. Section 98.36(b)(7) of the final rule states that, for Tier 4 units, the annual C02
emissions will be reported for all fuels combined, and that any biogenic CO2 emissions will also
be reported separately. It also states that CH4 and N20 emissions are to be reported for each
type of fuel combusted, calculated in accordance with §98.33(c). In §98.33(c)(3), EPA has
specified that reporters using Tier 4 are to use the best available estimates of the annual heat
input from each type of fuel combusted in the unit during the reporting year, excluding fuel used
only for startup or ignition. This can be from CEMS data or engineering calculations. Using this
data they are to calculate CH4 and N2O emissions for each fuel type.
In revising the final version of the rule, EPA has also added §98.36(d) to define data reporting
requirements for units subject to Part 75, which requires total emissions by unit, not by fuel.
EPA believes that these provisions in the final rule effectively address the concerns of the
commenters.
Commenter Name: Keith Adams
Commenter Affiliation: Air Products and Chemicals, Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-1142.1
Comment Excerpt Number: 30
Comment: The proposed rule offers the option to calculate and report emissions for aggregated
units under the provisions of §98.36(c)(1), (2), and (3). These are effective methods by which a
source can streamline the process measurement, emission calculation, and emission reporting
requirements. Air Products strongly support the optional aggregation provisions and encourages
EPA to consider expanding the applicability of such options. For example, eliminating the
restriction of the aggregated maximum capacity of 250 mm BTU/hr under §98.36(c)(1) would
not compromise the accuracy or completeness of the reported data, but could reduce the emission
449
-------
calculation and reporting burden and provide some additional protection to confidential business
information.
Response: See the Preamble, Section II. R., and the response to comment EPA-HQ-OAR-2008-
0508-0520.1 excerpt 16 for EPA's response on CBI.
EPA has made a number of significant adjustments in the final rule to the data reporting
requirements of §98.36, both to clarify those requirements and to reduce the reporting burden.
For units that use Tiers 1, 2, and 3 to calculate CO2 mass emissions, the cumulative 250
mmBtu/hr heat input capacity limit on the aggregation of units into a group has been dropped.
Rather, the 250 mmBtu/hr restriction applies only to the individual units in the group. Therefore,
for reporting purposes, individual units with maximum rated heat input capacities of 250
mmBtu/hr or less may be aggregated without limit into a single group, provided that the Tier 4
methodology is not required for any of the units, and all units in the group use the same Tier for
any common fuel(s) that they combust. Units with maximum rated heat inputs greater than 250
mmBtu/hr using Tiers 1, 2, and 3 must report as individual units, unless they burn the same type
of fuel provided by a common pipe or supply line; in that case, the owner or operator may opt to
use the highest Tier required for a grouped unit for the calculation method with the common
pipe reporting provisions in §98.36(c)(3). Units using Tier 4 must report as individual units
unless they share a monitored common stack; in that case, the common stack reporting
provisions of §98.36(c)(2) may be used.
Commenter Name: Michael DiMauro
Commenter Affiliation: Massachusetts Municipal Wholesale Electric Company (MMWEC)
Document Control Number: EPA-HQ-OAR-2008-0508-0580
Comment Excerpt Number: 6
Comment: Fuel Data Applicable to a Group of Units: The Proposed Rule does not appear to
discuss the reporting of fuel consumption measurement data that represents the combined usage
for a group of stationary combustion units. Often, records documenting fuel usage (aside from
fuel metering data) are not available at, or applicable to, the individual unit level. Examples of
records that provide accurate information on fuel consumption, but which do not represent unit
level measurements include: (a) Oil Tank Drop measurements, for storage tanks at facilities
operating multiple oil fired units; (b) documentation of fuel oil deliveries to a site that operates
multiple combustion units which are served by one or more non-dedicated oil tanks; and (c)
documentation of natural gas usage on billing invoices where multiple (non-dedicated) gas lines
serve the facility and the facility operates multiple combustion units. These monitoring
situations are analogous to a common pipe fuel configuration in that fuel usage is measured at a
location from which fuel is delivered to several combustion sources. For common pipes, GHG
emission reporting is only required at the aggregate level, not for the individual combustion units
(see 98.36(c)(3)). However, this type of monitoring also has some aspects in common with
aggregation (as does common pipe monitoring), but "aggregation" is only allowed for a group of
units whose total design heat input is < 250 MMBtu/hr, which is a very restrictive condition. For
facilities at which a fuel is measured at a common supply point serving multiple units (e.g. an oil
storage tank), and but which is not a common pipe, the rule should provide clarification and
elaboration on the following issues: a) Whether fuel consumption should be only reported at the
450
-------
group level, for the set of combustion units to which this fuel usage documentation is applicable
(as with common pipes), or if fuel usage must be apportioned to the individual unit level; b) The
rule should also address the situation in which some of the combustion units in the group are
subject to the Acid Rain or CAIR Programs, and are therefore individually metered. In this
situation, the rule should allow fuel usage from such Part 75 units to be extracted from the group
fuel usage totals (i.e. Group Fuel Consumption for Non-Part 75 Units = Total Fuel Consumption
for entire group from documented records - Directly Monitored Fuel Consumption for Part 75
Units) c) If apportionment is required, the rule should provide guidance on acceptable types of
apportionment schemes. Part 75 contains several apportionment approaches that could be
adopted, including apportionment based on Unit level MW output, Unit level steam production
or Unit level fuel flows measured by uncertified meters, d) It should be clarified that this
monitoring approach is not considered aggregation and therefore is not subject to the restriction
that the combined design heat input of the group be < 250 MMBtu/hr
Response: EPA acknowledges the concerns of the commenter, and has revised the reporting
alternatives described in §98.36(c) to reduce the burden on reporters. First, for units that use
Tiers 1, 2, and 3 to calculate C02 mass emissions, the cumulative 250 mmBtu/hr heat input
capacity limit on the aggregation of units into a group has been dropped. Rather, the 250
mmBtu/hr restriction applies only to the individual units in the group. Therefore, for reporting
purposes, individual units with maximum rated heat input capacities of 250 mmBtu/hr or less
may be aggregated without limit into a single group, provided that the Tier 4 methodology is not
required for any of the units, and all units in the group use the same Tier for any common fuel(s)
that they combust. Furthermore, EPA has clarified the provisions for common pipe reporting in
§98.36(c)(3). To use common-pipe reporting, a facility must determine the total amount of fuel
combusted by the common pipe units using a calibrated fuel flow meter. EPA has added a
provision allowing facilities to subtract fuel diverted away from these units prior to performing
GHG emissions calculations, provided that the amount of fuel diverted is measured with a
calibrated fuel flow meter. EPA believes that these revisions will reduce the burden of reporting.
The commenter suggests that combustion units subject to the Acid Rain or CAIR Programs that
are part of a group of units which includes non-Part 75 units should be allowed to determine fuel
consumption for the non-Part 75 units using a subtractive method. EPA assumes that the
commenter is referring to a common pipe situation where a supply line serves both Part 75 units
and non-Part 75 units. If the non-Part 75 units are eligible for the Tier 1 or 2 methodology,
"company records" (as defined in 98.6) may be used to determine the total fuel consumption for
the group of units. If Tier 3 is required, a calibrated fuel flow meter must be used at the common
pipe to measure the total amount of fuel combusted.
The final rule requires GHG emissions from Part 75 units to be reported separately, under the
same unit, stack or pipe ID numbers that are used for Part 75 electronic reporting. Therefore, if
Part 75 units share a common supply line with non-Part 75 units, it is appropriate to subtract out
the individually metered fuel combusted by the Part 75 units from the total fuel combusted by the
group before calculating the CO2 emissions for the group of non-Part 75 units.
451
-------
Commenter Name: Michael E. Van Brunt
Commenter Affiliation: Covanta Energy Corporation
Document Control Number: EPA-HQ-OAR-2008-0508-0548.1
Comment Excerpt Number: 5
Comment: Consistent with international precedent, the Proposed Rule requires that biogenic
emissions be reported separately; however, it appears that these biogenic emissions are included
in the total reported C02 emissions. To be fully consistent with international precedents, the
EPA must clarify that biogenic emissions of CO2 are not to be included in total CO2 emissions.
According to the IPCC 2006 guidelines, "the C02 emissions from combustion of biomass
materials (e.g. paper, food, and wood waste) contained in the waste are biogenic emissions and
should not be included in national total emission estimates."
Response: While EPA has decided to track biogenic emissions separately, they still must be
reported. EPA believes that it is clear in §98.2(b)(l)(i) that CO2 emissions from biogenic fuels
do not count toward the 25,000 metric ton threshold for reporting for stationary combustion
units, although CH4 and N2O emissions from biogenic fuels must be considered. Furthermore,
EPA notes that the tracking of carbon of biogenic nature is accounted, for national GHG
inventories, within the Land Use, Land-Use Change and Forestry sector by examining the carbon
fluxes of forestry. This means that the exhalation of carbon and uptake of carbon by trees is
examined together. All net emissions are included in national totals. Additionally, EPA plans to
make the distinction between biogenic and non-biogenic C02 emission clear in any document or
database available to the public.
Commenter Name: Kathleen M. Sgamma
Commenter Affiliation: Independent Petroleum Association of Mountain States (IPAMS)
Document Control Number: EPA-HQ-OAR-2008-0508-0521.1
Comment Excerpt Number: 13
Comment: IPAMS supports the aggregated reporting of units with combined maximum rated
heat input of 250 MMBtu/hr or less.
Response: EPA appreciates this comment, and believes that the final rule includes further
clarification and flexibility regarding aggregation provisions. For units that use Tiers 1, 2, and 3
to calculate CO2 mass emissions, the cumulative 250 mmBtu/hr heat input capacity limit on the
aggregation of units into a group has been dropped. Rather, the 250 mmBtu/hr restriction applies
only to the individual units in the group. Therefore, for reporting purposes, individual units with
maximum rated heat input capacities of 250 mmBtu/hr or less may be aggregated without limit
into a single group, provided that the Tier 4 methodology is not required for any of the units, and
all units in the group use the same Tier for any common fuel(s) that they combust.
452
-------
Commenter Name: Angus E. Crane
Commenter Affiliation: North American Insulation Manufacturers Association (NAIMA)
Document Control Number: EPA-HQ-OAR-2008-0508-0537.1
Comment Excerpt Number: 13
Comment: The proposed rule should provide a longer, reasonable period of time to respond to
EPA's written requests. Proposed section 98.36 sets forth data reporting requirements. Within
this section, proposed section 98.36(d)(2) states that "[wjithin 7 days of receipt of a written
request (e.g., a request by electronic mail) from the Administrator or from the applicable air
pollution control agency, the owner or operator shall submit the explanations described in
Section 98.34(a) and (b)" in a certain manner. Seven days is an unreasonably short period of
time to respond to such requests. On some occasions, EPA and other regulatory agencies have
submitted requests for information to owner/operators during periods when the people necessary
to assemble the response are unavailable, e.g., holidays such as Christmas and Thanksgiving.
Moreover, there is no reason for requiring such a quick response. GHG emissions, and any
questions about them, pose no immediate health or environmental risk that will be worsened
during the 23 days needed to extend the proposed reporting deadline to a more reasonable 30-day
period. Accordingly, NAIMA asks that EPA revise the proposed rule to provide a 30-day, not a
7-day, response time under proposed section 98.36(d)(2).
Response: EPA acknowledges the commenter's concerns. In §98.36(e)(3) of the final rule, EPA
has allowed owners or operators 30 days from receipt of a written request for information to
respond to that request.
Commenter Name: D. Lawrence Zink
Commenter Affiliation: Montana Sulphur & Chemical Company Inc. (MSCC)
Document Control Number: EPA-HQ-OAR-2008-0508-0505.1
Comment Excerpt Number: 14
Comment: At our facility, and we believe at many others, it is fruitless and possibly infeasible
to allocate fuel usage to individual units on a "best available data" basis because we have a single
fuel gas header that supplies combustion fuel to several and varying process heaters, incinerators,
and boilers. None of these individual heaters etc., actually approaches the 30,000,000 BTU/hr or
25,000 ton thresholds individually, and it may be that in aggregate they also do not meet these
thresholds. The fuel is frequently a mixture of natural gas and refinery fuel gas, with the ratio of
gases varying over a day. Our records are limited to the total of each type of fuel gas supplied
over a day. We may have estimates of the ratio of the total fuel gas used in various units; even
so, we believe it is unnecessarily complex to require reporting of emissions by fuel type from
each individual unit inside a facility, let alone to invoke "best available" and/or "all available"
data considerations/decisions on potentially thousands of events during a year. Ultimately the
volume of C02e emissions from fuel burning is what it is and is determined by the total amount
of fuel burned at the facility. It is not relevant to precisely identify which process heater or
boiler accounted for which molecule of CO2. Furthermore, most of these emissions are merged
to a single emission point where they mix with process emissions from other than fuel burning
activities. We suggest that for fuel burning emissions from a site location, aggregate fuel data
should be more than sufficient, for example, if the emissions are all co-located on the same site,
453
-------
or are emitted within (for instance) one kilometer of each other. It may not be unreasonable to
ask sources to identify the contributing units by name or label, but it serves no purpose to force
an allocation, let alone one based on "all process data" or "best available" criteria. None of this
internal information, even if derived from the best possible measurements, has any bearing on
purported impacts from GHG emissions.
Response: See the response to comment EPA-HQ-OAR-2008-0508-1142.1 excerpt 31 for the
response on the level of reporting, and the response to comment EPA-HQ-OAR-2008-0508-
0520.1 excerpt 16 for the response indicating the additional flexibility provided to reporters,
particularly for common pipe and aggregated unit circumstances.
For the situation described by the commenter (i.e., a supply line that feeds a single type of fuel to
multiple units), the common pipe reporting option in §98.36(c)(3) is the best option for
quantifying CO2 emissions and to reduce the reporting burden. If the gas combusted by the units
is listed in Table C-l, then Tier 1 or Tier 2 could be used to calculate C02 emissions, with
company records used to quantify fuel consumption. If the gas is not listed in Table C-l, then, in
this case, since none of the individual units served by the supply line is > 250 mmBtu/hr, GHG
emissions reporting is not required.
EPA further notes that the alternative reporting requirements, such as for the aggregation of units
or the use of common pipes, are allowed to be used by multiple groupings of units at a facility.
For example, if a facility has a single gas header for supplying natural gas to multiple units, it
may use the common pipe reporting option and report a single GHG value. In addition, a facility
may aggregate multiple small units (i.e., 250 mmBtu/hr) that combust another common fuel and
report a single GHG value. The use of the alternative reporting requirements is allowed for
multiple groupings of units, so the comment about determining ratios of fuel use by units is not
necessary if the reporter chooses the reporting alternatives.
Commenter Name: See Table 4
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0455.1
Comment Excerpt Number: 16
Comment: Proposed §98.36(b)(5) states that reporting is required for "[t]he calculated CO2,
CH4, and N2O emissions for each type of fuel combusted, expressed in metric tons of each gas
and in metric tons of CC^e" (emphasis added). However, Tier Four of Subpart C of the Proposal
and 40 C.F.R. Part 75 calculation methods determine CO2 mass emissions and heat input by
combining all fuel types combusted in a unit. Therefore, when using the Tier Four calculation
methods, it is impossible to report the calculated CO2 mass emissions by each type of fuel. EPA
should clarify that those facilities using Tier Four and 40 C.F.R. Part 75 calculations are not
required to report GHG emissions by fuel type.
Response: EPA acknowledges the commenter's concerns, and has addressed this issue in the
final rule. Section 98.36(b)(7) of the final rule states that, for Tier 4 units, the annual CO2
emissions will be reported for all fuels combined, and that any biogenic CO2 emissions will also
be reported separately. It also states that CH4 and N2O emissions are to be reported for each
type of fuel combusted, calculated in accordance with §98.33(c). In §98.33(c)(3), EPA has
454
-------
specified that reporters using Tier 4 are to use the best available estimates of the annual heat
input from each type of fuel combusted in the unit during the reporting year, excluding fuel used
only for startup or ignition. This can be from CEMS data or engineering calculations. Using this
data they are to calculate CH4 and N2O emissions for each fuel type.
In revising the final version of the rule, EPA has also added §98.36(d) to define data reporting
requirements for units subject to Part 75, which requires total emissions by unit, not by fuel.
EPA believes that these provisions in the final rule effectively address the concerns of the
commenters.
Commenter Name: Steven D. Meyers
Commenter Affiliation: General Electric Company (GE)
Document Control Number: EPA-HQ-OAR-2008-0508-0532.1
Comment Excerpt Number: 19
Comment: Paragraph (c) of Section 98.36 of the proposed regulations provides that small fuel
combustion sources may be aggregated for reporting as long as the aggregate maximum rated
heat input capacity of the units does not exceed 250 MMBtu/hr. In addition, this paragraph also
allows the aggregated reporting of oil-fired or gas-fired fuel combustion units as long as the fuel
combustion units are fed through a common fuel supply line. These provisions will be very
important to lessen the reporting burden of many industrial emission sources such as GE
facilities that may have numerous boilers, process heaters, process flames, furnaces, dryers,
space heaters and other fuel combustion sources. In some cases, an industrial facility may have
numerous gas-fired units that are fired by a common gas line that is metered only at the fence
line. Significant expense would be incurred both for the installation of numerous gas meters and
for the data collection and emission calculation activities that would be needed to report these
units individually.
Response: EPA appreciates the commenter's support, and has made a number of significant
adjustments in the final rule to the data reporting requirements of §98.36, both to clarify those
requirements and to reduce the reporting burden.
For units that use Tiers 1, 2, and 3 to calculate CO2 mass emissions, the cumulative 250
mmBtu/hr heat input capacity limit on the aggregation of units into a group has been dropped.
Rather, the 250 mmBtu/hr restriction applies only to the individual units in the group. Therefore,
for reporting purposes, individual units with maximum rated heat input capacities of 250
mmBtu/hr or less may be aggregated without limit into a single group, provided that the Tier 4
methodology is not required for any of the units, and all units in the group use the same Tier for
any common fuel(s) that they combust. Units with maximum rated heat inputs greater than 250
mmBtu/hr using Tiers 1, 2, and 3 must report as individual units, unless they burn the same type
of fuel provided by a common pipe or supply line; in that case, the owner or operator may opt to
use the highest Tier required for a grouped unit for the calculation method with the common pipe
reporting provisions in §98.36(c)(3). Units using Tier 4 must report as individual units unless
they share a monitored common stack; in that case, the common stack reporting provisions of
§98.36(c)(2) may be used.
455
-------
Commenter Name: See Table 7
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0412.1
Comment Excerpt Number: 23
Comment: GPA also supports the aggregated reporting of units with combined maximum rated
heat input of 250 MMBtu/hr or less.
Response: EPA appreciates this comment, and believes that the final rule includes further
clarification and flexibility regarding aggregation provisions that will reduce the burden on
sources. For units that use Tiers 1, 2, and 3 to calculate CO2 mass emissions, the cumulative 250
mmBtu/hr heat input capacity limit on the aggregation of units into a group has been dropped.
Rather, the 250 mmBtu/hr restriction applies only to the individual units in the group. Therefore,
for reporting purposes, individual units with maximum rated heat input capacities of 250
mmBtu/hr or less may be aggregated without limit into a single group, provided that the Tier 4
methodology is not required for any of the units, and all units in the group use the same Tier for
any common fuel(s) that they combust.
Commenter Name: Linda Farrington
Commenter Affiliation: Eli Lilly and Company (Lilly)
Document Control Number: EPA-HQ-OAR-2008-0508-0680.1
Comment Excerpt Number: 20
Comment: The proposed language in Subpart C requires facilities to report GHG emissions
separately for each type of fuel used in each combustion unit. Lilly believes this level of detail is
unnecessary and we question the value gained from having to report emission data for individual
units. Because the amount of GHG emissions varies among different types of fuels, we
understand the need to report emission by fuel type. But we disagree with the requirement to
report GHG emissions for each individual combustion unit. The reporting alternatives for the
aggregation of small units and the monitored common stack configurations found in §98.36
provide some relief, but further simplification could be achieved by allowing facilities to use
Tier 1 or Tier 2 equations to calculate GHG emissions for each type of fuel used at the facility
(instead of calculating emissions for each individual combustion unit). For example, a facility
may have a single fuel oil storage tank that supplies fuel to multiple boilers and generators.
Because the proposed rule requires reporting by combustion unit, the facility would be required
to estimate fuel usage for each individual boiler and generator. If the proposed rule were
simplified to require reporting at a facility level only, the reporter would only need to monitor
the level in the fuel oil storage tank and perform the emission calculations based upon the total
fuel used at the facility. This would simplify the site's procedures, reduce the amount of required
monitoring, and decrease the volume of individual data points that must be reported and verified
by the EPA.
Response: See the response to comment EPA-HQ-OAR-2008-0508-0520.1 excerpt 16 for
EPA's response to the need for unit-level data, including additional flexibility EPA has provided
for unit aggregation and common pipe configurations at facilities. Unit-level data on fuel
consumption by type is a critical component of a rigorous and credible verification program.
456
-------
Commenter Name: Traylor Champion
Commenter Affiliation: Georgia-Pacific, LLC (GP)
Document Control Number: EPA-HQ-OAR-2008-0508-0380.1
Comment Excerpt Number: 27
Comment: EPA should clarify the common pipe language to specifically allow its use for
combination boilers that combust more than one fuel. Notwithstanding our preferred approach
of using the Tier 1 methodology on fuels coming across the fenceline rather than at the unit level
regardless of the size of the combustion unit, the common pipe aggregation should be allowed
for combination units that combust more than one fuel and this should be clearly stated in the
rule language. EPA should add language that clarifies this intent by inserting a second sentence
in §98.36(c)(3) that reads: "This reporting option can be used even if one or more of the units
combusting the aggregated fuel burns a separate fuel." Also, the language in the reporting
elements in subsections (iv), (vi), (vii), and (viii) should be updated to be consistent with the
above inserted language.
Response: If the common pipe option is selected, the rule requires that all of the units served by
the pipe combust the same type of fuel. Therefore, a unit that combusts both fuel from a
common supply line and one or more additional fuels cannot use the common pipe reporting
option. It must report as an individual unit or possibly as part of a group of aggregated units
under §98.36(c)(1), if it is small (< 250 mmBtu/hr) and there are other small combustion units at
the facility. The unit aggregation option may be used only if Tier 4 is not required for any of the
units in the group, and if the same Tier is used for any fuel(s) that the units have in common.
Commenter Name: Lorraine Krupa Gershman
Commenter Affiliation: American Chemistry Council (ACC)
Document Control Number: EPA-HQ-OAR-2008-0508-0423.2
Comment Excerpt Number: 75
Comment: There is a reference to equation C-14 in both §98.3 6(d)(l)(vii)(D) and (E). We
believe that reference is incorrect. The correct reference should be to equation C-13.
Response: EPA has corrected this error in the final rule.
Commenter Name: William Fred Durham
Commenter Affiliation: West Virginia Department of Environmental Protection (DEP)
Document Control Number: EPA-HQ-OAR-2008-0508-0629.1
Comment Excerpt Number: 7
Comment: Paragraph (a) of 98.36 Data reporting requirements of the proposed MRR states "In
addition to the facility-level information required under 98.3, the annual GHG emissions report
shall contain the unit-level or process-level emissions data in paragraph (b) and (c) of this section
(as applicable) and the emissions verification data in paragraph (d) of this section." The
Preamble, Fact Sheet, Frequently Asked Questions, and PowerPoint downloaded from the
457
-------
Resources part of EPA's MRR webpage at http://www.epa.gov/climatechange/emissions/
ghgrulemaking.html indicate that facility-level reporting is required, which implies that unit- or
process-level reporting is not required. The facility-level reporting appears to be intended to
contrast with corporate-level reporting typical of voluntary GHG programs. On the other hand,
98.36 seems to state clearly that all facilities subject to the MRR must report at the unit- or
process-levels. The verbiage contained in 98.36 may appear clear to those who work with the
Federal Register on a daily basis but it is less so to those who do not. The DAQ requests EPA to
expand 98.36 to expressly state which types of facilities must report at the unit- or process-levels
and to clarify the discussion in its Fact Sheets, etc. to make clear the distinction between its
corporate to facility level reporting and its facility to unit- or process-level reporting
requirements.
Response: See the Preamble, Section II. F., for the responses on the selection of the level of
reporting, as well as the general content of the annual emissions report. EPA intends to make
available guidance materials that to assist stakeholders in understanding the various general and
source category-specific provisions of the rule.
The unit-level reporting provisions in §98.36 are intended to supplement the facility-level report,
and apply only to those units for which reporting under Subpart C, General Stationary
Combustion is required.
Commenter Name: Michael A. Palazzolo
Commenter Affiliation: Alcoa, Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-0650.1
Comment Excerpt Number: 9
Comment: The proposed rule requires the owner/operator to have a written Quality Assurance
Performance Plan (QAPP). This plan must have a detailed description of the procedures used for
maintenance and repair of flow meters and "a maintenance log shall be kept". This requirement
for a QAPP is not workable for the many owners and operators who plan to determine their GHG
emissions based on utility fuel bills or invoices. For example, natural gas supply meters are
frequently owned or operated by the utility, and the facility purchasing the natural gas cannot
control or specify the maintenance, repair or recordkeeping for these meters. To resolve this
issue, we recommend that EPA not require a QAPP for situations where a fuel flow meter or
other measurement device is owned/operated by the fuel supplier rather than the facility
owner/operator. The accuracy required for commercial sale of the fuel will be sufficient to meet
the GHG reporting needs.
Response: See the Preamble, Section II. M., and separate comment response document volume
for the response on the general recordkeeping requirements.
The requirement for a QAPP has been replaced by a facility Monitoring Plan under §98.3. The
Monitoring Plan does not require a description of the supplier's QA procedures but should
indicate which pieces of data are provided by the suppliers. The commenter should note that
EPA has revised Subpart C to clarify that facilities are not responsible for the calibration and on-
going QA of fuel billing meters provided that the fuel supplier and the unit(s) combusting the
458
-------
fuel do not have any common owners and are not owned by subsidiaries or affiliates of the same
company.
Commenter Name: Vince Brisini
Commenter Affiliation: RRI Energy Inc. (RRI)
Document Control Number: EPA-HQ-OAR-2008-0508-0618.1
Comment Excerpt Number: 10
Comment: U.S. EPA should clarify in its GHG reporting rule that facilities currently reporting
under Part 75 and applying Tier 4 methodology to those affected EGUs — are not required to
report GHG emissions by fuel type. In §98.36(b)(5), U.S. EPA proposes to require reporters to
calculate GHG emissions by each type of fuel combusted; however, the Tier 4 methodology
described in the proposed GHG reporting rule, like calculation methods described in Part 75,
specify that CO2 mass emissions and heat input are calculated by combining all fuel types
combusted in a unit. Therefore, it is unnecessary and burdensome for reporters using Tier 4
calculation methods as required by Part 75 to report CO2 emissions by fuel type from these
combustion units.
Response: EPA acknowledges the commenter's concerns, and has addressed this issue in the
final rule. Section 98.36(b)(7) of the final rule states that, for Tier 4 units, the annual CO2
emissions will be reported for all fuels combined, and that any biogenic C02 emissions will also
be reported separately. It also states that CH4 and N2O emissions are to be reported for each
type of fuel combusted, calculated in accordance with §98.33(c). In §98.33(c)(3), EPA has
specified that reporters using Tier 4 are to use the best available estimates of the annual heat
input from each type of fuel combusted in the unit during the reporting year, excluding fuel used
only for startup or ignition. This can be from CEMS data or engineering calculations. Using this
data they are to calculate CH4 and N2O emissions for each fuel type.
In revising the final version of the rule, EPA has also added §98.36(d) to define data reporting
requirements for units subject to Part 75, which requires total emissions by unit, not by fuel.
EPA believes that these provisions in the final rule effectively address the concerns of the
commenters.
Commenter Name: Alison A. Keane
Commenter Affiliation: National Paint & Coatings Association, Inc. (NPCA/FSCT)
Document Control Number: EPA-HQ-OAR-2008-0508-0593.1
Comment Excerpt Number: 10
Comment: Requiring submission after request within 7 days is unwarranted. While records
maintained onsite will be available upon request - it will often take more time to compile and
submit. EPA should provide a 30 day period in which to fulfill a data submission request. In
addition, request for data submissions should only be made via hard copy mail - submission of
these requests electronically may not always make it to the right facility or the right individual at
the facility and the facility should not be held responsible for faulty electronic communications.
459
-------
Response: EPA acknowledges the commenter's concerns. In Section 98.36(e)(3) of the final
rule, EPA has allowed owners or operators 30 days from receipt of a written request for
information to respond to that request.
EPA does not believe that it is necessary to specify that requests for data submissions be made
via hard copy mail. EPA believes that electronic requests are sufficiently reliable.
Commenter Name: Michael DiMauro
Commenter Affiliation: Massachusetts Municipal Wholesale Electric Company (MMWEC)
Document Control Number: EPA-HQ-OAR-2008-0508-0580
Comment Excerpt Number: 12
Comment: The types of information that are considered "company records" for the purpose of
documenting fuel usage under Tier I and II should be clarified. In particular: i. It should be
verified that manually or automatically collected fuel flow data measured by certified or
uncertified fuel meters qualify as "company records" of fuel usage suitable for use in Tier I or
Tier II monitoring. A Unit that has a design heat input < 250 MMBtu should not be pushed into
Tier III fuel sampling simply because fuel usage is determined from fuel meter flow records
rather from fuel supplier shipment delivery slip records, ii. It should be verified that manually or
automatically collected Oil Tank Drop measurements qualify as "company records" of oil fuel
usage suitable for use in Tier I or Tier II monitoring, iii. It should be clarified that for sources
that: (a) operate multiple oil fired stationary combustion units whose individual design heat
inputs are < 250 MMBtu and whose combined design heat Inputs > 250 MMBtu/hr, and (b) who
supply oil to these multiple stationary units from one or more non-dedicated Oil Storage tanks, it
is acceptable to use fuel delivery invoices to document total oil usage for these combustion units,
under the Tier I or Tier II monitoring schemes.
Response: EPA acknowledges the commenter's concerns, and has defined the term "company
records" in §98.6 of the final rule. EPA believes that the revised definition provides appropriate
guidance as to what records a facility may use to determine fuel consumption. EPA does not
intend that the presence of a fuel flow meter will require a unit to calculate emissions using Tier
3. For units that use Tiers 1, 2, and 3 to calculate CO2 mass emissions, the cumulative 250
mmBtu/hr heat input capacity limit on the aggregation of units into a group has been dropped.
Rather, the 250 mmBtu/hr restriction applies only to the individual units in the group. Therefore,
for reporting purposes, individual units with maximum rated heat input capacities of 250
mmBtu/hr or less may be aggregated without limit into a single group, provided that the Tier 4
methodology is not required for any of the units, and all units in the group use the same Tier for
any common fuel(s) that they combust.
460
-------
Commenter Name: J. Michael Kennedy
Commenter Affiliation: Florida Electric Power Coordinating Group
Document Control Number: EPA-HQ-OAR-2008-0508-0473.1
Comment Excerpt Number: 13
Comment: Under §98.36(b), EPA proposes to require unit level reporting of various pieces of
information not only for Subpart C combustion sources, but also for ARP units. Although most
of the information specified in §98.36(b) is not burdensome to report, the data required under
(b)(5) would be for some units. Proposed §98.36(6)(5) would require the reporting of calculated
C02, CH4, and N20 data for each fuel type combusted at the unit. Units using continuous
monitoring methods, like CO2/O2 CEMS and volumetric flow monitors (to calculate heat input)
generally do not employ instrumentation to record when a different fuel is being combusted. For
example, a coal-fired unit that uses oil to startup would monitor CO2/O2 and volumetric flow all
the way through the startup process and past the point when coal enters the boiler without
recordation of when the change in fuel took place. Similarly, some oil and gas-fired units may
switch between the two fuels, or even co-fire oil and gas, without recording which fuel type was
responsible for the emissions and flow. For such units, it simply is not possible to provide
estimates of emissions by fuel type without addition of what might be complicated, expensive,
and otherwise unnecessary instrumentation. Therefore, FCG urges EPA to remove the provision
from the rule.
Response: EPA acknowledges the commenter's concerns, and has addressed this issue in the
final rule. Section 98.36(b)(7) of the final rule states that, for Tier 4 units, the annual CO2
emissions will be reported for all fuels combined, and that any biogenic C02 emissions will also
be reported separately. It also states that CH4 and N2O emissions are to be reported for each
type of fuel combusted, calculated in accordance with §98.33(c). In §98.33(c)(3), EPA has
specified that reporters using Tier 4 are to use the best available estimates of the annual heat
input from each type of fuel combusted in the unit during the reporting year, excluding fuel used
only for startup or ignition. This can be from CEMS data or engineering calculations. Using this
data they are to calculate CH4 and N2O emissions for each fuel type.
In revising the final version of the rule, EPA has also added §98.36(d) to define data reporting
requirements for units subject to Part 75, which requires total emissions by unit, not by fuel.
EPA believes that these provisions in the final rule effectively address the concerns of the
commenters.
Commenter Name: Kelly R. Carmichael
Commenter Affiliation: NiSource
Document Control Number: EPA-HQ-OAR-2008-0508-1080.2
Comment Excerpt Number: 13
Comment: Ni Source supports the aggregation approaches for unit-level reporting identified in
Part 98.36(c). Part 98.36(c)(1) allows aggregate reporting for up to 250 MMBtu/hr of
combustion sources at a facility and Part 98.36(c)(3) allows multiple gas-fired or oil-fired units
fed through a common fuel line to report combined emissions for those units. This aggregate
reporting provides reasonable approaches to reporting detail while providing operators the
461
-------
opportunity to consider logical groupings within a facility. NiSource strongly supports these
aggregate approaches for reporting combustion emissions.
Response: EPA appreciates the commenter's support. For units that use Tiers 1, 2, and 3 to
calculate C02 mass emissions, the cumulative 250 mmBtu/hr heat input capacity limit on the
aggregation of units into a group has been dropped. Rather, the 250 mmBtu/hr restriction applies
only to the individual units in the group. Therefore, for reporting purposes, individual units with
maximum rated heat input capacities of 250 mmBtu/hr or less may be aggregated without limit
into a single group, provided that the Tier 4 methodology is not required for any of the units, and
all units in the group use the same Tier for any common fuel(s) that they combust. Units with
maximum rated heat inputs greater than 250 mmBtu/hr must report as individual units, unless
they burn the same type of fuel (oil or gas) provided by a common pipe or supply line; in that
case, the owner or operator may opt to use the common pipe reporting provisions in
§98.36(c)(3). Units using Tier 4 must report as individual units unless they share a monitored
common stack; in that case, the common stack reporting provisions of §98.36(c)(2) may be used.
Commenter Name: Kelly R. Carmichael
Commenter Affiliation: NiSource
Document Control Number: EPA-HQ-OAR-2008-0508-1080.2
Comment Excerpt Number: 14
Comment: To avoid confusion during implementation and provide reporting consistency,
NiSource recommends that EPA specify the horsepower (hp) equivalent to 250 MMBtu/hr.
Combustion capacity at many facilities is permitted based on horsepower rating rather than firing
rate and presenting the horsepower equivalent will ensure that the aggregation threshold is
consistently implemented for subject facilities. In our discussions with member companies of
INGAA, NiSource agrees with INGAA recommendation that the rule indicate that aggregation
for combustion reporting can be based on 250 MMBtu/hr or 30,000 hp. Similarly, the 30,000 hp
equivalency to 250 MMBtu/hr should be used for defining whether a Tier 1 or Tier 2 approach
can be used for an individual source (i.e., larger sources must use Tier 3 or Tier 4).
Response: EPA has not defined a horsepower equivalent to the maximum rated heat input
capacity defined in §98.36 of the final rule. It is straightforward for an individual facility to
carry out unit conversions as internal guides for applicability, and EPA may consider similar
conversions as part of guidance to stakeholders. Nevertheless, having multiple thresholds in
different units would add complexity to the applicability determination, going against the
overwhelming majority of comments requesting more streamlining of the threshold
determination.
462
-------
Commenter Name: Traylor Champion
Commenter Affiliation: Georgia-Pacific, LLC (GP)
Document Control Number: EPA-HQ-OAR-2008-0508-0380.1
Comment Excerpt Number: 26
Comment: Notwithstanding our preferred approach of using the Tier 1 methodology on fuels
coming across the fenceline, the common pipe aggregation should be expanded to solid fuels
such as coal and petroleum coke. As with natural gas and oil, facilities that use solid fossil fuels
track very closely the amount of fuel purchased and actually used by adjustments to inventory
since it is, in most cases, a significant part of the overall energy cost. They also carefully
monitor the heat content of these fuels to assure that the fuel meets specifications. Accounting
for and reporting solid fuel usage more detailed than at the fenceline provides no additional value
in terms of facility emissions, yet adds a significant and unnecessary reporting burden.
Response: EPA acknowledges the concerns of the commenter. The common pipe reporting
option in §98.36(c)(3) applies only to liquid and gaseous fuels. However, the unit aggregation
option in §98.36(c)(1) applies to units combusting any type of fuel, including solid fuel. In the
final rule, the cumulative 250 mmBtu/hr heat input capacity limit on the aggregation of units into
a group has been dropped. Rather, the 250 mmBtu/hr restriction applies only to the individual
units in the group. Therefore, for reporting purposes, individual units with maximum rated heat
input capacities of 250 mmBtu/hr or less may be aggregated without limit into a single group,
provided that the Tier 4 methodology is not required for any of the units, and all units in the
group use the same Tier for any common fuel(s) that they combust.
Commenter Name: Ron Downey
Commenter Affiliation: LWB Refractories
Document Control Number: EPA-HQ-OAR-2008-0508-0719.1
Comment Excerpt Number: 35
Comment: 40 C.F.R. 98.36 requires unit or process-specific reporting of combustion emissions.
The physical configuration of some lime plants do not lend themselves to unit-specific emissions
calculations because one fuel feed system may support multiple kilns. The Proposed Rule's
objective to collect facility-level data is not undermined by permitting facility-wide reporting of
combustion fuel emissions. The Proposed Rule should follow the Western Climate Initiative's
Final Draft of Essential Requirements of Mandatory Reporting, which permits facility-wide
reporting of combustion fuel emissions. In accordance with 40 C.F.R. 98.37, source can retain
any unit-specific emissions information in company records and make it available for review
upon request by EPA. Facility-wide reporting of combustion emissions satisfies EPA's objective
of developing facility-wide emissions information, without requiring businesses in highly
competitive industries to disclose highly sensitive confidential business information.
Response: See the Preamble, Section II. R., and the response to comment EPA-HQ-OAR-2008-
0508-0520.1 excerpt 16 for EPA's response on CBI. Also see the response to the same comment,
comment EPA-HQ-OAR-2008-0508-0520.1, excerpt 16 for the response to the need for unit-
level data, additional flexibility EPA has provided for aggregation and common pipe
configurations at facilities.
463
-------
Commenter Name: Lorraine Krupa Gershman
Commenter Affiliation: American Chemistry Council (ACC)
Document Control Number: EPA-HQ-OAR-2008-0508-0423.2
Comment Excerpt Number: 73
Comment: In §98.36(d), the verification data is far greater than that required by any other rule.
Instead of submitting this data annually and requiring excessive reporting, ACC recommends
that facilities should be required to maintain this data and produce it upon request. In
§98.36(d)(l)(i) requirements for verification data for Tier 3 methodology, where a process gas is
being combusted, the submittal of daily data on quantity of fuel combusted, carbon content of the
fuel, and molecular weight of the fuel is excessive. ACC recommends that monthly sampling be
allowed unless and until a facility can show through a statistical analysis that a different and
possibly less frequent sampling analysis may be appropriate. Further, these results should be
shifted over to §98.37 Recordkeeping instead of requiring submittal of daily (or monthly)
information for each of the variables used in the Tier 3 calculation methodology. At the most,
EPA should not require reporting of more data than of monthly averages.
Response: EPA does not agree with the commenter's assertion that the verification data is far
greater than that required by any other rule, or that the amount of unit-level data and verification
information to be reported electronically is excessive, burdensome, or unnecessary. See the
response to comment EPA-HQ-OAR-2008-0508-0520.1 excerpt 16 for EPA's response to the
need for unit-level data, including additional flexibility EPA has provided for aggregation and
common pipe configurations at facilities.
However, the final rule addresses some of the commenter's concerns. In particular, for gaseous
fuels other than natural gas or biogas, the daily sampling requirement has been retained, but only
for facilities with existing equipment in place that is capable of providing the data. Otherwise,
weekly sampling is required. EPA is requiring this frequency because of the potential variability
in process gas compared to commercial gaseous fuels. The commenter's suggestion to use
statistical analysis to show that less frequent sampling is acceptable has merit. However, no
details of the statistical method to be used for the demonstration were provided. Therefore, EPA
has not incorporated the commenter's suggestion, but is willing to consider it in a future
rulemaking, if an appropriate demonstration method is provided for Agency review.
Commenter Name: Marc J. Meteyer
Commenter Affiliation: Compressed Gas Association (CGA)
Document Control Number: EPA-HQ-OAR-2008-0508-0981.1
Comment Excerpt Number: 26
Comment: The proposed rule requires reporting of GHG emissions for each type of fuel
combusted. It is not clear if the expectation is discrete, or combined, reporting of the GHG
emissions for each/all fuel types. Separate reporting of GHG emissions from the combustion of
each discrete fuel type increases the risk that confidential business information (operating rates,
fuel choices, operating efficiencies) could be revealed in reports accessible to domestic and
464
-------
international competitors and customers of the regulated source. Further, when C02 emissions
are calculated using the Tier 4 method, there is no way to distinguish which CO2 emissions come
from each individual fuels. CGA Comment: EPA should clarify that emission reporting is
required only for the combined emissions from all fuels combusted. Reporting emissions for
each fuel separately should not be required. Additionally, provisions to protect the
confidentiality of all process, production and business- related information required under the
rule should be strengthened. While CGA accepts that facility-level emissions cannot be
protected from public disclosure, it strongly requests all other information should, by default, be
considered confidential business information and afforded the utmost protection from public
disclosure.
Response: EPA acknowledges the commenter's concerns, and has addressed this issue in the
final rule. Units calculating emissions using Tiers 1, 2, or 3 must report emissions by fuel type.
However, §98.36(b)(7) of the final rule states that, for Tier 4 units, the annual CO2 emissions
will be reported for all fuels combined, and that any biogenic C02 emissions will also be
reported separately. It also states that CH4 and N2O emissions are to be reported for each type of
fuel combusted, calculated in accordance with §98.33(c). In §98.33(c)(3), EPA has specified
that reporters using Tier 4 are to use the best available estimates of the annual heat input from
each type of fuel combusted in the unit during the reporting year, excluding fuel used only for
startup or ignition. This can be from CEMS data or engineering calculations. Using this data
they are to calculate CH4 and N20 emissions for each fuel type.
In revising the final version of the rule, EPA has also added §98.36(d) to define data reporting
requirements for units subject to Part 75, which requires total emissions by unit, not by fuel.
EPA believes that these provisions in the final rule effectively address the concerns of the
commenters.
See the Preamble, Section II. R., and the response to comment EPA-HQ-OAR-2008-0508-
0520.1 excerpt 16 for EPA's response on CBI.
Commenter Name: Juanita M. Bursley
Commenter Affiliation: GrafTech International Holdings Inc. Company (GrafTech)
Document Control Number: EPA-HQ-OAR-2008-0508-0686.1
Comment Excerpt Number: 26
Comment: GrafTech requests EPA to re-evaluate the selection of its proposed requirements for
reporting unit-level data, to simplify the report and reduce the burden on the regulated
community, particularly if a facility meets the criteria and opts to aggregate its smaller
combustion units into "process-level" groups or combine units supplied by a common fuel
supply piping configuration for reporting purposes. In the majority of cases, the Tier 1 or Tier 2
reporting methods would be acceptable to estimate emissions from these groups of combustion
units. In particular, requiring the additional reporting of the unit types and maximum rated heat
input of each unit is excessively burdensome, considering the likelihood that many reporting
facilities have large numbers of fuel combustion units. Furthermore, requiring such detailed
information would essentially negate the simplification provided by allowing the facility to
aggregate multiple units for emissions reporting, and this information is not necessary to verify
data. And lastly, GrafTech is concerned that in industries such as the carbon and manufactured
465
-------
graphite industry, which typically operate numerous fuel-fired process equipment, this level of
detail would potentially provide what is considered proprietary information on production
capabilities to competitors, putting companies with large production facilities in the U.S. that
have to report at an economic disadvantage.
Response: See the Preamble, Section II. R., and the response to comment EPA-HQ-OAR-2008-
0508-0520.1 excerpt 16 for EPA's response on CBI. Also see the response to the same comment,
comment EPA-HQ-OAR-2008-0508-0520.1, excerpt 16 for the response to the need for unit-
level data, additional flexibility EPA has provided for unit aggregation and common pipe
configurations at facilities.
Commenter Name: Robert Rouse
Commenter Affiliation: The Dow Chemical Company
Document Control Number: EPA-HQ-OAR-2008-0508-0533.1
Comment Excerpt Number: 26
Comment: Dow Suggests that the Type and Quantity of Fuel Combusted in Each Source
Should Be Relocated to Section 98.37 (Recordkeeping). In 98.36(b) and (c), there are situations
when the fuel-type might be Confidential Business Information (CBI). For example, a facility
may not want to identify to competitors how much process off-gas is recovered and burned.
Individual emission units should not be required to report their fuel type, and EPA should not
require it to be reported. This detail should be moved from the reporting section to the
recordkeeping section of this rule. Dow Supports the Reporting Alternative for Stationary
Combustion Units for Small Units and Suggests Raising the Aggregate Limit to < 750 mm
Btu/hr. Dow supports the general concept of aggregating small combustion units as proposed in
98.36(c)(1). Dow suggests that large petrochemical complexes be able to combine sources
together as long as the maximum rated heat input capacity of each unit is < 250 mm Btu/hr and
the aggregate maximum rate heat input capacity of the units does not exceed 750 mm Btu/hr.
The proposed aggregate limit of 250 mm Btu/hr will result in some larger complexes still having
to report a number of smaller sources on a unit-level basis. Dow Supports EPA's Proposed
Common Pipe Configuration Concept. Dow supports the general concept of reporting combined
emissions from units served by common supply line as outlined in 98.36(c)(3). Dow Suggests
that the Majority of the Items Listed under Proposed 98.36(d) "Verification Data" be Removed
from the Reporting Section of the Rule and Relocated to the Recordkeeping Portion of the Rule
in 98.37. General - The verification data is more excessive than is submitted under any other
existing State or Federal emissions inventory rule. Dow realizes that EPA has chosen the
position of self-certification with EPA verification. Dow supports this position and suggests that
this goal can be accomplished by either a review of records by agencies or the submittal of the
details contained in 98.36(d) for "one" of the regulated combustion sources at a site. In general,
instead of submitting this data annually and requiring excessive reporting, facilities should be
required to maintain this data and produce it upon request. EPA's proposed reporting
requirements are unnecessarily burdensome, far beyond what is required for future policy
decisions. Specific Comments - In 98.36(d)(l)(iii)(A - E), the requirements for verification data
for Tier 3 methodology, where a process gas is being combusted, the submittal of daily data on
quantity of fuel combusted, carbon content of the fuel, and molecular weight of the fuel are
excessive. Dow recommends that monthly sampling be allowed unless and until a facility can
show through a statistical analysis that a different and possibly less frequent sampling analysis
466
-------
may be appropriate. Further, these results should be moved to 98.37 on Recordkeeping instead
of requiring submittal of daily (or monthly) information for each of the variables used in the Tier
2 calculation methodology. At the most, EPA should not require reporting of more than monthly
average values. In 98.36(d)( 1 )(iii)(F) and (I), the requirement for submittal of the results of the
initial calibrations and periodic recalibrations of the fuel flow meters used to measure the amount
of fuel combusted is another example of a requirement that should be a recordkeeping
requirement only. These calibration records do not lend themselves well to electronic reporting,
and submittal of this information for all flow meters is not necessary for EPA to verify the
quality of the GHG emissions information provided. In 98.36(d)(iv)(F), Dow suggests that EPA
move the requirements to report linearity checks and cylinder gas audits to the recordkeeping
portion of this rule. Reporting of RATA results should be clarified such that a summary report
of the results vs. the details of the RATA evaluation is acceptable. Dow Suggests Revisions to
Proposed 98.36(d)(2). EPA's proposal requires an entity to respond within 7 days of receiving a
written request or email. Dow suggests that this response time be extended to 30 days to ensure
that the request is forwarded to the proper personnel and that they have ample time respond to
such requests. This would alleviate complications that may arise if the appropriate personnel do
not receive the requests immediately or have off-site commitments for a short period of time
(such as auditing or project work or even vacation).
Response: See the Preamble, Section II. R., and the response to comment EPA-HQ-OAR-2008-
0508-0520.1 excerpt 16 for EPA's response on CBI.
EPA does not agree with the commenter's assertion that the amount of unit-level data and
verification information to be reported electronically is excessive, burdensome, or unnecessary.
For this mandatory GHG emissions reporting rule, two main approaches to data verification were
considered, i.e., EPA verification and third-party verification. EPA decided on the former
approach. In view of this, the reporting of additional, unit-level information is deemed necessary
to provide assurance that the reported facility-wide GHG emissions data are both credible and
accurate. However, as explained in the paragraphs below, EPA has made a number of significant
adjustments in the final rule to the data reporting requirements of §98.36, both to clarify those
requirements and to reduce the reporting burden.
For units that use Tiers 1, 2, and 3 to calculate CO2 mass emissions, the cumulative 250
mmBtu/hr heat input capacity limit on the aggregation of units into a group has been dropped.
Rather, the 250 mmBtu/hr restriction applies only to the individual units in the group. Therefore,
for reporting purposes, individual units with maximum rated heat input capacities of 250
mmBtu/hr or less may be aggregated without limit into a single group, provided that the Tier 4
methodology is not required for any of the units, and all units in the group use the same Tier for
any common fuel(s) that they combust. Units with maximum rated heat inputs greater than 250
mmBtu/hr using Tiers 1, 2, and 3 must report as individual units, unless they burn the same type
of fuel provided by a common pipe or supply line; in that case, the owner or operator may opt to
use the common pipe reporting provisions in §98.36(c)(3). Units using Tier 4 must report as
individual units unless they share a monitored common stack; in that case, the common stack
reporting provisions of §98.36(c)(2) may be used.
The Tier 2 and 3 fuel sampling requirements in §98.34 have been substantially relaxed. EPA
believes that the provisions in the final rule will pose less of a burden on reporters.
467
-------
The supplementary verification information requirements of §98.36(e) have been clarified and,
in some cases, differ substantively from the proposed rule. Paragraph (e)(1) in §98.36 clearly
states that no additional verification information is required for sources that monitor and report
emissions and heat input data using Part 75. For sources using Tiers 1, 2, 3, and 4, the final rule
streamlines some of the reporting. Sources using Tier 3 are required to report only monthly
averages of the fuel carbon content and molecular weight rather than the proposed requirement to
submit the results of each individual determination. Sources that use Tier 4 are required to report
quarterly cumulative CO2 mass emissions, rather than the proposed requirement to report daily
C02 emissions. Also, to address concerns raised by some of the commenters, the certification
and QA test reporting requirements of Tiers 3 and 4 have been clarified. The final rule requires
only that records be kept of the CEMS and fuel flow meter QA tests and the methods used. The
test results are not required to be reported electronically or in hard copy, but must be made
available to EPA and/or the State agencies upon request. In §98.36(e)(3) of the final rule, EPA
has allowed owners or operators 30 days from receipt of a written request for information to
respond to that request.
Regarding the use of statistical analysis to justify less frequent fuel sampling, the suggestion has
merit. However, no details of the statistical method to be used for such a demonstration were
provided. Therefore, EPA has not incorporated the commenter's suggestion, but is willing to
consider it in a future rulemaking, if an appropriate demonstration method is provided for
Agency review.
Commenter Name: Marc J. Meteyer
Commenter Affiliation: Compressed Gas Association (CGA)
Document Control Number: EPA-HQ-OAR-2008-0508-0981.1
Comment Excerpt Number: 27
Comment: The proposed rule offers the option to calculate and report emissions for aggregated
units under the provisions of §98.36(c)(1), (2), and (3). These are effective methods by which a
source can streamline the process measurement, emission calculation, and emission reporting
requirements. CGA Comment: CGA strongly support the optional aggregation provisions and
encourages EPA to consider expanding the applicability of such options. For example,
eliminating the restriction of the aggregated maximum capacity of 250 mm BTU/hr under
§98.36(c)(1) would not compromise the accuracy or completeness of the reported data, but could
reduce the emission calculation and reporting burden and provide some additional protection to
confidential business information.
Response: EPA appreciates the commenter's support, and has made a number of significant
adjustments in the final rule to the data reporting requirements of §98.36, both to clarify those
requirements and to reduce the reporting burden. For units that use Tiers 1, 2, and 3 to calculate
CO2 mass emissions, the cumulative 250 mmBtu/hr heat input capacity limit on the aggregation
of units into a group has been dropped. Rather, the 250 mmBtu/hr restriction applies only to the
individual units in the group. Therefore, for reporting purposes, individual units with maximum
rated heat input capacities of 250 mmBtu/hr or less may be aggregated without limit into a single
group, provided that the Tier 4 methodology is not required for any of the units, and all units in
the group use the same Tier for any common fuel(s) that they combust. Units with maximum
rated heat inputs greater than 250 mmBtu/hr using Tiers 1, 2, and 3 must report as individual
468
-------
units, unless they burn the same type of fuel provided by a common pipe or supply line; in that
case, the owner or operator may opt to use the highest Tier required for a grouped unit for the
calculation method with the common pipe reporting provisions in §98.36(c)(3). Units using Tier
4 must report as individual units unless they share a monitored common stack; in that case, the
common stack reporting provisions of §98.36(c)(2) may be used.
Commenter Name: Marc J. Meteyer
Commenter Affiliation: Compressed Gas Association (CGA)
Document Control Number: EPA-HQ-OAR-2008-0508-0981.1
Comment Excerpt Number: 28
Comment: The proposed rule describes in detail all the information required to be reported in
order to verify the reported GHG emissions. The data compilation for all the information EPA
seeks under §98.36(d) is extremely burdensome for regulated sources. While some of this
information is used in order to develop, and assure the accuracy of, the emissions estimate,
reporting all of this information is not necessary. In many cases, the necessity of this
information is questionable, based on the rule's intention to develop an annual emissions
estimate. Examples include §98.36(d)(l)(iv)(A) - number of operating hours per day of a
particular emission source and §98.36(d)(l)(iv)(C) - daily C02 emissions (when an annual total
is the rule's objective). Reporting at this level of detail also increases the risk that confidential
business information could be revealed in reports accessible to domestic and international
competitors and customers of the regulated source. CGA Comment: Regulated sources should
only be required to maintain the appropriate information that supports the emissions calculations
and reporting basis, and make this information available upon request of EPA. Reporting of any
information unrelated to emissions should not be required. All process, production and business-
related information required to be reported under provisions to insure the veracity of the reported
emissions should be afforded the maximum confidentiality protections.
Response: See the Preamble, Section II. R., and the response to comment EPA-HQ-OAR-2008-
0508-0520.1 excerpt 16 for EPA's response on CBI. Also see the same response to comment
EPA-HQ-OAR-2008-0508-0520.1 excerpt 16 for the response to the need for unit-level data,
including additional flexibility EPA has provided for aggregation and common pipe
configurations at facilities.
EPA has not finalized the requirements to report daily CO2 emissions or the number of unit
operating hours per day. Sections 98.36(e)(2)(vi)(A) and (B) require facilities to report only the
number of annual unit operating hours and the cumulative CO2 mass emissions in each quarter
of the reporting year.
469
-------
Commenter Name: Marc J. Meteyer
Commenter Affiliation: Compressed Gas Association (CGA)
Document Control Number: EPA-HQ-OAR-2008-0508-0981.1
Comment Excerpt Number: 29
Comment: The proposed rule appears to require the source report its CEMS relative accuracy
test audit (RATA) results. It is not clear if EPA would be satisfied by a singular statement that
the CEMS passed or failed the RATA, or if the intent is to submit the entire RATA report which,
in addition to being many pages in length, often contains confidential business information.
CGA Comment: Clarify that EPA does not want a source to submit its entire RATA report and
instead, will be satisfied with a singular statement that the RATA was conducted (by whom and
on what date) and the results of the RATA, as a pass/fail designation.
Response: EPA acknowledges the commenter's concerns, and has included additional language
to §98.36(e)(2)(iv)(E) and (F), clarifying that reporters are required to submit the dates and
summarized results of the QA tests (e.g., RATAs) performed during the reporting year. The rule
does not require facilities to submit detailed test run information or hard copy test reports.
Commenter Name: Kimberly S. Lagomarsino
Commenter Affiliation: Mississippi Lime
Document Control Number: EPA-HQ-OAR-2008-0508-1568
Comment Excerpt Number: 24
Comment: 40 CFR 98.36(d) requires that monthly and daily data details be included in the
reported data. It is Mississippi Lime Company's understanding that the annual GHG reports to
EPA may be filed electronically. As such, the requested data details will involve manually
entering significant amounts of data; a redundant endeavor of capturing data previously
generated through facility accounting mechanisms. Suggestion: Please revise 98.36(d) to allow
for detailed information to be maintained in on-site records available for review upon request
versus being submitted in the annual reports.
Response: EPA intends to develop electronic reporting tools that will reduce the manual entry
burden, particularly for data that are used in multiple calculations. EPA also intends to explore
bulk upload options that take advantage of facilities' existing electronic data management
systems. See the response to comment EPA-HQ-OAR-2008-0508-0520.1 excerpt 16 for the
response to the need for unit-level data, including additional flexibility EPA has provided for
unit aggregation and common pipe configurations at facilities.
470
-------
Commenter Name: Sarah B. King
Commenter Affiliation: DuPont Company
Document Control Number: EPA-HQ-OAR-2008-0508-0604.1
Comment Excerpt Number: 31
Comment: EPA should modify §98.36(b) and (c) to allow a facility to report only the total C02
for a facility instead of unit-specific calculation and reporting. This is advantageous to EPA as a
Registry calculation tool because it will capture smaller sources and make the total Registry
more complete. Many facilities do not currently have the meters installed that would be
necessary to perform unit-by-unit calculations. Even those that have unit metering capability
primarily utilize them for rough cost allocations. The additional calibration and maintenance
requirements and the need for uninterrupted operation necessary to comply with the proposed
rule are additional examples of how the proposed approach to such calculations would be
burdensome and excessive, while not adding to the overall use of the information to develop a
greenhouse gas inventory.
Response: The purpose of the rule is not solely to develop a GHG inventory, but to inform the
development of future climate policy under the Clean Air Act. See the response to comment
EPA-HQ-OAR-2008-0508-0520.1 excerpt 16 for the response to the need for unit-level data,
including additional flexibility EPA has provided for aggregation and common pipe
configurations at facilities.
Commenter Name: Juanita M. Bursley
Commenter Affiliation: GrafTech International Holdings Inc. Company (GrafTech)
Document Control Number: EPA-HQ-OAR-2008-0508-0686.1
Comment Excerpt Number: 23
Comment: GrafTech agrees with the EPA's proposal under §98.36(c)(1) and (c)(3), to allow a
facility to aggregate combustion units for the purpose of simplifying its calculations for
estimating GHG emissions. According to this proposed language, a facility can 1) aggregate
smaller combustion units into "process-level" groups, as long as the combined maximum rated
heat input capacity is < 250 mmBtu/hr per group and provided the amount of fuel use can be
accurately quantified, or 2) combine units supplied by a common fuel supply piping
configuration if there is a calibrated fuel flow meter, with no restriction on the total maximum
rated heat input capacity of the group. In fact, GrafTech believes that aggregating smaller
combustion units into "process-level" groups should also not be limited to groups having
combined maximum rated heat input capacity is < 250 mmBtu/hr, provided the facility has
sufficient monitoring/metering systems to accurately quantify the amount of fuel used. While
this maximum rated heat input capacity may be consistent with the definition of a large unit
under other regulatory programs, this added limitation in this case will not improve the quality of
GHG emissions data, but may cause a facility the unnecessary burden to add or upgrade current
fuel metering systems. This flexibility will allow each facility to monitor fuel use, collect data
and calculate emissions in the most efficient way for its operations, without negatively affecting
the accuracy or consistency of the submitted emissions data, and without unnecessary added
costs of installing or upgrading fuel metering systems. However, this flexibility will be wholly
negated if the facility has to install CEMS simply because a combustion unit exceeds 1,000 hours
471
-------
of operations (see above comments). Furthermore, GrafTech believes it is commonplace for a
reporting facility to have multiple combustion units supplied by a common fuel supply piping
configuration, where the primary, or in many cases the only, fuel flow meter is the billing meter
owned and operated by the fuel supplier. In this case, GrafTech believes that the supplier, rather
than the combustion facility, should be responsible under this GHG reporting rule for meeting
calibration and all the other requirements associated with maintaining this fuel use monitoring
system in good operating order and retaining the required recordkeeping for documentation
purposes. The amount of fuel used, in this case, should be quantified through the use of purchase
receipts or similar billing records provided to the facility by the fuel supplier. Since the
supplier's metering system is used for billing purposes, it would be expected to be properly
maintained so as to provide accurate measurements of the facility's fuel use. As nearly all GHG
reporting facilities will have such fuel purchase records from the supplier, this will be the most
efficient and least burdensome method for facilities to obtain fuel usage data.
Response: See the response to comment EPA-HQ-OAR-2008-0508-0520.1 excerpt 16 for the
response to the need for unit-level data, including additional flexibility EPA has provided for
aggregation and common pipe configurations at facilities.
EPA has made a number of significant adjustments in the final rule to the data reporting
requirements of §98.36, both to clarify those requirements and to reduce the reporting burden.
For units that use Tiers 1, 2, and 3 to calculate CO2 mass emissions, the cumulative 250
mmBtu/hr heat input capacity limit on the aggregation of units into a group has been dropped.
Rather, the 250 mmBtu/hr restriction applies only to the individual units in the group. Therefore,
for reporting purposes, individual units with maximum rated heat input capacities of 250
mmBtu/hr or less may be aggregated without limit into a single group, provided that the Tier 4
methodology is not required for any of the units, and all units in the group use the same Tier for
any common fuel(s) that they combust. Units with maximum rated heat inputs greater than 250
mmBtu/hr must report as individual units, unless they burn the same type of fuel (oil or gas)
provided by a common pipe or supply line; in that case, the owner or operator may opt to use the
highest Tier required for a grouped unit for the calculation method with the common pipe
reporting provisions in §98.36(c)(3). Units using Tier 4 must report as individual units unless
they share a monitored common stack; in that case, the common stack reporting provisions of
§98.36(c)(2) may be used.
Units are not required to install CEMS unless all of the criteria under §98.33 (b)(4)(ii) are met.
The rule has been clarified to affirm that the use of fuel sampling results provided by the fuel
supplier is permissible, and that the use of fuel billing records to quantify fuel consumption is
also allowed.
Also, EPA has revised Subpart C to clarify that facilities are not responsible for the calibration
and on-going QA of fuel billing meters provided that the fuel supplier and the unit(s) combusting
the fuel do not have any common owners and are not owned by subsidiaries or affiliates of the
same company.
472
-------
Commenter Name: Lauren E. Freeman
Commenter Affiliation: Hunton & Williams LLP
Document Control Number: EPA-HQ-OAR-2008-0508-0493.1
Comment Excerpt Number: 36
Comment: In §98.36(b), EPA proposes to require unit-level reporting of various items of
information not only for Subpart C combustion sources, but for all units reporting under Subpart
D. See Proposed §98.46. Although much of the information specified in §98.36(b) is not
particularly burdensome to report, reporting the data that EPA proposes to require under
§98.36(b)(5) would be burdensome for some units. Proposed §98.36(b)(5) would require the
reporting of calculated CO2, CH4, and N2O data for each fuel type combusted at the unit. Units
using continuous monitoring methods, like C02 or 02 CEMS and volumetric flow monitors (to
calculate heat input), generally do not employ instrumentation to record when a different fuel is
being combusted. For example, a coal-fired unit that uses oil to startup would monitor C02/02
and volumetric flow all the way through the startup process and past the point when coal enters
the boiler without recording when the change in fuel took place. Similarly, some oil- and gas-
fired units may switch between the two fuels, or even co-fire oil and gas, without recording
which fuel or fuels were responsible for the emissions and flow. For such units, it simply is not
possible to provide estimates of emissions by fuel type without addition of what might be
complicated, expensive, and otherwise unnecessary instrumentation. Nor does UARG
understand why such data are needed to fulfill Congress' mandate. EPA should remove this
proposed provision or limit its application to units that already have the instrumentation or other
means to make the calculation. If EPA retains the proposed requirement, EPA must describe
why the information is needed, estimate the costs of gathering this information, and provide
sufficient time for installation of equipment.
Response: EPA acknowledges the commenter's concerns, and has addressed this issue in the
final rule. Section 98.36(b)(7) of the final rule states that, for Tier 4 units, the annual C02
emissions will be reported for all fuels combined, and that any biogenic C02 emissions will also
be reported separately. It also states that CH4 and N20 emissions are to be reported for each
type of fuel combusted, calculated in accordance with §98.33(c). In §98.33(c)(3), EPA has
specified that reporters using Tier 4 are to use the best available estimates of the annual heat
input from each type of fuel combusted in the unit during the reporting year, excluding fuel used
only for startup or ignition. This can be from CEMS data or engineering calculations. Using this
data they are to calculate CH4 and N20 emissions for each fuel type.
In revising the final version of the rule, EPA has also added §98.36(d) to define data reporting
requirements for units subject to Part 75, which requires total emissions by unit, not by fuel.
EPA believes that these provisions in the final rule effectively address the concerns of the
commenters.
473
-------
Commenter Name: Ron Downey
Commenter Affiliation: LWB Refractories
Document Control Number: EPA-HQ-OAR-2008-0508-0719.1
Comment Excerpt Number: 37
Comment: 40 C.F.R. 98.36(d)(l)(i) and (ii) requires sources to report fuel usage in short tons
for solid fuels. However, 40 C.F.R. 98.36(d)((l)(iii) requires sources to report the amount of
fuel combusted in metric tons. LWB recommends that EPA revise the Proposed Rule to require
sources using the Tier 1, 2, and 3 calculation methodologies to report fuel usage in metric tons,
to coincide with sector reporting. If this comment is accepted, the emission factors in Table C-l
should be updated reflect "mmBtu/metric ton."
Response: EPA believes that it is appropriate to report solid fuel usage in short tons. EPA has
revised the Tier 3 reporting requirements in §98.36 to require reporting fuel usage in short tons
for solid fuels, consistent with the other Tiers.
Commenter Name: Fiji George
Commenter Affiliation: El Paso Corporation
Document Control Number: EPA-HQ-OAR-2008-0508-0398.1
Comment Excerpt Number: 43
Comment: El Paso fully supports the aggregation of small combustion units that have a
combined maximum rated heat input capacity of 250 mmBtu/hr or less to simplify unit-level
reporting.
Response: EPA appreciates the commenter's support, and has made a number of significant
adjustments in the final rule to the data reporting requirements of §98.36, both to clarify those
requirements and to reduce the reporting burden. For units that use Tiers 1, 2, and 3 to calculate
CO2 mass emissions, the cumulative 250 mmBtu/hr heat input capacity limit on the aggregation
of units into a group has been dropped. Rather, the 250 mmBtu/hr restriction applies only to the
individual units in the group. Therefore, for reporting purposes, individual units with maximum
rated heat input capacities of 250 mmBtu/hr or less may be aggregated without limit into a single
group, provided that the Tier 4 methodology is not required for any of the units, and all units in
the group use the same Tier for any common fuel(s) that they combust.
Commenter Name: See Table 5
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0480.1
Comment Excerpt Number: 44
Comment: Section 98.36(d)(2) identifies the requirements for operator response to agency
requests regarding methods for quantifying fuel consumption and requires a response within 7
days of receipt of a written request. INGAA recommends that this requirement be revised to
allow at least two weeks for such a response. A seven day response time is not adequate when
474
-------
considering the timing involved to review and process the request. For example, if key
personnel are on business travel or otherwise out of the office for only a few days, that could
severely hinder the ability to respond within 7 days. Two weeks or more should be allowed and
this schedule is still indicative of an expeditious response to an agency request.
Response: EPA acknowledges the commenter's concerns. In §98.36(e)(3) of the final rule, EPA
has allowed owners or operators 30 days from receipt of a written request for information to
respond to that request.
Commenter Name: Fiji George
Commenter Affiliation: El Paso Corporation
Document Control Number: EPA-HQ-OAR-2008-0508-0398.1
Comment Excerpt Number: 44
Comment: §98.36(d)(2) requires that facilities submit a response (explanation) to any written
request from the administrator within seven days of receipt of such request. Depending on the
severity and complexity of the request it may not be possible to complete a proper response in
seven days. El Paso recommends the administrator provide at least ten business days to respond
and the option to request an automatic, 30-day extension if reasonably necessary in light of the
nature and extent of the required response.
Response: EPA acknowledges the commenter's concerns. In §98.36(e)(3) of the final rule, EPA
has allowed owners or operators 30 days from receipt of a written request for information to
respond to that request.
Commenter Name: Gregory A. Wilkins
Commenter Affiliation: Marathon Oil Corporation
Document Control Number: EPA-HQ-OAR-2008-0508-0712.1
Comment Excerpt Number: 53
Comment: Marathon supports EPA's proposal that facilities may group units that burn a
common fuel if the group does not exceed 250 mmBtu/hr. There is no limit to the number of
groups allowed per facility. This will help reduce cost by allowing very small individual
stationary sources like engines (assuming they are not exempted from this rule) to be aggregated
together and estimated one time, EPA states in the Preamble that for liquid and gas fired units
smaller than 250 mmBtufhr, the use of Tier 1 and 2 methodology is allowed if emission factors
arc listed by the EPA. Tier 1 and 2 use default or measured heating value, default CO2 factors
and measured or estimated fuel consumption.
Response: EPA appreciates the commenter's support, and has made a number of significant
adjustments in the final rule to the data reporting requirements of §98.36, both to clarify those
requirements and to reduce the reporting burden. For units that use Tiers 1, 2, and 3 to calculate
CO2 mass emissions, the cumulative 250 mmBtu/hr heat input capacity limit on the aggregation
of units into a group has been dropped. Rather, the 250 mmBtu/hr restriction applies only to the
individual units in the group. Therefore, for reporting purposes, individual units with maximum
475
-------
rated heat input capacities of 250 mmBtu/hr or less may be aggregated without limit into a single
group, provided that the Tier 4 methodology is not required for any of the units, and all units in
the group use the same Tier for any common fuel(s) that they combust.
Commenter Name: Gregory A. Wilkins
Commenter Affiliation: Marathon Oil Corporation
Document Control Number: EPA-HQ-OAR-2008-0508-0712.1
Comment Excerpt Number: 57
Comment: Marathon opposes the extensive additional reporting requirements required by
Subpart C. EPA is proposing to require additional facility level information like unit types,
maximum rated heat capacity for each unit, type and amount of fuel combusted by each unit, and
unit level total GHG emissions. Other reporting requirements include all fuel carbon content
values, information on substitute values, and flow meter calibration information. For one facility
this could get very burdensome for every carbon content sample alone. Marathon does not see
the value in reporting this information as it is not essential for anything besides verification of
emission calculation (which was discussed previously in the comments). Marathon reminds
EPA that with the common pipe allowance it will be almost impossible to determine fuel use and
corresponding GHG emissions by unit if multiple units are supplied from a single fuel drum.
Marathon proposes that these reporting requirements be removed from this subpart and instead
allow for activity and sampling information to be kept as records by the facility using current
data collection methods. This information could then be made available to EPA if they were to
conduct an inspection.
Response: See the response to comment EPA-HQ-OAR-2008-0508-0520.1 excerpt 16 for the
response to the need for unit-level data, including additional flexibility EPA has provided for
aggregation and common pipe configurations at facilities.
EPA notes that the supplementary verification information requirements of §98.36(e) have been
clarified and, in some cases, differ substantively from the proposed rule. Paragraph (e)(1) in
§98.36 clearly states that no additional verification information is required for sources that
monitor and report emissions and heat input data using Part 75. For sources using Tiers 1, 2, 3,
and 4, the final rule streamlines some of the reporting. Sources using Tier 3 are required to
report only monthly averages of the fuel carbon content and molecular weight rather than the
proposed requirement to submit the results of each individual determination.
Commenter Name: See Table 3
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0433.2
Comment Excerpt Number: 65
Comment: The text incorrectly refers to Equation C-14, should be C-13.
Response: EPA has corrected this error in the final rule.
476
-------
Commenter Name: Ron Downey
Commenter Affiliation: LWB Refractories
Document Control Number: EPA-HQ-OAR-2008-0508-0719.1
Comment Excerpt Number: 30
Comment: Sources are required to report the maximum rated heat input capacity of combustion
units, in mmBtu/hr for boilers, combustion turbines, engines, and process heaters only. 40
C.F.R. 98.36(b)(3). LWB requests clarification that the maximum rated heat input capacity of a
unit is equal to the design capacity of the unit. We also would like confirmation that the term
"process heaters" refers to all combustion equipment used to provide heat for the process that has
a nameplate capacity.
Response: EPA believes the terms "maximum rated heat input capacity" and "design capacity"
are equivalent and that both refer to the maximum amount of fuel of known Btu content that a
unit is capable of combusting on a steady state basis, as of the initial installation of the unit, as
specified by the manufacturer.
EPA does not believe that any additional language is necessary to clarify the term "process
heaters." EPA uses the term "process heaters" to refer to a wide variety of devices in which heat
is transferred indirectly to a process material, but do not produce electrical or steam load.
Nameplate capacity is not one of the necessary criteria for a combustion source to be included in
this category.
Commenter Name: Renae Schmidt
Commenter Affiliation: CITGO Petroleum Corporation
Document Control Number: EPA-HQ-OAR-2008-0508-0726.1
Comment Excerpt Number: 15
Comment: CITGO assumes that the aggregation of small units §98.36(cXl) applies to Tier 2
combustion sources with a common stack. A note of this understanding is recommended in
§98.36(c)(2) paragraph for Monitored common stack configurations.
Response: It is EPA's intent that the common stack provisions in §98.36(c)(2) be used only for
Tier 4 units using CEMS at the common stack. EPA has substantially revised §98.36(c)(1).
According to the final rule, individual units with maximum rated heat input capacities of 250
mmBtu/hr or less may be aggregated without limit into a single group, provided that the Tier 4
methodology is not required for any of the units, and all units in the group use the same Tier for
any common fuel(s) that they combust. EPA does not believe that any further language is
necessary to clarify that units meeting these requirements and sharing a common stack may be
aggregated according to §98.36(c)(1).
477
-------
Commenter Name: J. P. Blackford
Commenter Affiliation: American Public Power Association (APPA)
Document Control Number: EPA-HQ-OAR-2008-0508-0661.1
Comment Excerpt Number: 1
Comment: APPA supports the flexibility allowed by the Draft Rule for data aggregation, as it is
generally less onerous for reporting entities and has no major objections with the level of
reporting aggregation included in the Draft Rule. In order to calculate the aggregated emissions,
specific data from individual sources will need to be collected and managed. APPA does offer
the suggestion that while in most cases multiple units may share a single stack, there are also
some configurations at our member utilities where a single unit has multiple stacks (one example
is a Pratt and Whitney "Twin Pack" which has two turbines and two stacks but is one unit).
Since these units use natural gas as their fuel source, this issue would not be of significance at
this time, but, it is offered to inform EPA of some alternate configurations for EGUs.
Response: EPA appreciates this comment, and is aware of less common unit/stack
configurations such as the one identified by the commenter.
Commenter Name: Jeffrey A. Sitler
Commenter Affiliation: University of Virginia (UVA)
Document Control Number: EPA-HQ-OAR-2008-0508-0675.1
Comment Excerpt Number: 4
Comment: When aggregating small units as described in §98.36(c)(1), is there a limit to the
number of units that can be aggregated into a group or is the only requirement that the aggregate
maximum rated heat input capacity of all units in the group does not exceed 250mmBtu/hr?
Response: EPA acknowledges the commenter's concerns, and believes that the final rule
includes further clarification on this topic. The rule language does not limit aggregation to a
specific number of units. However, EPA has made a number of significant adjustments in the
final rule to the data reporting requirements of §98.36 to clarify reporting requirements and to
reduce the reporting burden for aggregated units.
For units that use Tiers 1, 2, and 3 to calculate C02 mass emissions, the cumulative 250
mmBtu/hr heat input capacity limit on the aggregation of units into a group has been dropped.
Rather, the 250 mmBtu/hr restriction applies only to the individual units in the group. Therefore,
for reporting purposes, individual units with maximum rated heat input capacities of 250
mmBtu/hr or less may be aggregated without limit into a single group, provided that the Tier 4
methodology is not required for any of the units, and all units in the group use the same Tier for
any common fuel(s) that they combust. Units with maximum rated heat inputs greater than 250
mmBtu/hr using must report as individual units, unless they burn the same type of fuel provided
by a common pipe or supply line; in that case, the owner or operator may opt to use the highest
Tier required for a grouped unit for the calculation method and the common pipe reporting
provisions in §98.36(c)(3). Units using Tier 4 must report as individual units unless they share a
monitored common stack; in that case, the common stack reporting provisions of §98.36(c)(2)
may be used.
478
-------
Commenter Name: Rhea Hale
Commenter Affiliation: American Forest & Paper Association (AF&PA)
Document Control Number: EPA-HQ-OAR-2008-0508-0909.1
Comment Excerpt Number: 5
Comment: AF&PA agrees with EPA's inclusion of the provisions in section 98.36(c) Reporting
Alternatives for Stationary Combustion Units. These provisions allow the use of common pipe
configurations and monitored common stack configurations options would preclude the need to
install fuel meters on individual units. These options should be allowed for all combustion units
at a facility provided they meet the requirements of 98.36(c). It is extremely important to retain
these provisions as facilities would need to schedule the installation of fuel meters on individual
combustion units in order for the meters to be operational at the start of the 2010 reporting
period. Installation of such meters would need to take place during scheduled mill outages,
many of which occur on a greater than 12 month rotation schedule particularly for large
combustion units. For example, a pulp mill that experienced major outage in May of 2009 may
not see another major outage until fall of 2010, well after the collection of GHG data is to begin.
In order to comply with the reporting rule, a compliant GHG estimation system needs to be in
place by January 1, 2010 (see Initial Reporting Year comments below). A second GHG
reporting system would need to be implemented for use after January 1, 2011. It is far more cost
and resource effective to create a single information collection and reporting system to
commence after appropriate equipment can be installed (e.g., in 2010 for use in 2011), rather
than to do so twice (once for 2010 and then again for 2011). A Tier 1 type system could be
installed and operated beginning in 2010. The more sophisticated, expensive and unnecessary
systems (Tier 2, 3 and 4) could not.
Response: See the Preamble, Section II. G., for the response on the selection of the initial
reporting year.
The final rule requires data collection for calendar year 2010, but has been changed since
proposal to allow use of best available monitoring methods for the first part of 2010.
Furthermore, the commenter should note that the final rule does not require fuel flow meters
used for Tier 3 calculations to be calibrated until January 1, 2011.
The final rule includes further clarification and flexibility regarding aggregation and common
pipe provisions that will reduce the burden on sources. EPA has retained the provision requiring
fuel use in a common pipe configuration to be accurately measured by a calibrated fuel flow
meter, and has clarified that Tier 3 methods are to be used for all common pipe configurations.
Units using Tier 4 CEMS, may also use the common stack reporting provisions of §98.36(c)(2).
479
-------
Commenter Name: Sarah B. King
Commenter Affiliation: DuPont Company
Document Control Number: EPA-HQ-OAR-2008-0508-0604.1
Comment Excerpt Number: 7
Comment: EPA proposes to require a response to a written request within 7 days. Such
response time is unreasonable and unnecessary. Furthermore, the lack of immediate availability
of such data poses no threat to human health and the environment as GHG emissions and climate
change are not acute issues, but manifest over the long-term. EPA should allow facilities a
reasonable period of time - a minimum of 30 days - to respond to such requests. EPA should
also allow a further extension if the facility has extenuating circumstances.
Response: EPA acknowledges the commenter's concerns. In §98.36(e)(3) of the final rule, EPA
has allowed owners or operators 30 days from receipt of a written request for information to
respond to that request.
Commenter Name: John M. McManus
Commenter Affiliation: American Electric Power
Document Control Number: EPA-HQ-OAR-2008-0508-0725.1
Comment Excerpt Number: 10
Comment: AEP has a concern that §98.46(a) would subject electric generation facilities that are
subject to the ARP to §98.3 6(b), which would require unit level reporting of various pieces of
information. Although most of such information would not be burdensome to report, the data
that would be required under §98.36(b)(5) would be burdensome for some units to report. That
provision could require the reporting of calculated CO2, CH4, and N2O data for each fuel type
combusted at the unit. That would be a problem for units that use CEMS, since such methods
generally do not employ instrumentation to record what type of fuel is being combusted at any
point in time. AEP requests that EPA either delete §98.36(b)(5) or limit its application to units
that already have the instrumentation or other means to calculate CO2, CH4, and N2O emissions
data by fuel type.
Response: EPA acknowledges the commenter's concerns, and has addressed this issue in the
final rule. Section 98.36(b)(7) of the final rule states that, for Tier 4 units, the annual CO2
emissions will be reported for all fuels combined, and that any biogenic CO2 emissions will also
be reported separately. It also states that CH4 and N2O emissions are to be reported for each
type of fuel combusted, calculated in accordance with §98.33(c). In §98.33(c)(3), EPA has
specified that reporters using Tier 4 are to use the best available estimates of the annual heat
input from each type of fuel combusted in the unit during the reporting year, excluding fuel used
only for startup or ignition. This can be from CEMS data or engineering calculations. Using this
data they are to calculate CH4 and N2O emissions for each fuel type.
In revising the final version of the rule, EPA has also added §98.36(d) to define data reporting
requirements for units subject to Part 75, which requires total emissions by unit, not by fuel.
EPA believes that these provisions in the final rule effectively address the concerns of the
commenters.
480
-------
Commenter Name: [Name Not Given]
Commenter Affiliation: Graphic Arts Coalition (GAC)
Document Control Number: EPA-HQ-OAR-2008-0508-0701.1
Comment Excerpt Number: 11
Comment: Requiring submission after request within 7 days is unwarranted. EPA should
provide a 30 day period in which to fulfill a data submission request. In addition, request for
data submissions should only be made via hard copy.
Response: EPA acknowledges the commenter's concerns. In §98.36(e)(3) of the final rule, EPA
has allowed owners or operators 30 days from receipt of a written request for information to
respond to that request.
EPA does not believe that it is necessary to specify that requests for data submissions be made
via hard copy mail. EPA believes that electronic requests are sufficiently reliable.
Commenter Name: Keith Overcash
Commenter Affiliation: North Carolina Division of Air Quality (NCDAQ)
Document Control Number: EPA-HQ-OAR-2008-0508-0588
Comment Excerpt Number: 11
Comment: Consistent with reporting for criteria and hazardous pollutants, reporting should be
done at the unit/process level. We are concerned that 98.36(c), which permits aggregation of
combustion units, will not allow separation of different combustion device types and different
fuels. We support aggregation of small units if the device and fuel type are the same; if this is
the intention of 98.36(c), then this should be clarified.
Response: EPA acknowledges the commenter's concerns and agrees that reporting in specific
cases (identified in Subpart C) should be done at the unit level. However, EPA believes that the
unit-level information that is reported in the case of aggregated units (i.e., unit ID numbers,
maximum rated heat input capacity, etc.) is sufficient for the purposes of this rule because the
aggregation provision applies to homogenous fuels and smaller units, which require less
intensive data for verification under EPA's approach of linking data intensity to significance of
the source. It is EPA's intention to allow the aggregation of any units with a maximum rated heat
input capacity less than 250 mmBtu/hr, provided that the use of Tier 4 is not required or elected
for any of the units, and that the units use the same Tier for any common fuels they combust.
EPA believes that the unit aggregation provision as written in the final rule provides an
appropriate balance between easing the burden on reporters and gathering useful data on GHG
emissions.
481
-------
Commenter Name: Marc J. Meteyer
Commenter Affiliation: Compressed Gas Association (CGA)
Document Control Number: EPA-HQ-OAR-2008-0508-0981.1
Comment Excerpt Number: 25
Comment: The proposed rule requires calculation and reporting of GHG emissions at the "unit-
level" (unless the aggregation options of §98.36(c) are employed). Reporting emissions at the
unit-level goes beyond the policy development intention of the reporting rule and increases the
risk that confidential business information (operating rates, fuel choices, operating efficiencies)
could be revealed in reports accessible to domestic and international competitors and customers
of the regulated source. CGA Comment: Emission reporting should be required at the facility-
level only by source type. Reporting at the unit-level should not be required. Additionally,
provisions to protect the confidentiality of all process, production and business-related
information required under the rule should be strengthened. While CGA accepts that facility-
level emissions cannot be protected from public disclosure, it strongly requests all other
information should, by default, be considered confidential business information and afforded the
utmost protection from public disclosure.
Response: See the Preamble, Section II. R., and the response to comment EPA-HQ-OAR-2008-
0508-0520.1 excerpt 16 for EPA's approach to CBI.
Also see the to the same comment, comment EPA-HQ-OAR-2008-0508-0520.1, excerpt 16 for
the response to the need for unit-level data, including additional flexibility EPA has provided for
aggregation and common pipe configurations at facilities.
Commenter Name: Renae Schmidt
Commenter Affiliation: CITGO Petroleum Corporation
Document Control Number: EPA-HQ-OAR-2008-0508-0726.1
Comment Excerpt Number: 14
Comment: For reasons stated earlier, CITGO disagrees with the reporting requirements of
§98.36(b)(6) and §98.36(b)(9) for CH4 and N2O calculations from combustion sources. For
paragraph §98.36(b)(6), the sentences appears to have left out Tier 3 calculation methodology
(Tier 3 does not use Part 75 calculation methodology).
Response: EPA has substantially revised §98.36. The final rule addresses data reporting
requirements for all Tiers.
See the Preamble, Section II. C., and the response to comment EPA-HQ-OAR-2008-0508-
0561.1 excerpt 2 for information on the rationale for reporting for CH4 and N2O.
EPA believes that the use of fuel-specific emission factors for these pollutants strikes an
appropriate balance between minimizing the burden on reporters and obtaining valuable GHG
emission data. EPA has, however, revised the final rule to exclude CH4 and N2O emissions
from fuels for which the rule does not provide emission factors, and has deleted the provision
482
-------
allowing the owner or operator of a facility to develop site-specific emission factors for such
fuels. EPA believes that this change will reduce the reporting burden on facilities.
Commenter Name: See Table 6
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0679.1
Comment Excerpt Number: 99
Comment: Page 16631/Sec 98.32: Stationary combustion units are required to report at the unit
level. Reporting at the unit level is overly burdensome. In Section 98.36(c)(3) on Page 16637,
aggregation of small units is permitted; however, some sites have no metering. API requests the
use of small unit aggregation methods based on parameters such as design capacity, hours of
operation, load, and fuel characteristics.
Response: See the response to comment EPA-HQ-OAR-2008-0508-0520.1 excerpt 16 for the
response to the need for unit-level data, including additional flexibility EPA has provided for
aggregation and common pipe configurations at facilities.
Commenter Name: Renae Schmidt
Commenter Affiliation: CITGO Petroleum Corporation
Document Control Number: EPA-HQ-OAR-2008-0508-0726.1
Comment Excerpt Number: 16
Comment: CITGO disagrees that the following information should be reported (but rather
maintained in the records): Tier 2 Calculation Methodology (§98.36(dXii): (B) Monthly high
heat values used in the equations (0) Indication of actual or substituted value Tier 3 Calculation
Methodology (§98.36(dXiii): (B) Number of required carbon content determinations for each
fuel (C) Each carbon content value used (D) Indication of actual or substituted value (E) Dates
and results of calibrations - should only report exceptions (H) Methods used to determine carbon
content (I) Methods used to calibrate fuel flow meters These types of records are suitable for
calculation tools such as process historians, database systems, and spreadsheet calculations.
Transfer of this information into another (and currently unknown) electronic report system is
completely unnecessary to achieve intended reporting rule objectives. At our largest refinery,
there are over 50 heaters and boilers with nearly 100 fuel gas meters. Reporting all of the above
information is completely unnecessary. Reporting should focus on the core emission data,
source identification, and exceptions to any requirements.
Response: See the response to comment EPA-HQ-OAR-2008-0508-0520.1 excerpt 16 for the
response to the need for unit-level data, including additional flexibility EPA has provided for
aggregation and common pipe configurations at facilities.
EPA has made a number of significant adjustments in the final rule to the data reporting
requirements of §98.36, both to clarify those requirements and to reduce the reporting burden.
EPA is allowing facilities to keep more records on-site, and submit them within 30 days of a
483
-------
written request from the Administrator or from the applicable state or local air pollution control
agency (see §98.36(e)(3).)
The final rule retains the requirement to report monthly HHV values and to use flags to indicate
whether each is an actual, measured value or is substitute data. However, the proposed Tier 3
requirement to report all carbon content and molecular weight values has been relaxed. Only
monthly average values of these parameters are required to be reported. Further, the final rule
requires only that records be kept of the CEMS and fuel flow meter QA tests and the methods
used. The test results are not required to be reported electronically or in hard copy, but must be
made available to EPA and/or the State agencies upon request.
Commenter Name: Caroline Choi
Commenter Affiliation: Progress Energy
Document Control Number: EPA-HQ-OAR-2008-0508-0439.1
Comment Excerpt Number: 16
Comment: Under 98.36(b), EPA proposes to require unit level reporting of various pieces of
information not only for Subpart C combustion sources, but also for ARP units. Although most
of the information specified in 98.36(b) is not burdensome to report, the data required under
(b)(5) would be for some units. Proposed 98.36(b)(5) would require the reporting of calculated
C02, CH4, and N20 data, for each fuel type combusted at the unit. Units using continuous
monitoring methods, like CO2/O2 CEMS and volumetric flow monitors (to calculate heat input)
generally do not employ instrumentation to record when a different fuel is being combusted. For
example, a coal-fired unit that uses oil to startup would monitor CO2/O2 and volumetric flow all
the way through the startup process and past the point when coal enters the boiler without
recordation of when the change in fuel took place. Similarly, some oil and gas-fired units may
switch between the two fuels, or even co-fire oil and gas, without recording which fuel type was
responsible for the emissions and flow. For such units, it is not possible to provide estimates of
emissions by fuel type without addition of what might he complicated, expensive, and otherwise
unnecessary instrumentation. Therefore, Progress Energy urges EPA to remove the provision
from the rule.
Response: EPA acknowledges the commenter's concerns, and has addressed this issue in the
final rule. Section 98.36(b)(7) of the final rule states that, for Tier 4 units, the annual CO2
emissions will be reported for all fuels combined, and that any biogenic CO2 emissions will also
be reported separately. It also states that CH4 and N2O emissions are to be reported for each
type of fuel combusted, calculated in accordance with §98.33(c). In §98.33(c)(3), EPA has
specified that reporters using Tier 4 are to use the best available estimates of the annual heat
input from each type of fuel combusted in the unit during the reporting year, excluding fuel used
only for startup or ignition. This can be from CEMS data or engineering calculations. Using this
data they are to calculate CH4 and N2O emissions for each fuel type.
In revising the final version of the rule, EPA has also added §98.36(d) to define data reporting
requirements for units subject to Part 75, which requires total emissions by unit, not by fuel.
EPA believes that these provisions in the final rule effectively address the concerns of the
commenters.
484
-------
Commenter Name: Kyle Pitsor
Commenter Affiliation: National Electrical Manufacturers Association (NEMA)
Document Control Number: EPA-HQ-OAR-2008-0508-0621.1
Comment Excerpt Number: 21
Comment: The NEMA Carbon/Manufactured Graphite EHS Committee agrees with the EPA's
proposal under §98.36(c)(1) and (c)(3), to allow a facility to aggregate combustion units for the
purpose of simplifying its calculations for estimating GHG emissions. According to this
proposed language, a facility can 1) aggregate smaller combustion units into "process-level"
groups, as long as the combined maximum rated heat input capacity is < 250 mmBtu/hr per
group and provided the amount of fuel use can be accurately quantified, or 2) combine units
supplied by a common fuel supply piping configuration if there is a calibrated fuel flow meter,
with no restriction on the total maximum rated heat input capacity of the group. In fact, the
NEMA Carbon/Manufactured Graphite EHS Committee believes that aggregating smaller
combustion units into "process-level" groups should also not be limited to groups having
combined maximum rated heat input capacity is < 250 mmBtu/hr, provided the facility has
sufficient monitoring/metering systems to accurately quantify the amount of fuel used. While
this maximum rated heat input capacity may be consistent with the definition of a large unit
under other regulatory programs, this added limitation in this case will not improve the quality of
GHG emissions data, but may cause a facility the unnecessary burden to add or upgrade current
fuel metering systems. This flexibility will allow each facility to monitor fuel use, collect data
and calculate emissions in the most efficient way for its operations, without negatively affecting
the accuracy or consistency of the submitted emissions data, and without unnecessary added
costs of installing or upgrading fuel metering systems. However, this flexibility will be wholly
negated if the facility has to install CEMS simply because a combustion unit exceeds 1,000 hours
of operations.
Response: EPA appreciates the commenter's support, and has made a number of significant
adjustments in the final rule to the data reporting requirements of §98.36, both to clarify those
requirements and to reduce the reporting burden. For units that use Tiers 1, 2, and 3 to calculate
CO2 mass emissions, the cumulative 250 mmBtu/hr heat input capacity limit on the aggregation
of units into a group has been dropped. Rather, the 250 mmBtu/hr restriction applies only to the
individual units in the group. Therefore, for reporting purposes, individual units with maximum
rated heat input capacities of 250 mmBtu/hr or less may be aggregated without limit into a single
group, provided that the Tier 4 methodology is not required for any of the units, and all units in
the group use the same tier for any common fuel(s) that they combust. Units with maximum
rated heat inputs greater than 250 mmBtu/hr must report as individual units, unless they burn the
same type of fuel (oil or gas) provided by a common pipe or supply line; in that case, the owner
or operator may opt to use the highest tier required for a grouped unit for the calculation method
with the common pipe reporting provisions in §98.36(c)(3). Units using Tier 4 must report as
individual units unless they share a monitored common stack; in that case, the common stack
reporting provisions of §98.36(c)(2) may be used.
Additionally, a facility is required to install CEMS only if each of the criteria under
§98.33(b)(4)(ii) are met.
485
-------
Commenter Name: Kathy G. Beckett
Commenter Affiliation: West Virginia Chamber of Commerce
Document Control Number: EPA-HQ-OAR-2008-0508-0956.1
Comment Excerpt Number: 21
Comment: Under §98.36(b), EPA proposes to require unit level reporting of various pieces of
information not only for Subpart C combustion sources, but also for ARP units. See Proposed
§98.46(a). Although most of the information specified in §98.36(b) is not burdensome to report,
the data required under (b)(5) would be for some units. Proposed §98.36(b)(5) would require the
reporting of calculated C02, CH4, and N20 data for each fuel type combusted at the unit. Units
using continuous monitoring methods, like CO2/O2 CEMS and volumetric flow monitors (to
calculate heat input) generally do not employ instrumentation to record when a different fuel is
being combusted. For such units, it simply is not possible to provide estimates of emissions by
fuel type without addition of what might be complicated, expensive, and otherwise unnecessary
instrumentation. It is not obvious why such data are needed to fulfill Congress' mandate. EPA
should remove the provision or limit its application to units that already have the instrumentation
or other means to make the calculation. If EPA retains the requirement, EPA must describe why
the information is needed, estimate the costs of gathering this information, and provide sufficient
time for installation of equipment.
Response: EPA acknowledges the commenter's concerns, and has addressed this issue in the
final rule. Section 98.36(b)(7) of the final rule states that, for Tier 4 units, the annual C02
emissions will be reported for all fuels combined, and that any biogenic CO2 emissions will also
be reported separately. It also states that CH4 and N20 emissions are to be reported for each
type of fuel combusted, calculated in accordance with §98.33(c). In §98.33(c)(3), EPA has
specified that reporters using Tier 4 are to use the best available estimates of the annual heat
input from each type of fuel combusted in the unit during the reporting year, excluding fuel used
only for startup or ignition. This can be from CEMS data or engineering calculations. Using this
data they are to calculate CH4 and N2O emissions for each fuel type.
In revising the final version of the rule, EPA has also added §98.36(d) to define data reporting
requirements for units subject to Part 75, which requires total emissions by unit, not by fuel.
EPA believes that these provisions in the final rule effectively address the concerns of the
commenters.
See the Regulatory Impact Analysis (RIA) for a detailed description of EPA's cost estimates for
reporting under Subpart C.
Commenter Name: Patrick J. Nugent
Commenter Affiliation: Texas Pipeline Association (TPA)
Document Control Number: EPA-HQ-OAR-2008-0508-0460.1
Comment Excerpt Number: 22
Comment: TP A supports proposed §98.3 6(c), which would allow the use of specified reporting
alternatives for stationary combustion units in certain circumstances. This proposed rule takes a
486
-------
measured approach to EPA's data collection efforts that minimizes unnecessary burden on the
regulated community.
Response: EPA appreciates the commenter's support, and has made a number of significant
adjustments in the final rule to the data reporting requirements of §98.36, both to clarify those
requirements and to reduce the reporting burden. For units that use Tiers 1, 2, and 3 to calculate
C02 mass emissions, the cumulative 250 mmBtu/hr heat input capacity limit on the aggregation
of units into a group has been dropped. Rather, the 250 mmBtu/hr restriction applies only to the
individual units in the group. Therefore, for reporting purposes, individual units with maximum
rated heat input capacities of 250 mmBtu/hr or less may be aggregated without limit into a single
group, provided that the Tier 4 methodology is not required for any of the units, and all units in
the group use the same tier for any common fuel(s) that they combust. Units with maximum
rated heat inputs greater than 250 mmBtu/hr must report as individual units, unless they burn the
same type of fuel (oil or gas) provided by a common pipe or supply line; in that case, the owner
or operator may opt to use the highest tier required for a grouped unit for the calculation method
with the common pipe reporting provisions in §98.36(c)(3). Units using Tier 4 must report as
individual units unless they share a monitored common stack; in that case, the common stack
reporting provisions of §98.36(c)(2) may be used.
Commenter Name: Kyle Pitsor
Commenter Affiliation: National Electrical Manufacturers Association (NEMA)
Document Control Number: EPA-HQ-OAR-2008-0508-0621.1
Comment Excerpt Number: 22
Comment: The NEMA Carbon/Manufactured Graphite EHS Committee believes it is
commonplace for a reporting facility to have multiple combustion units supplied by a common
fuel supply piping configuration, where the primary, or in many cases the only, fuel flow meter
is the billing meter owned and operated by the fuel supplier. In this case, the NEMA
Carbon/Manufactured Graphite EHS Committee believes that the supplier, rather than the
combustion facility, should be responsible under this GHG reporting rule for meeting calibration
and all the other requirements associated with maintaining this fuel use monitoring system in
good operating order and retaining the required recordkeeping for documentation purposes. The
amount of fuel used, in this case, should be quantified through the use of purchase receipts or
similar billing records provided to the facility by the fuel supplier. Since the supplier's metering
system is used for billing purposes, it would be expected to be properly maintained so as to
provide accurate measurements of the facility's fuel use. As nearly all GHG reporting facilities
will have such fuel purchase records from the supplier, this will be the most efficient and least
burdensome method for facilities to obtain fuel usage data.
Response: EPA acknowledges the concerns of the commenters. Section 98.34(b)(l)(iii) of the
final rule provides that fuel billing meters are exempted from the calibration requirement,
"provided that the supplier and the unit(s) combusting the fuel do not have any common owners
and are not owned by subsidiaries or affiliates of the same company." Further, for Tiers 1 and 2,
the "company records" (see §98.6) used to quantify fuel usage include data from qualifying gas
billing meters. The nomenclature under Equations C-4 and C-5 in §98.33 also provide that data
from qualifying fuel billing meters may be used to determine fuel usage for the Tier 3 calculation
methodology.
487
-------
Commenter Name: Kimberly S. Lagomarsino
Commenter Affiliation: Mississippi Lime
Document Control Number: EPA-HQ-OAR-2008-0508-1568
Comment Excerpt Number: 22
Comment: 40 CFR 98.36 requires "the annual GHG emissions report shall contain the unit-
level or process-level emissions data..." as well as the "maximum rated heat input capacity of the
unit...." Such rated heat input capacity information, on a unit-level, is highly sensitive and
confidential business information. And, as previously noted, Mississippi Lime Company is
unable to determine exact process emissions on a kiln-by-kiln basis. Suggestion: Please revise
98.36 to allow for the facility-level reporting of emissions. In addition, please indicate that unit-
level information, as much as is available, must be retained on-site and must be available for
review upon request.
Response: See the Preamble, Section II. R., and the response to comment EPA-HQ-OAR-2008-
0508-0520.1 excerpt 16 for EPA's response on CBI. Also see the response to the same comment,
comment EPA-HQ-OAR-2008-0508-0520.1, excerpt 16 for the response to the need for unit-
level data, including additional flexibility EPA has provided for aggregation and common pipe
configurations at facilities. The response to this cited comment also indicates how this additional
flexibility may be useful for the Lime industry.
EPA has decided to retain the requirement to report the maximum rated heat input capacity of
each unit for boilers, combustion turbines, engines, and process heaters. EPA believes that the
definition of "maximum rated heat input capacity" in §98.6 clarifies that this term refers to "the
hourly heat input to a unit (in mmBtu/hr), when it combusts the maximum amount of fuel per
hour that it is capable of combusting on a steady state basis, as of the initial installation of the
unit, as specified by the manufacturer."
Commenter Name: See Table 3
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0433.2
Comment Excerpt Number: 23
Comment: The data reporting requirements of §98.36 will also require data processing updates
for many facilities with existing CEMs installations. These may arise from the need to capture
new information not already included in emission reports, adding calculations to compute
pollutant averages in the individual units as specified by the rule, or calculating emissions of
GHG emissions not directly measured by the facility. Furthermore, since the specific data
reporting requirements are not specified in the draft rule, but "will be provided" by the EPA,
additional facility resources will be required to implement the reporting requirements when they
are finalized. If release and implementation of the EPA-mandated reporting is at all like that of
40 CFR parts 75, these resources may be substantial. The lack of a predefined data reporting
format in the proposed rule should be addressed and subjected to public comment prior to
publication of any Final rule arising from this proposal.
488
-------
Response: See the Preamble and separate comment response document for the response on
collection, management, and dissemination of GHG emissions data.
The data reporting format for Part 98 is currently under development by EPA. The exact format
will be presented to the public as soon as possible, to allow time for the regulated sources to
become familiar with it. The Agency will base the reporting format on the data elements that are
required to be reported under the various Subparts of the rule.
Commenter Name: Sarah B. King
Commenter Affiliation: DuPont Company
Document Control Number: EPA-HQ-OAR-2008-0508-0604.1
Comment Excerpt Number: 12
Comment: EPA should recognize the reality that the most accurate and verifiable determination
of energy consumption based C02 emissions would result from applying emission factors to
sitewide fuel consumption, purchased electricity consumption, purchased steam consumption,
etc. The consumption of fuels, electricity and other energy-bearing materials (e.g., steam) is
easily verifiable using third-party invoices. This method in many cases provides a complete and
comprehensive accounting of sitewide combustion-based C02 emissions. Requirements to
report emissions at the combustion unit level do not improve the accounting of GHG emissions;
rather, they are likely to impose significant inaccuracies while substantially increasing the
burden in terms of investment in monitoring devices, costs of calibration and maintenance,
development and maintenance of data management systems, recordkeeping and personnel time
commitments. Inaccuracies occur due to flow meter errors, CEMS errors, unmonitored fugitive
errors and the multiplication of all these errors over dozens or hundreds of devices at a complex
facility. Rather than requiring the complex and costly methodologies for inherently less accurate
unit-based reporting of GHG emissions, EPA should emphasize the need to provide accurate
sitewide energy consumption-based GHG emissions reporting and allow a reasonable estimation
basis for distributing fuel, electricity and other energy-bearing materials - and their respective
GHG emissions - among combustion units and other operations. Reasonable estimations could
be made based on internal site fuel and electricity metering, process knowledge, and other
reasonable methods. The key point is that the sitewide GHG emission values would be accurate
and verifiable so that the national inventory of emissions would be accurate.
Response: See the Preamble, Section II. L., on General Monitoring Requirements for the overall
rationale for methodologies required under this rule, and the response to comment EPA-HQ-
OAR-2008-0508-0909.1 excerpt 4 and EPA-HQ-OAR-2008-0508-0580 excerpt 10 for the
rationale for methodologies required under Subpart C.
See the Preamble, Section II. D, for the selection of source categories to report.
Though EPA disagrees with the commenter's proposed monitoring approach, EPA has made a
number of significant adjustments in the final rule to the data reporting requirements of §98.36,
both to clarify those requirements and to reduce the reporting burden. For units that use Tiers 1,
2, and 3 to calculate CO2 mass emissions, the cumulative 250 mmBtu/hr heat input capacity
limit on the aggregation of units into a group has been dropped. Rather, the 250 mmBtu/hr
restriction applies only to the individual units in the group. Therefore, for reporting purposes,
489
-------
individual units with maximum rated heat input capacities of 250 mmBtu/hr or less may be
aggregated without limit into a single group, provided that the Tier 4 methodology is not
required for any of the units, and all units in the group use the same Tier for any common fuel(s)
that they combust. Units with maximum rated heat inputs greater than 250 mmBtu/hr using
Tiers 1, 2, and 3 must report as individual units, unless they burn the same type of fuel provided
by a common pipe or supply line; in that case, the owner or operator may opt to use the highest
Tier required for a grouped unit for the calculation method with the common pipe reporting
provisions in §98.36(c)(3). Units using Tier 4 must report as individual units unless they share a
monitored common stack; in that case, the common stack reporting provisions of §98.36(c)(2)
may be used.
Commenter Name: Robert D. Bessette
Commenter Affiliation: The Council of Industrial Boiler Owners (CIBO).
Document Control Number: EPA-HQ-OAR-2008-0508-0513.1
Comment Excerpt Number: 38
Comment: Regarding, §98.36(c)(1), aggregation is unduly limited in applicability by imposing
an aggregate maximum heat input capacity of 250 MMBtu/hr. There should be no aggregate
limit if a common fuel is used and the analytic data to determine total emissions is representative
of all units in the identified group. Imposing a limit of 250 MMBtu/hr is arbitrary and there is no
legal or policy rationale to justify imposing these additional compliance costs.
Response: EPA acknowledges the concerns of the commenter. EPA has made a number of
significant adjustments in the final rule to the data reporting requirements of §98.36, both to
clarify those requirements and to reduce the reporting burden. For units that use Tiers 1, 2, and 3
to calculate CO2 mass emissions, the cumulative 250 mmBtu/hr heat input capacity limit on the
aggregation of units into a group has been dropped. Rather, the 250 mmBtu/hr restriction applies
only to the individual units in the group. Therefore, for reporting purposes, individual units with
maximum rated heat input capacities of 250 mmBtu/hr or less may be aggregated without limit
into a single group, provided that the Tier 4 methodology is not required for any of the units, and
all units in the group use the same tier for any common fuel(s) that they combust.
Commenter Name: See Table 4
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0455.1
Comment Excerpt Number: 19
Comment: However, the Class of'85 urges EPA to reconsider its proposed verification
response period. As proposed, the rule allows only a seven-day verification response period. The
Class of'85 does not believe that, given the potential breadth of the data request contemplated by
this part, the proposed response period is appropriate or reasonable. Therefore, the Group urges
EPA to lengthen this response period to 30 days.
490
-------
Response: EPA acknowledges the commenter's concerns. In the final rule, EPA has allowed
owners or operators 30 days from receipt of a written request for verification information to
respond to that request.
Commenter Name: Lorraine Krupa Gershman
Commenter Affiliation: American Chemistry Council (ACC)
Document Control Number: EPA-HQ-OAR-2008-0508-0423.2
Comment Excerpt Number: 6
Comment: EPA should allow facilities more time to respond for data requests. Requiring a
response to a written request within seven days is an impossible deadline. A person might be on
vacation, and might not even see the request in that time period. While the records likely will be
readily available, it will take a bit of time to compile them and send them. Further, the timing to
produce the records may be in conflict with other legally required reporting obligations and
result in missing the deadline. EPA should allow a minimum of 30 days to fulfill a data
submission request, with an option for an extension if the facility requests it and explains why an
extension is needed. We are concerned about EPA's proposal to request data through an
electronic mailing to the facility. We believe it is important for EPA to request any data through
a hard copy mailing, with an additional electronic request if desired. Our concern is that facility
personnel and email addresses change over time, and it is very likely that a response sent only by
email would not be received in a timely manner. Further, with the proliferation of SPAM and
unwanted email, it is important that a facility be able to determine when it is in receipt of a
legitimate data request.
Response: EPA acknowledges the commenter's concerns. In the final rule, EPA has allowed
owners or operators 30 days from receipt of a written request for information to respond to that
request.
491
-------
9.
RECORDS THAT MUST BE RETAINED
Commenter Name: Lauren E. Freeman
Commenter Affiliation: Hunton & Williams LLP
Document Control Number: EPA-HQ-OAR-2008-0508-0493.1
Comment Excerpt Number: 37
Comment: EPA uses proposed §98.37 to restate which records must be kept under other
provisions of Subparts A and C, and to state which provisions require "no special
recordkeeping." This provision is unnecessary and confusing. If the recordkeeping requirements
in the other provisions are clearly stated, there is no need to repeat them in a separate provision.
If EPA wishes to highlight the fact that proposed §98.34(a) and (b) and §98.35(b)(2) include
recordkeeping requirements, that could be accomplished by including the word "recordkeeping"
in the section titles. UARG also notes that proposed §98.37 includes references to several
subsections that do not exist in the proposed Subpart — i.e., §98.35(a)(1), 98.35(a)(4). To the
extent this provision is intended to require retention of records created under Part 75 for more
than 3 years, UARG also objects to it for the reasons stated above in comments on Subpart A.
Response: EPA believes that the provisions of the revised §98.37 are appropriate and necessary.
The commenter should note that §98.37 no longer refers to §98.35(a)(1) or §98.35(a)(4).
492
-------
10. COST DATA
Commenter Name: See Table 10
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0635
Comment Excerpt Number: 20
Comment: CEMS are cost-effective. In most, if not all, of these cases, CO2 CEMS, at the least,
are available for one hundred thousand dollars or less - which is generally a very small
percentage of the total cost of a new facility. [Footnote: 142 Cf. EPA, EPA Air Pollution Costs
Manual (2002), available at: http://www.epa.gov/ttn/catc/dirl/c_allchs.pdf.]142 CEMS for other
gases are not substantially more expensive, and the price would certainly drop if the market for
these CEMS grew. Moreover, the overall societal value of a functioning carbon market will far
outweigh monitoring costs. Good data will create value here, just as it has in the Acid Rain
Program context, where the benefits of a well-functioning market have outweighed CEMS and
other system costs forty times over, [footnote: 143 See Lorraine G. Chestnut & David M. Mills,
A Fresh Look at the Benefits and Costs of the U.S. Acid Rain Program, 77 J. of Environ. Mgmt.
252, 266 (2005) (Ex. 18).]
Response: EPA agrees with the commenter that in many cases, CEMS are an appropriate means
to monitor CO2 emissions. EPA has retained the requirement for units meeting all the conditions
in §98.33(b) to use C02 or 02 CEMS to monitor their C02 emissions. Units that are already
required to monitor and report C02 under Part 75 will also continue to do so under Part 98.
However, EPA does not believe that it is appropriate to require all stationary combustion units to
install CO2 CEMS at this time, as this would be overly burdensome to regulated sources in the
context of a data-gathering program, regardless of potential future regulatory efforts.
Additionally, EPA is not implementing or planning to implement a cap and trade program for
GHGs at this time and is therefore has not designed this reporting rule specifically to support a
cap and trade program.
Commenter Name: Rhea Hale
Commenter Affiliation: American Forest & Paper Association (AF&PA)
Document Control Number: EPA-HQ-OAR-2008-0508-0909.1
Comment Excerpt Number: 10
Comment: AF&PA is concerned that the cost to the industry for Tier 4 methodology is
inconsistent with the stated goal of the proposed rule to minimize the burden on the industry.
The pulp and paper industry has over 105 boilers with fuel capacity greater than 250 MMBtu/hr
that burn coal as a primary or secondary fuel, of which a large portion have CEMs already
installed. The estimated cost to add C02 analyzers to these units ranges from $15,000 per unit to
$75,000 per unit depending on type of sample system, any necessary reconfiguration of the
system, and the potential addition of calibrated fuel flow meters or stack fuel gas flow monitors.
An estimated 75 boilers would require an additional $45,000 per unit in upfront costs which
could total $3.4 million dollars. This cost is unreasonable, particularly given the industry's
propensity to co-fired biomass which requires the use of emissions factors to calculate emissions
493
-------
despite the existence of CEMS. These costs do not include the additional maintenance
requirements and quality assurance costs that would be associated with additional CEMs.
Response: EPA is requiring the use of CEMS for solid fossil fuel-fired units due to the
complexity of monitoring solid fuel consumption and the heterogeneous nature of the solid fuels.
EPA has considered the commenter's analysis, but disagrees with the commenter's assessment of
the level of burden associated with installing and maintaining the concentration and volume
monitors that the rule requires be added to an existing CEMS. In the revised rule, EPA has
clarified that if the unit in question meets all six criteria then a C02 or 02 and a stack gas
volumetric flow rate monitor would be required to be installed. EPA's cost estimates are
annualized and fall within the range of capital costs cited in this comment. Further detail on the
engineering cost analysis for Subpart C can be found in RIA (EPA-HQ-OAR-2008-0318-002),
Section 4.3.
Commenter Name: Dale Backlund, Regulatory Affairs Leader, The DOW Chemical Company
and Victoria Evans, National Practice Leader for Greenhouse Gases, URS Corporation
Commenter Affiliation: None
Document Control Number: EPA-HQ-OAR-2008-0508-1338
Comment Excerpt Number: 4
Comment: Downscaling to reporting GHG emissions at the facility level is especially
burdensome for General Stationary Combustion sources for data Tiers 3 and 4. These require
individual monitoring on either monthly (Tier 3) or continuous (Tier 4) bases, for both the flow
and the fuel content. Additional costs for purchasing, installing, calibrating, maintaining,
recalibrating, and certifying these monitors, meters, and sensors on individual sources is
anticipated (see below). Since the greenhouse gas issue is on a tens of tons or hundreds of tons
basis, the cost of doing daily feed analysis or adding CEMS to the combustion device is not
warranted.
Response: EPA has considered this comment but has retained the rule language from the
proposed rule requiring that emissions be reported at the facility level. In preparation of the final
rule, EPA has loosened the unit aggregation requirements for reporting, lifting the 250 mmBtu/hr
total heat input limit on the aggregation of units into groups for reporting purposes.
EPA has clarified its general monitoring approach in the final rule. While EPA intends that
facilities that meet all of the conditions in §98.33(b) to use Tier 4 methods, EPA does not intend
that CEMS be added in order to comply with this rule. EPA does require facilities with CEMS
to add CO2 or O2 concentration monitors if necessary in order to determine emissions.
In preparation of the final rule, EPA has revised the mandatory fuel sampling and analysis
requirements for traditional fossil fuels for Tiers 2 and 3 and has revised §98.34 to require that
natural gas be sampled semiannually, and that a representative sampling be taken from each fuel
shipment or delivery for fuel oil and coal. For other liquid fuels and biogas, quarterly sampling
is required. For other solid fuels, excluding municipal solid waste, weekly composite sampling
with monthly analysis is required. For other gaseous fuels, the daily sampling requirement has
been retained, but only for facilities with existing equipment in place that is capable of providing
the data. Otherwise, weekly sampling is required.
494
-------
Commenter Name: Craig S. Campbell
Commenter Affiliation: Lafarge North America
Document Control Number: EPA-HQ-OAR-2008-0508-0674.1
Comment Excerpt Number: 4
Comment: EPA maintains that adding C02 CEMs will be cost effective for facilities that
already have other continuous monitors in place. At 74 Fed. Reg. 16483 EPA states: The
incremental cost of adding a diluent gas (C02 or 02) monitor or a flow monitor, or both, to meet
Tier 4 monitoring requirements would likely not be unduly burdensome for a large unit that
combusts solid fossil fuels or MSW, operated frequently, and is already required to install,
certify, maintain, and operate CEMS and to perform on-going QA testing of the existing
monitors. The cost of compliance with the proposed rule would be even less for units that
already have all of the necessary monitors in place. Lafarge's research on CO 2 CEMs indicates
that in many cases the retrofit installation for these units will present technology-compatibility
challenges (with respect to the existing installed monitoring systems), and higher costs than used
in EPA's economic impact analysis. In our current assessment it appears an FTIR hot/wet
system is best suited for monitoring C02 emissions from cement kilns. These units can measure
within the desired range (25 to 35% C02) and offer good accuracy. However, this technology is
not easily adapted to the existing CEMs systems in-place at of our most cement plants.
Retrofitting an existing CEMs unit with a stand alone C02 analyzer is also problematic - in
some cases the sampling system cannot accommodate another analyzer, in other cases the facility
would essentially be forced to use an older technology that is less accurate and perhaps less
reliable. Lafarge's preliminary engineering cost estimate for installing new C02 CEMs at its
existing plants is approximately $175,000 per kiln, with an annual operating cost of
approximately $25,000 per kiln (Lafarge operates 22 cement kilns in the U.S., ranging from 1 to
5 kilns per plant). Lafarge's installation cost estimate is more than 3 times higher than the "fist
cost" installation cost estimates used in EPA's Economic Impact analysis. But even more
importantly, any additional costs for a new/duplicative monitoring system would be unwarranted
given the already well-established WBCSD Cement C02 protocol.
Response: See the response to comment EPA-HQ-OAR-2008-0508-0455.1 excerpt 7 and the
response to comment EPA-HQ-OAR-2008-0508-0580 excerpt 10 for EPA's rationale and
approach to the use of CEMS.
EPA is requiring the use of CEMS for solid fossil fuel-fired units with installed CEMS that are
required by applicable Federal or State regulation or the unit's operating permit due to the
complexity of monitoring solid fuel consumption and the heterogeneous nature of the solid fuels.
EPA has considered the commenter's analysis, but disagrees with the commenter's assessment of
the burden associated with installing and maintaining the concentration and volume monitors that
the rule requires be added to an existing CEMS. In the revised rule, EPA has clarified that if the
unit in question meets all six criteria then a C02 or 02 and a stack gas volumetric flow rate
monitor would be required to be installed. EPA's estimates of monitoring costs are averages for
a representative facility and may not represent the actual cost in individual circumstances.
495
-------
Commenter Name: Rich Raiders
Commenter Affiliation: Arkema Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-0511.1
Comment Excerpt Number: 44
Comment: EPA underestimated Subpart C compliance costs for reporting facilities. Table 4.2h
of the Regulatory Impact Analysis for the Mandatory Reporting of Greenhouse Gas Emissions
Proposed Rule, Final Report, EPA, March 2009 ("RIA") indicates that setup costs for in-stack
gas sampling can be completed for $3,270. Simple Arkema stack test programs, not including
any MACT-related testing protocols, cost $10,000 to plan and execute one time. Very little of
these prior protocols is recoverable for subsequent sampling events, so most of the $10,000 cost
is incurred every time a sample is required. EPA should double the annual cost estimate for fuel
sampling and eliminate the fuel sampling requirement for commodity fuel consumers. EPA does
not include instrumentation costs for automated gas sampling equipment when safety
considerations prohibit reporters from testing or obtaining grab samples of some fuel streams.
Arkema estimated that inline process equipment capable of managing Tier 3 data collection
requirements would cost approximately $250,000 each to install and $20,000 per year to operate.
Requiring 15 such meters to manage potential Arkema Tier 3 streams, Arkema would invest
$3.75 million in monitoring potential Tier 3 streams. EPA did not include the cost of replacing
gas flow meters for Subpart C compliance. Many existing natural gas and diesel fuel flow
meters are not capable of calibration, may have never been calibrated, or may only be calibrated
by pipeline personnel. EPA should either remove the calibration requirement in lieu of reliance
on vendor sales records or include in their cost estimate replacement natural gas meters. EPA
should not require or encourage commodity fuel meter replacement under any Subpart C final
regulation.
Response: Concerning sampling, in preparation of the final rule, EPA has revised the
mandatory fuel sampling and analysis requirements for traditional fossil fuels for Tiers 2 and 3
and has revised §98.34 to require that natural gas be sampled semiannually, and that a
representative sampling be taken from each fuel shipment or delivery for fuel oil and coal. For
other liquid fuels and biogas, quarterly sampling is required. For other solid fuels, excluding
municipal solid waste, weekly composite sampling with monthly analysis is required. For other
gaseous fuels, the daily sampling requirement has been retained, but only for facilities with
existing equipment in place that is capable of providing the data. Otherwise, weekly sampling is
required.
EPA further notes that the applicability of Tier 3 was revised, and the requirements are now only
applicable to large units (i.e., > 250 mmBtu) for fuels either included in Table C-l or that
contribute greater than ten percent of the heat input to a unit. Concerning calibration, EPA
acknowledges the concerns of the commenters. Section 98.34 of the final rule has been clarified
to allow calibration procedures specified by the flow meter manufacturer or an industry-accepted
or industry consensus standard calibration method. Section 98.34 also exempts fuel billing
meters from the calibration requirement, "provided that the supplier and the unit(s) combusting
the fuel do not have any common owners and are not owned by subsidiaries or affiliates of the
same company." EPA also recognizes that for many continuous industrial processes such as
petroleum refineries, removal of a flow meter for calibration could be severely disruptive of
normal process operation. In view of this, today's rule allows these facilities to perform the
496
-------
initial flow meter calibrations and subsequent recalibrations for orifice, nozzle, or venturi meters
at the time of scheduled maintenance outages.
Keeping in mind this additional flexibility on calibration, it is noted that EPA's estimates of
monitoring costs are averages for a representative facility and may not represent the actual cost
in individual circumstances.
Commenter Name: Sam Chamberlain
Commenter Affiliation: Murphy Oil Corporation
Document Control Number: EPA-HQ-OAR-2008-0508-0625
Comment Excerpt Number: 32
Comment: Report on C02, CH4, and N20. See Subpart C, Table C-l for additional guidelines.
Includes boilers, combustion turbines, engines, incinerators, process heaters, etc... For > 250
mm BTU/hr Nat Gas (liquid & gaseous fossil fuel) requires Tier 3 methodology. Tier 3 =
periodic (Monthly) determination of carbon content of fuel and DIRECT measurement of fuel
combusted. Daily determinations of refinery gas, process gas also required if used as a fuel.
EPA says online chromatographs are likely in place. Tank drop measurements can be used for
fuel oil. Murphy has analyzed its refineries and have determined significant regulatory burden
and we have no online chromatographs in operation. At one refinery only the #2 FCC, Crude
heater and Platformer Charge and Hydrocracker combined heaters fall under Tier 4 reporting.
All other fired sources fall under Tier 3 and use installed fuel flow measurement and sampling.
However, QA/QC requirements will have to be improved to meet the EPA QAPP criteria. In
addition, many orifice plate, pressure transducers flow meters will need to be upgraded or
replaced. Pilot gas flow measurement and fuel gas samples will be problematic for meeting
proposed rules. Murphy may be required to install additional CEMS, hire additional laboratory
personnel and/or purchase additional sampling equipment. Murphy has estimated the cost of
compliance to meet the stationary combustion sources to approach close to $1,000,000, which
includes and not limited to purchase of three CEMS, additional laboratory sampling equipment,
additional manpower resources, etc. And these compliance requirements cannot be installed on
or before January 1, 2010, therefore Murphy recommends submitting best professional judgment
for the first reporting period of GHG emissions for 2010.
Response: See the Preamble, Section III. C., for EPA's response on the method for calculating
GHG emissions. Please see the Preamble, Section III. G., "Summary of Comments and
Responses on Initial Reporting Year and Best Available Monitoring Methods," for information
on additional flexibility for 2010.
EPA is requiring the use of CEMS for solid fossil fuel-fired units with installed CEMS that are
required by applicable Federal or State regulation or the unit's operating permit due to the
complexity of monitoring solid fuel consumption and the heterogeneous nature of the solid fuels.
EPA's estimates of monitoring costs are averages for a representative facility and may not
represent the actual cost in individual circumstances.
The final rule requires data collection for calendar year 2010, but has been changed since
proposal to allow use of best available monitoring methods for the first part of 2010. In addition,
497
-------
EPA has added additional flexibility to its fuel flow meter calibration requirements (see
§98.3(i)).
Commenter Name: See Table 3
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0433.2
Comment Excerpt Number: 21
Comment: The total capital and installation costs for installation of a C02 analyzer to an
existing combustion source can range from perhaps as low as $25,000 in a best-case situation, up
to as much as $500,000 for a major facility upgrade. Once a C02 monitor is added to the CEMS
or an existing CO2 or O2 monitor installed only to provide process control data becomes subject
to the proposed 40 CFR part 98 requirements, the quality assurance requirements of this rule will
add substantial additional annual operating costs to the facility. These costs include purchasing
additional calibration gases certified by EPA protocols, performing and analyzing daily zero and
calibration checks on each monitoring instrument in accordance with the proposed rule,
performing quarterly multi-point linearity checks of each analyzer, and performing annual
relative accuracy test audits of each CO2 or O2 monitor and CEMs system. In addition, there
will likely be an increase in labor costs as additional technicians may be needed to monitor and
maintain the new instrumentation. The EPA estimate of total increased annual operating costs of
this rule on a facility may be adequate to cover these costs for one new monitoring installation
provided the new monitors are installed in an existing CEMs installation that monitors and
reports gaseous pollutant emissions. However, the estimated incremental costs are inadequate
for facilities that must certify numerous monitors according to the proposed rule.
Response: See the Preamble, Section II. L., for the response on the general monitoring
approach. Please also see Section III. Y. 3. of the Preamble for EPA's response regarding our
revised cost estimates for petroleum refineries. Specifically, we added relevant costs for existing
monitors that may have been installed for process control purposes but that are not currently
required to perform calibration checks or other QA/QC activities. However, we also note that
many of the monitoring alternatives provided in the rule are not EPA protocols. The final rule
generally allows calibration and maintenance of the monitoring systems according to
manufacturer's specifications or according to the requirements of applicable methods from
consensus standard organizations. While we anticipate these QA/QC requirements will provide
quality-assured data adequate for the purposes on this final rule, they are expected to be
somewhat less rigorous and less burdensome than typical EPA protocols to which the commenter
appears to refer. Note that EPA's cost estimates are annualized and do not widely differ from the
capital cost cited in this comment, although we are unaware of any application in which a CO2
analyzer system would have capital costs approaching $500,000. We expect that what the
commenter referred to as a "major facility upgrade" includes costs in addition to those that are
required for compliance with the final rule. Further detail on the engineering cost analysis for
Subpart C can be found in RIA (EPA-HQ-OAR-2008-0318-002), Section 4.3. We believe our
revised costs accurately portray the burden associated with the final reporting requirements.
498
-------
Commenter Name: Keith A. Nagel
Commenter Affiliation: ArcelorMittal USA and Severstal North America
Document Control Number: EPA-HQ-OAR-2008-0508-0496.1
Comment Excerpt Number: 25
Comment: EPA's stated rationale for requiring facilities with CEMS that do not monitor C02 to
"upgrade" to CO2 CEMS is that the "incremental cost" will not be unduly burdensome. 74 Fed.
Reg. at 16483. In all scenarios except where C02 CEMS are already in place, actual costs would
be more burdensome than EPA suggests. One primary reason is that EPA's capital cost estimates
are based on "annualized costs over a 15-year timeframe." EPA-HQ-OAR-2008-0508-0002 at p.
4 - 22. While CO2 CEMS may operate for 15 years (as EPA presumes), the real world cash-flow
impact of such capital improvements cannot be similarly deferred. Rather, contractors require
payment in full no later than the date of installation. Given the challenging economic climate
and existing budget constraints, payment of lump-sum capital costs for many simultaneous
upgrades (even assuming the actual amount of those costs matches EPA's estimates) will create a
significant economic burden. Assessing whether that significant burden is "undue" also requires
assessment of the relative benefits expected. The Tier 4 approach appears to provide, at most,
very marginal improvement over Tier 3 reporting. As acknowledged in the preamble, "for
combustion sources, the emission rate of CO2 is directly proportional to the carbon content of the
fuel, and virtually all of the carbon is oxidized to C02." 74 Fed. Reg. at 16480. Since Tier 3
requires careful monitoring of fuel carbon content and "virtually all" the measured carbon
becomes C02, this methodology is more than accurate enough to achieve Congress' expressed
goal: the collection of sufficient information to guide future legislative and regulatory efforts. 74
Fed. Reg. at 16456.11 Since CO is strictly regulated, facilities will have no incentive to
overestimate CO emissions (which would, in turn, reduce reported GHGs). If estimates are good
enough to report CO emissions under active permits, then they should also suffice for CO2
emissions reporting purposes. Indeed, the only expected difference between the Tier 3 and Tier
4 protocols is that Tier 3 reporting may modestly overestimate CO2 emissions where incomplete
combustion results in low-level CO emissions. As noted above, that adjustment can be made
simply and accurately for many sources without any additional costs. Thus, the real-world
difference in Tier 3 and Tier 4 reporting cannot justify the proposed mandatory imposition of
significant up-front capital costs. It would be regulatory overkill to require sources to track
down such minute carbon overestimates when the rule claims to cover only 85% of national
GHG emissions and exempts all sources under 25,000 metric tons per year. Accordingly, we
request that EPA limit mandatory Tier 4 reporting to only units that already have functioning
C02 CEMS.
Response: See the Preamble, Section II. L., for EPA's response on the general monitoring
approach.
EPA is requiring the use of CEMS for solid fossil fuel-fired units with installed CEMS that are
required by applicable Federal or State regulation or the unit's operating permit due to the
complexity of monitoring solid fuel consumption and the heterogeneous nature of the solid fuels.
EPA has considered the commenter's analysis, but disagrees with the commenter's assessment of
the burden associated with installing and maintaining the concentration and volume monitors that
the rule requires be added to an existing CEMS. In the revised rule, the EPA has clarified that if
the unit in question meets all six criteria then a CO2 or O2 and a stack gas volumetric flow rate
499
-------
monitor would be required to be installed. EPA's estimates of monitoring costs are averages for
a representative facility and may not represent the actual cost in individual circumstances.
Commenter Name: Keith A. Nagel
Commenter Affiliation: ArcelorMittal USA and Severstal North America
Document Control Number: EPA-HQ-OAR-2008-0508-0496.1
Comment Excerpt Number: 22
Comment: Steel companies need the flexibility to use alternate methods for calculating GHG
emissions from their combustion sources. As written, the Proposed Rule would require at least
Tier 3 reporting for many steel plant combustion sources because those sources are larger than
250 mmBtu and/or combust blast furnace gas and/or coke oven gas (which have no default
factors). The proposed Tier 3 rules would necessitate calculations based on daily sampling and
analysis of fuel carbon content, molecular weight and quantity. Conducting such daily sampling
and analysis of process gases plant-wide would be prohibitively expensive. For example,
periodic coke oven gas sampling for a particular unit at ArcelorMittal's Burns Harbor facility
costs $770 for a single daily sample set. Thus, daily sampling and analysis of just coke oven gas
could cost more than $280,000 annually per unit.
Response: EPA acknowledges the concerns of the commenter, and has revised the final rule to
include default factors for coke oven and blast furnace gases in Table C-l. In addition, EPA has
attempted to clarify measurement procedures that will provide flexibility and minimize burden
where initial prescriptions were impractical. While the revised rule does require daily sampling
and analysis where the equipment is in place, if this equipment is not in place, weekly sampling
and analysis may be used. If sampling and analysis occur at less than the minimum frequency,
appropriate substitute data values shall be used in the emissions calculations, in accordance with
§98.35.
Commenter Name: Matt Smorch
Commenter Affiliation: Countrymark Cooperative, LLP
Document Control Number: EPA-HQ-OAR-2008-0508-1081.1
Comment Excerpt Number: 4
Comment: Countrymark takes issue with EPA's estimate for implementing Continuous
Emission Monitoring Systems (CEMS). The estimate of approximately $9,500 per refinery does
not include the cost of installation, infrastructure, and supporting systems needed to insure
quality CEMS installation and operation. Countrymark estimates the cost to be near $200,000.
This is especially true if additional CEMS is required for the CCR platformer, flare system, and
on-stream hydrocarbon composition determination.
Response: See the Preamble, Section II. L., for EPA's response on the general monitoring
approach. Also, please see Section III. Y. 3. of the Preamble for EPA's response regarding final
requirements for flares and the revised cost estimates for refineries.
500
-------
We note that CEMS are not required in either Subpart C or Subpart Y unless they are already in-
place and meet certain criteria as indicated in Subpart C, and then only for selected sources. If
CEMS are not in place, they are not required to be installed. As such, we clarify that the
installation of new CEMS are not required for catalytic reforming units (e.g., CCR platformers),
flares, or other sources at the refinery. As a point of clarification, we interpret the comment
regarding CEMS for flare systems to refer to continuous flow and composition monitoring of the
flare gas, rather than an "emissions" monitoring system. The final rule in Subpart Y requires the
use of the Tier 3 Calculation Methodology (specifically Equation C-5 in Subpart C of the final
rule) for combustion units using fuel gas. Tier 3 requires daily monitoring of composition only
when appropriate equipment is in place; otherwise weekly sampling allowed. The provisions for
flares are similar, but also include higher heating value monitoring alternative and an engineering
estimation method.
Also, we note that we do not require CO2/CO/O2 monitoring systems for catalytic cracking units
with capacities of 10,000 bbls/day or less because these units are smaller GHG emission sources
and are most likely to not have existing monitoring systems. For these sources, we allow
engineering estimates as an alternative to the use of a C02/C0/02 monitoring system when a
monitoring system in not already in-place. If a facility does need to install a monitoring system,
then the capital costs that we estimated for such systems are not vastly different than those cited
by the commenter. However, please note that EPA's costs are annualized, and are averages for a
representative facility. In determining the average cost, EPA assumed that only a small
percentage of facilities would need to install these monitors. Further detail on the engineering
cost analysis for Subpart C and Subpart Y can be found in RIA (EPA-HQ-OAR-2008-0318-002),
Section 4.3 and 4.17, respectively.
Commenter Name: Edward N. Saccoccia
Commenter Affiliation: Praxair Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-0977.1
Comment Excerpt Number: 4
Comment: §98.33(b)(5)(ii)(E) imposes the Tier 4 method if the source has any existing CEMS
system. Depending on the type of gas monitoring system a source may have (extractive vs. in-
situ; wet vs. dry, etc.) the addition of a CO2 CEMS can be a very costly modification.
Modifications could include, assuming it is even technically feasible, the addition of stack
sampling ports, addition of extractive sampling systems, sample conditioning systems,
calibration gas systems and modification to data acquisition and reporting systems and software.
These modifications can impose $40,000 to $250,000 of capital costs, as well as ongoing
maintenance and operating costs for such units. As stated above, these costs may be imposed on
the false premise that direct emission measurement via CEMS is an inherently more accurate
than alternative calculation methods (e.g. Tiers 1, 2, or 3).
Response: See the Preamble, Section II. L., for EPA's response on the general monitoring
approach.
It is EPA's view that direct measurement can be more accurate than calculation methods in
certain circumstances, and the final rule reflects this view. EPA is requiring the use of CEMS
for solid fossil fuel-fired units due to the complexity of monitoring solid fuel consumption and
501
-------
the heterogeneous nature of the solid fuels. EPA has considered the commenter's analysis, but
disagrees with the commenter's assessment of the burden associated with installing and
maintaining the concentration and volume monitors that the rule requires be added to an existing
CEMS. In the revised rule, EPA has clarified that if the unit in question meets all six criteria
then a C02 or 02 and a stack gas volumetric flow rate monitor would be required to be installed.
EPA's estimates of monitoring costs are averages for a representative facility and may not
represent the actual cost in individual circumstances. Note that EPA's cost estimates are
annualized and do not widely differ from the capital cost cited in this comment. Further detail on
the engineering cost analysis for Subpart C can be found in RIA (EPA-HQ-OAR-2008-0318-
002), Section 4.3.
Commenter Name: Ted Michaels
Commenter Affiliation: Energy Recovery Council (ERC)
Document Control Number: EPA-HQ-OAR-2008-0508-0544.1
Comment Excerpt Number: 2
Comment: The Increased Costs for Installing Part 75-like CEMS Are Not Justified As the WCI
recognized, the substantial costs to implement Tier 4 methodology are very difficult to justify
since the Tier 2 methods provide C02 emissions of sufficient accuracy. All MWC facilities have
state-of-the-art wet or dry extractive Part 60 CEMs that use 02 for diluent correction. None of
the facilities have stack gas flow monitors, only a few have Part 60 certified C02 CEMS, and all
facilities with dry-based CEMS do not have moisture monitoring. Consequently, for all large
MWCs nationally, extensive CEM retrofits will be required to comply with Tier 4 including: 1.
Installation of stack flow monitors; 2. Installation of moisture monitors for dry based systems; 3.
Installation of C02 analyzers and integration into existing CEMs; 4. Plant modifications and
integration including: installation of stack flow monitor ports, signal and power wiring, wiring
tray or conduit and new access platforms (depending on suitable flow monitor location); 5. New
CEM data systems for automatic data substitution and reporting; and 6. Initial certification of
flow monitoring systems and C02 analyzers. Based upon cost estimates from approved CEMS
equipment vendors at one of ERC members companies, estimated costs for installation of Tier 4
monitoring would range up to $4.5 million, with annual operating costs of a half a million
dollars. Further, the purchase, installation, startup and certification process for the new
equipment would likely delay reporting of 2010 emissions data collection and subsequent
reporting.
Response: See the Preamble, Section II. L., for EPA's response on the general monitoring
approach.
EPA is requiring the use of CEMS for larger solid fossil fuel-fired units due to the complexity of
monitoring solid fuel consumption and the heterogeneous nature of the solid fuels. EPA has
considered the commenter's analysis, but disagrees with the commenter's assessment of the
burden associated with installing and maintaining the concentration and volume monitors that the
rule requires be added to an existing CEMS. In the revised rule, EPA has clarified that if the unit
in question meets all six criteria then a C02 or 02 and a stack gas volumetric flow rate monitor
would be required to be installed. EPA's estimates of monitoring costs are averages for a
representative facility and may not represent the actual cost in individual circumstances.
502
-------
As a result of commenters' legitimate concern on timing, EPA has revised the initial reporting
approach for the final rule. See the Preamble, Section II. G., "Summary of Comments and
Responses on Initial Reporting Year and Best Available Monitoring Methods," for more
information on additional flexibility provided to reporters for 2010.
Commenter Name: See Table 7
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0412.1
Comment Excerpt Number: 26
Comment: Natural gas systems will also need to comply with Subpart C - General Stationary
Fuel Combustion Sources. These sources bear the second highest burden of all regulated entities
- 17% of all first year total annualized costs and 15% of first year capital costs. EPA has
estimated that, in order to measure the cumulative 6% of GHG emissions produced by sources
regulated under Subpart C, sources will need to incur on average first year total annualized costs
of $10,000 based upon a total cost estimate of $29.0 million for 3,000 sources. These additional
costs exacerbate the cost-benefit imbalance that arises under Subpart W. Requiring sources that
are regulated under Subpart W to bear the additional expenses of direct measurement to quantify
these small emissions will impose a great financial burden on particular states such as New
Mexico, Oklahoma, and Texas that maintain a large portion of the nation's oil and natural gas
industry.
Response: See the Preamble, Section III. C., on the method for calculating emissions.
EPA acknowledges the commenters' concerns regarding natural gas sampling costs, and has
revised the §98.34 as follows: for natural gas, semiannual sampling and analysis is required.
Furthermore, EPA has revised Subpart C so that units of any size combusting only pipeline
quality natural gas and/or distillate oil may use Tier 2 methods. EPA points out that it is not
finalizing Subpart W at this time.
Commenter Name: Lloyd Stone
Commenter Affiliation: Westlake Chemical Corporation
Document Control Number: EPA-HQ-OAR-2008-0508-0442.1
Comment Excerpt Number: 6
Comment: Although CEMS are in use at some of our facilities, CO2 CEMS are not used as the
diluent monitor, and flow meters are not in prevalent use either. The purported cost of
compliance with Subpart C is also underestimated in the Regulatory Impact Analysis for the
Mandatory Reporting of Greenhouse Gas Emissions Proposed Rule (GHG Reporting). One
example is that the RIA's Annualized First costs estimates should only be made for support
facilities and CEMS hardware (fixed assets). Tables 4-2f, 4-2g, 4-2h, and 4-2i represent the
other ODC costs as non-annualized First time costs just like Labor and Consultant costs.
Whereas, the other ODC costs (Planning, Select equipment, Install and check CEMS, and
Performance specification tests) are annualized in Table 4-2a. In Table 4-2a, the final value of
$56,040 becomes $60,544 when only the support facility and CEMS costs are annualized. That
503
-------
is an 8% error multiplied several times over for the 3000 entities that EPA estimates is impacted
by the 25,000 metric tons C02e. A second example is that the CEMS/flow meter maintenance
costs do not appear to be included in the annual costs, overlooking another substantial cost of
compliance. A third example is that no Labor costs are shown for purchasing CEMS equipment
in Tables 4-2a, 4-2b, and 4-2c. Purchase orders do not automatically generate once a
technician/engineer makes the equipment selection. Purchasing employees' time should be
accounted for as a result. A final example on cost discrepancies is that EPA does not include
costs for the data acquisition and management (i.e., software), and data quality assurance/quality
control (via the mandated written quality assurance performance plan). Westlake has already
begun the process of evaluating software designed to handle the management of GHG data. The
costs are in the 100,000's of dollars for purchasing and implementing this needed software.
Response: See the Preamble, Section II. L., for EPA's response on the general monitoring
approach.
EPA does not agree with the commenter's first example that annualized costs in the RIA should
not include ODC costs. In fact, all of the tables cited in the comment breakdown planning and
equipment costs between labor performed by employees and work performed by a contractor.
ODC costs includes the latter. EPA believes that apportioning some planning and equipment
selection costs to a contractor is the most realistic assumption to make. EPA does not agree with
the commenter that CEMS maintenance costs are not included in Tables 4-2a, 4-2b, and 4-2c.
The line item 'Purchase CEMS hardware' in Table 4-2a is the cost of the CEMS hardware. Labor
for purchasing CEMS equipment in the same table is provided under Planning ($3,477) and
Select equipment ($9,281). EPA also does not agree with the commenter's final examples that
costs for software or quality assurance/quality control are not included. DAHS software costs
are provided for in the line item Purchase CEMS hardware. Costs for quality assurance/quality
control are shown on line items QA/QC plan and Annual QA and O&M review and update. For
further detail on the Subpart C engineering cost analysis, please see the Final RIA (EPA-HQ-
2008-0508) and the cost appendix to the RIA.
EPA is requiring the use of CEMS for solid fossil fuel-fired units due to the complexity of
monitoring solid fuel consumption and the heterogeneous nature of the solid fuels. EPA has
considered the commenter's analysis, but disagrees with the commenter's assessment of the
burden associated with installing and maintaining the concentration and volume monitors that the
rule requires be added to an existing CEMS. In the revised rule, EPA has clarified that if the unit
in question meets all six criteria then a CO2 or O2 and a stack gas volumetric flow rate monitor
would be required to be installed. EPA's estimates of monitoring costs are averages for a
representative facility and may not represent the actual cost in individual circumstances. .
Commenter Name: Henry Derwent
Commenter Affiliation: International Emissions Trading Association (IETA)
Document Control Number: EPA-HQ-OAR-2008-0508-0512.1
Comment Excerpt Number: 5
Comment: The proposal envisages that going forward, Continuous Emissions Monitors
(CEMS) will be a requirement only in those sectors and organizations where they are already
required, mainly those in the existing SO2 and NOx programme. IETA supports this provision.
504
-------
Industry studies have shown that installing CEMS costs between $165,000 to $200,000.
Additionally, annual operating and maintenance costs would average around $63,000. If
emergency services are required by a CEMS vendor, costs per day range from $1,200 to $1,600
plus portal to portal expenses and travel time to and from the site. Given these costs, IETA is
opposed to requiring broader use of CEMS.
Response: EPA appreciates the commenter's input and thanks you for your comment. EPA
notes that the requirements of this rule were not designed as part of implementing a specific cap
and trade program, which is beyond the scope of the direction by Congress.
Commenter Name: Karin Ritter
Commenter Affiliation: American Petroleum Institute (API)
Document Control Number: EPA-HQ-OAR-2008-0508-2167.1
Comment Excerpt Number: 3
Comment: The following summarizes API member company feedback on parameters EPA
used to develop the cost implications for Subpart C. The responses below represent feedback
from 7 U.S. refineries, with capacities ranging from 50 to over 300 KBPCD (thousand barrels
per calendar day). Subpart C (Stationary Combustion) Costs: API members indicated that the
cost to install CO2 monitors, flow meters, and analyzers to comply with the requirements of
Subpart C could range from $500,000 to $7,000,000 per facility.
Response: EPA is requiring the use of CEMS for solid fossil fuel-fired units due to the
complexity of monitoring solid fuel consumption and the heterogeneous nature of the solid fuels.
EPA recommends that the commenter cross-check the facilities and units encompassed by the 7
U.S. refineries to see if the requirement to apply Tier 4 applies. EPA has considered the
commenter's analysis, but disagrees with the commenter's assessment of the burden associated
with installing and maintaining the concentration and volume monitors that the rule requires be
added to an existing CEMS. In the revised rule, EPA has clarified that if the unit in question
meets all six criteria in §98.33(b) then a CO2 or O2 and a stack gas volumetric flow rate monitor
would be required to be installed. EPA's estimates of monitoring costs are averages for a
representative facility and may not represent the actual cost in individual circumstances.
505
-------
11. OTHER SUBPART C COMMENTS
Commenter Name: Patrick J. Nugent
Commenter Affiliation: Texas Pipeline Association (TPA)
Document Control Number: EPA-HQ-OAR-2008-0508-0460.1
Comment Excerpt Number: 20
Comment: TPA generally supports the requirements set forth in Subpart C related to
combustion sources and commends EPA for the reasonable and clearly stated approach taken in
that Subpart.
Response: EPA appreciates your support of the requirements set forth in Subpart C and thanks
you for your comment.
Commenter Name: Lorraine Krupa Gershman
Commenter Affiliation: American Chemistry Council (ACC)
Document Control Number: EPA-HQ-OAR-2008-0508-0423.2
Comment Excerpt Number: 61
Comment: For the sampling requirements of §98.34(c) and (d)(3), EPA should allow sufficient
time until the next scheduled process unit turnaround or December 2009, whichever is later, for
installing sample taps or locations in order to collect the samples for carbon analysis, molecular
weight determinations, and high heating value. These sampling locations may not exist today.
Facilities should not be required to incur the cost of additional process unit shutdowns to install
these taps, and in most cases, scheduled shutdowns will occur on a three to five year cycle.
Response: See the Preamble, Section III. C., on monitoring and QA/QC requirements.
EPA acknowledges the concerns of the commenter. The final rule allows sampling data from the
fuel supplier to be used to meet Part 98 requirements. For unconventional gaseous fuels, daily
sampling is required only where the necessary equipment is already in place. Otherwise, weekly
sampling is required. The calibration deadline for fuel flow meters has been extended to April 1,
2010, with an exception for continuously operating processes, allowing calibration to coincide
with the next scheduled maintenance outage. Additional flexibility has been added in the flow
meter calibration methods. Industry consensus methods may be used. Also, flow meters with
active calibrations as of April 1, 2010 (either according to the manufacturer's schedule or the
industry consensus schedule), the April 1, 2010 deadline does not apply — these meters may be
recalibrated on their normal schedule.
506
-------
Commenter Name: Lorraine Krupa Gershman
Commenter Affiliation: American Chemistry Council (ACC)
Document Control Number: EPA-HQ-OAR-2008-0508-0423.2
Comment Excerpt Number: 48
Comment: In §§98.33(a)(3) and (b)(4), units may not have measured fuel flow rates and flow
measuring devices may not be installed. Installing this equipment in a short period of time may
be impossible due to long equipment delivery times, competition for purchasing measuring
devices at the same time and among the many entities subject to the greenhouse gas reporting
requirements, and timing of outages of process units required to install the equipment. Many of
these process units would not normally be taken out of service for three to five years. Such
outages would be unnecessarily costly. EPA should allow an additional five years or at the next
scheduled maintenance turnaround shutdown after December 2009 for facilities to install the
required flow meters, whichever is later. In the interim, in lieu of measured flow rates, facilities
should be allowed to use engineering calculations to determine flows.
Response: See the Preamble, Section III. C., on calculating CO2 emissions from combustion.
See the Preamble, Section II. G., on "Summary of Comments and Responses on Initial Reporting
Year and Best Available Monitoring Methods" for additional information on flexibility provided
for 2010.
EPA acknowledges the concerns of the commenter. The final rule allows sampling data from the
fuel supplier to be used to meet Part 98 requirements. For unconventional gaseous fuels, daily
sampling is required only where the necessary equipment is already in place. Otherwise, weekly
sampling is required. The calibration deadline for fuel flow meters has been extended to April 1,
2010, with an exception for continuously operating processes, allowing calibration to coincide
with the next scheduled maintenance outage. Additional flexibility has been added in the flow
meter calibration methods. Industry consensus methods may be used. Also, flow meters with
active calibrations as of April 1, 2010 (either according to the manufacturer's schedule or the
industry consensus schedule), the April 1, 2010 deadline does not apply — these meters may be
recalibrated on their normal schedule.
507
-------
12. CALCULATION OF BIOGENIC EMISSIONS
Commenter Name: Ron Downey
Commenter Affiliation: LWB Refractories
Document Control Number: EPA-HQ-OAR-2008-0508-0719.1
Comment Excerpt Number: 28
Comment: The formulas set forth in 40 CFR 98.33(e)(2) regarding how CEMS are used to
calculate CO2 emissions from the combustion of biomass or biomass-derived fuel is
inappropriate for sources such as lime plants that have process emissions. The proposed formula
assumes that if one was to subtract the volume of CO2 from fossil fuel combustion from the total
volume of CO2, then the remaining CO2 would be biogenic. In the case of the lime industry, the
difference between total and combustion emissions would be comprised of biogenic and process
emissions. LWB proposes that the following equation be added to 40 CFR 98.33(e)(2) to
account for sources with process emissions: Total CO2 tons - Fossil Fuel CO2 tons - Process
CO2 tons = Biogenic Fuel CO2 tons
Response: EPA appreciates that CEMS will capture both process and combustion emissions,
and has revised the rule for units that burn biomass (not including MSW) and fossil fuels, have
process emissions, and use a CEMS to measure C02. The revision to §98.33(e)(2) adds the
subtraction of process emissions from the CEMS measured CO2 to determine the biogenic
emissions. The process C02 emissions must be calculated according to the requirements of the
applicable subpart.
Commenter Name: Ted Michaels
Commenter Affiliation: Energy Recovery Council (ERC)
Document Control Number: EPA-HQ-OAR-2008-0508-0544.1
Comment Excerpt Number: 7
Comment: 98.33(e)(3) MSW Combustion. The calculations for MSW combustion focus on
biogenic CO2 which is not considered a GHG gas by IPCC or in any GHG reporting convention.
Non-biogenic C02 or Anthropogenic only is included in total C02e emissions. Since only non-
biogenic CO2 is included in CC^e total, Section 98.33(e)(5) should be revised to include
calculation of non-biogenic CO2 emissions derived from ASTM D 7459-08 and D 6866-06a
methods. Non-biogenic fraction is 1-biogenic fraction as reported with ASTM D6866 results. If
biogenic or biomass fraction is 0.30 then non-biogenic fraction in 1-0.30 or 0.70. Note also the
biogenic fraction of 0.30 used in the example is incorrect. The national biogenic CO2 average
fraction for MSW combustion is approximately 60 - 70% (or 0.60 - 0.70).
Response: The IPCC identifies C02 as a GHG, as does the UNFCCC, the Inventory of U.S.
Greenhouse Gases and Sinks, and all other reporting programs, and does not exclude biogenic
C02. Biogenic C02 may be included in total C02 emissions at the national level if there are net
changes in carbon stocks in land-based carbon pools (e.g., above ground biomass, soil carbon
etc.). EPA has retained the use of the ASTM D6866-06a and D7459-08 methods in the final
rule, and has expanded the use of these methods so that they may be used to calculate biogenic
emissions from any unit which uses CEMS and combusts a combination of biogenic and non-
508
-------
biogenic fuels (other than MSW). However, EPA continues to believe that biogenic C02
emissions should be reported to EPA and included in emissions totals, although they should be
tracked separately.
Commenter Name: Paul Dubenetzky
Commenter Affiliation: KERAMIDA Inc.
Document Control Number: EPA-HQ-OAR-2008-0508-0419.1
Comment Excerpt Number: 10
Comment: Many facilities are increasing the use of "biodiesel" as a fuel, either in compression
ignition engines or in stationary combustion sources such as boilers. "Biodiesel" is typically a
blend of methyl esters derived from plant or animal fat and "petrodiesel" derived from
petroleum. For instance a blend of 20% methyl ester and 80% petrodiesel is commonly referred
to as B20 biodiesel. Both the applicability provisions of 40 CFR 98.2(b)(2), 74 FR 16613 and
the reporting requirement of 40 CFR 98.36(b)(4), 74 FR 16637 require that the GHG emissions
from bio fuels and fossil fuels be accounted for separately. 40 CFR Subpart C, Table C-l, 74 FR
16639 contains CO2 methodology for only "Distillate Fuel Oil (#1, 2, 3, 4) and "Other Oil (401
deg. F)" and Table C-3, 73 FR 16641 contains CH4 and N20 methodology for only "Distillate
Oil". While there are reasonable interpretations of how to address the issue of GHG emissions
from the combustion of "biodiesel," the U.S. EPA should provide a specific protocol to address
the combustion of "biodiesel." KERAMIDA suggests that protocol include the 40 CFR 98,
Subpart MM emission factors for C02 provided in Table MM3 for 100% methyl ester and a
statement to the effect that the emissions from fuels that are a blend of biomass products and
petroleum based products shall be calculated and reported based on their weight percent
composition. The U.S. EPA should address gasoline containing ethanol in a similar matter using
the CO2 emission factor for ethanol found in Table MM-3 (40 CFR, Subpart MM Table 1, 74 FR
16719 & Table 3, 74 FR 16720 and 40 CFR 98, Subpart C, Table C-l, 74 FR 16639.
Response: EPA has clarified the rule as applied to biodiesel and ethanol blend fuels, and other
biomass fuels. In §98.33(e), the use of the Tier 1 method is specified to calculate biogenic
emissions from biogas and biodiesel, as well as other biomass fuels (except for MSW) listed in
Table C-l. EPA has added emission factors to Table C-l for liquid biomass-derived fuels
including ethanol, biodiesel, rendered animal fat, and vegetable oil. For premixed fuels that
contain biomass and fossil fuels (e.g., mixtures containing biodiesel), sources may use the best
available information to determine the mass of biomass fuels and document the procedure used
in the GHG Monitoring Plan.
Commenter Name: Louis Kollias
Commenter Affiliation: Metropolitan Water Reclamation District of Greater Chicago (District)
Document Control Number: EPA-HQ-OAR-2008-0508-0311
Comment Excerpt Number: 3
Comment: Is anaerobic biogas considered a biomass-derived fuel and therefore exempt from
potential reporting?
509
-------
Response: EPA considers anaerobic biogas a form of biomass-based fuel, as defined in §98.6.
The definition states that "non-fossilized and biodegradable organic fractions of industrial and
municipal wastes, including gases and liquids recovered from the decomposition of non-
fossilized and biodegradable organic material" are considered biomass. EPA continues to
believe that biogenic C02 emissions should be reported to EPA and included in emissions totals,
although they should be tracked separately. In the final rule, Subpart C (Stationary Fuel
Combustion Units) has been revised since proposal to require reporting of only biomass fuels
listed in Table C-l of Subpart C. In the revised §98.33(e), EPA has specified that emissions
from biogas and other biomass fuels listed in Table C-l (except for MSW) are to be calculated
using Tier 1. EPA has added default values for biogas in Table C-l.
Commenter Name: See Table 1
Commenter Affiliation:
Document Control Number: EPA-HQ-OAR-2008-0508-0278
Comment Excerpt Number: 1
Comment: In several sections of the proposed greenhouse gas reporting protocol, the EPA
solicits comments on how to better quantify the biomass fraction of fuels. There is a readily
available method called ASTM D6866 that can precisely and accurately quantify the biomass
fraction of any type of fuel or material (gas, liquids, or solids). This method is already adopted
in the current reporting rule under the Tier 4 sampling protocol for municipal solid waste (pages
16636 to 16639). The EPA should broaden the use of this method for all fuels and materials
since municipal solid waste is in essence a heterogeneous fuel / material. The ASTM D6866
method is a standardized version for industrial use of radiocarbon dating, an analytical technique
that was developed in the 1950s. Radiocarbon dating has been used for decades for dating
archaeological artifacts. The same principles of dating (i.e. analysis of the carbon-14 atom) can
also be used to measure the biomass component of fuels and materials. Biomass contains a well-
characterized amount of carbon-14 that is easily distinguished from other materials such as fossil
fuels that do not contain any carbon-14. Since the amount of carbon-14 in biomass is well
known, a percentage of biogenic carbon (or in the case of a gas sample, biogenic CO2) can be
calculated easily from the overall carbon atoms (or CO2) in the sample. Although ASTM D6866
is now used throughout the world to measure biomass carbon / CO2, the origins of the method
are American. It was written at the request of the USDA to satisfy legislation requiring federal
agencies to prefer procurement from manufacturers using the greatest amount of biomass in their
products (per the Farm Security and Rural Investment act of 2002). It was quickly established
that radiocarbon dating was the only viable and accurate technique to make the determination of
the biomass percentage. A working standard of radiocarbon dating for industrial use was
completed in 2004 and is now cited in US Federal Law (7 CFR part 2902). We believe that the
ASTM D6866 method should be allowed for all heterogeneous fuels (i.e. those that contain a
biomass fraction), not just municipal solid waste as cited in the current EPA greenhouse gas
reporting rule. The EPA should expand the use of ASTM D6866 to include all heterogeneous
and alternative fuels, including those referenced in Table C-2 on page 16640 of the EPA
protocol. Current regional protocols in the US, such as California's AB 32 and the Western
Climate Initiative, allow the use of ASTM D6866 for heterogeneous fuels. Below are two links
where ASTM D6866 is cited for heterogeneous fuels in these two protocols: California's AB32:
(Operator advised to use ASTM D6866 to determine CO2 emissions from the combustion of
biomass, municipal solid waste, or waste-derived fuels with biomass.) Page 93,
510
-------
http://www.arb.ca.gov/regact/2007/ghg2007/frofinoal.pdfWestern Climate Initiative: (Operator
that combusts fuels or fuel mixtures that contain biomass shall determine the biomass-derived
portion of C02 emissions using ASTM D6866.) Page 79, http://www.westernclimateinitiative.
org/ewebeditpro/items/0104F20744.pdf The European Union also allows the use of carbon-14
for measuring heterogeneous fuels, particularly for solid recovered fuels (SRF) and refuse-
derived fuels (RDF). A carbon-14 method called CEN/TS 15747:2008 was developed for these
types of fuels. It is almost identical to ASTM D6866. In fact, CEN/TS 15747:2008 cites ASTM
D6866 as the premise for the method. In 2007, the European Union published a FAQ for the EU
Emissions Trading Scheme. On pages 16 and 17, carbon-14 is cited as an acceptable method for
determining the biogenic fraction of heterogeneous fuels. Both ASTM D6866 and CEN/TR
15991:2007 (precursor to CEN/TS 15747:2008) are cited as acceptable carbon-14 methods. The
EUETS FAQ can be found at this link: http://ec.europa.eu/environment/climat/emission/
pdf/mrg2faq_sep_2007.pdf. Of course, it must be noted that Europe, California, and the Western
Climate Initiative are not the only entities advocating the use of carbon-14 for heterogeneous
fuels. Australia has also advocated its use, particularly for blended fuels. More information on
the Australian protocol can be found here (see pages 114 to 115): http://www.climatechange.
gov.au/reporting/publications/pubs/nger-technical-guidelines-vl-l.pdf. Lastly, we would like to
add that The Climate Registry's Greenhouse Gas Reporting Protocol (please see page 65) also
advocates the use of ASTM D6866 for biomass derived fuels. More information can be found at
this link: http://www.theclimateregistry.org/downloads/GRP.pdf. In light of the acceptance of
the ASTM D6866 method for all heterogeneous fuels, we believe that the method should be
allowed for all fuel types (i.e. gas, liquids or solids). The method works equally well for any
material. Under certain circumstances (e.g. plant operators without CEMS), sampling the liquid
or solid fuel itself might make more sense. Of course, it is better to sample the final CO2
emission to determine the biogenic fraction from the combustion. Nonetheless, there are
situations where analyzing the liquid or solid fuel is more economical, particularly if a
representative sample can be submitted to the laboratory. This is often the case for the cement
industry that is concurrently doing a host of other tests on their solid fuels. In that regard, the
CEN/TS 15747:2008 method was created in Europe because the cement and paper/pulp
industries are important users of SRF/RDF. They perform a host of tests on the SRF/RDF itself,
along with the biogenic fraction determination. On that note, the EU ETS FAQ cited before
contains sampling recommendations on page 17 for liquid and solid fuels. We would like to
mention that the ASTM D6866 method would address perfectly the concerns cited in Section V,
Subpart MM (pages 16569 to 16575). The method can determine unambiguously the biomass
fraction of any fuel mix. For example, synthetic ethanol made from fossil fuels is chemically
indistinguishable from bioethanol made from a biomass feedstock. ASTM D6866 is the only
method that can determine precisely the percentage of biocarbon in the fuel mix. In a similar
light, the ASTM D6866 can help resolve biocarbon fraction ambiguities in complex fuel mixes
such as Hydrogenation-Derived Renewable Diesel (HDRD). Lastly, we would like to suggest
that the Tier 4 calculation allow the use of ASTM D6866 to calculate the biogenic CO2 fraction
of any waste fuel or material, not just municipal solid waste. Since the ASTM D6866 method
works equally well for any waste materials that contain a biomass fraction, the EPA protocol
should include along with municipal solid waste, the use of ASTM D6866 for any waste
materials, waste fuels, tires and alternative fuels in the Tier 4 biogenic calculation protocol. In
summary, we are advocating through this public comment that the EPA should allow the use of
ASTM D6866 for all heterogeneous/alternative fuels (i.e. those that contain a biomass fraction)
to determine the biogenic percentage. We are also advocating that plant operators be allowed to
use the ASTM D6866 method to determine the biogenic fraction on the fuel itself when gas
sampling is difficult. Contrary to emission factors or other methods (e.g. manual sorting), the
511
-------
carbon-14 method can accurately determine the biogenic fraction on any type of fuel (gas, liquid,
or solid). As can be seen with the national and international GHG protocols cited in this
comment, the ASTM D6866 method has been accepted widely throughout the world for the
measurement of the biogenic fraction of heterogeneous fuels. It is important that the EPA GHG
protocol adopt similar reporting methods to ensure that C02 emissions calculated in the United
States are the same as the CO2 emissions calculated with these other protocols.
Response: EPA appreciates the commenter's support of the ASTM methods. In §98.33(e)(4) of
the final rule, EPA has laid out the use of the ASTM D6866-06a and D7459-08 methods so that
they may be used to calculate biogenic emissions from any unit using CEMS and combusting a
combination of biogenic and non-biogenic fuels (other than MSW). In situations where CEMS
are not used, however, EPA has provided for biogenic emissions to be calculated using Tier 1
methods.
Commenter Name: Louis Kollias
Commenter Affiliation: Metropolitan Water Reclamation District of Greater Chicago (District)
Document Control Number: EPA-HQ-OAR-2008-0508-0311
Comment Excerpt Number: 1
Comment: Should the District ever operate sewage sludge incinerators, it is unclear exactly
what calculation method would be used. However, NACWA believes that the ruling's Tier 2
Calculation Methodology would be used. However, calculation would be difficult due to the
variability in the heating value of sludge and the lack of emission factors provided in the
proposed ruling. It is unclear in NACWA's review why they consider biogas, but not sewage
sludge, a biomass-derived fuel.
Response: In the final rule, Subpart C (Stationary Fuel Combustion Units) has been revised
since proposal to require reporting of only those biomass fuels listed in Table C-l of Subpart C.
EPA has clarified this table, and sewage sludge is not included. Therefore, emissions from sewer
sludge would not be reported.
Commenter Name: Robert D. Bessette
Commenter Affiliation: The Council of Industrial Boiler Owners (CIBO).
Document Control Number: EPA-HQ-OAR-2008-0508-0513.1
Comment Excerpt Number: 34
Comment: Biogenic CO2 emissions methodology does not address liquid fuels that are derived
from biogenic sources, e.g., liquid byproduct streams from biological transformation processes.
Those streams should be treated similarly to biogas combustion in that either Tier 2 or Tier 3
methodology could be used. However, analyses of both biogenic liquids and biogases derived
from processing where analyses do not vary significantly over time should be allowed to use
periodic analyses or engineering determinations of quality for determining annual biogenic CO2
emissions. Such periodic evaluations could be based on initial determinations and then
subsequently upon significant changes to the process.
512
-------
Response: In preparation of the final rule, EPA has added a provision to §98.33(e) allowing the
use of Tier 1 methods to calculate biogenic emissions from most biogenic fuels listed in Table
C-l. If the biogenic fuels consist of biogas or biodiesel and the HHV is sampled at the minimum
required frequency (quarterly), Tier 2 shall be used instead. EPA has added emission factors to
Table C-l for liquid and gaseous biomass-derived fuels including biogas, ethanol, biodiesel,
rendered animal fat, and vegetable oil. For premixed fuels that contain biomass and fossil fuels
(e.g., mixtures containing biodiesel), sources may use the best available information to determine
the mass of biomass fuels and document the procedure used in the GHG Monitoring Plan.
Commenter Name: Chris Hornback
Commenter Affiliation: National Association of Clean Water Agencies (NACWA)
Document Control Number: EPA-HQ-OAR-2008-0508-0566.1
Comment Excerpt Number: 11
Comment: EPA should provide more detail or specific examples in its definition of biomass.
NACWA believes based on its reading of the proposal that biosolids or sewage sludge would be
considered a biomass fuel, but it is not absolutely clear that this is consistent with EPA's intent.
Response: EPA has finalized the definition of biomass as proposed. In the final rule, Subpart C
(Stationary Fuel Combustion Units) has been revised since proposal to require reporting of only
biomass fuels listed in Table C-l of Subpart C. EPA has clarified this table, and sewage sludge
is not included. Therefore, emissions from sewage sludge would not be reported.
Commenter Name: Lorraine Krupa Gershman
Commenter Affiliation: American Chemistry Council (ACC)
Document Control Number: EPA-HQ-OAR-2008-0508-0423.2
Comment Excerpt Number: 29
Comment: The definition of biomass should be expanded to encompass materials resulting
from biofuels production or bio-based materials processing. We recommend that the definition
should be revised as follows: "... including products, by-products, residues and waste from
agriculture, forestry and related industries, biofuels and bio-based materials industries, as well as
the non-fossilized..." This change is to clarify the source of materials for inclusion in biogenic
CO2 emissions.
Response: In response to the comment, EPA does not believe that any additional language is
needed to address the biomass definition. Biomass means non-fossilized and biodegradable
organic material originating from plants, animals and/or micro-organisms, including products,
by-products, residues and waste from agriculture, forestry and related industries as well as the
non-fossilized and biodegradable organic fractions of industrial and municipal wastes, including
gases and liquids recovered from the decomposition of non-fossilized and biodegradable organic
material. In §98.6 of the final rule, the definition states that organic material originating from
products and byproducts from agriculture, forestry and related industries are defined as biomass.
Biofuels derive from agricultural sources, and therefore it is implied that they would fall under
this definition. Table C-l in the General Stationary Combustion subpart has been revised to
513
-------
provide default values for more biogenic fuels.
Commenter Name: Robert D. Bessette
Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)
Document Control Number: EPA-HQ-OAR-2008-0508-0513.1
Comment Excerpt Number: 15
Form Letter? No
Comment: The definition of biomass should be expanded to encompass materials resulting
from biofuels production or bio-based materials processing. CIBO recommends this revised
text: "... including products, by-products, residues and waste from agriculture, forestry and
related industries, biofuels and bio-based materials industries, as well as the non-fossilized..."
This change is to clarify that source of materials for inclusion in biogenic CO2 emissions.
Response: EPA has clarified the definition of biomass in the rule. Biomass means non-
fossilized and biodegradable organic material originating from plants, animals and/or micro-
organisms, including products, by-products, residues and waste from agriculture, forestry and
related industries as well as the non-fossilized and biodegradable organic fractions of industrial
and municipal wastes, including gases and liquids recovered from the decomposition of non-
fossilized and biodegradable organic material. It has also clarified the list of fuels in Table C-l,
which would be expected to be reported using the Tier 1 Calculation Methodology.
Table 1
( OMMI YITK
Allll.l All-
IK N
Thierry Sam Tamers
Beta Analytic Limited
EPA-HQ-OAR-2008-0508-0278
Maurico Larenas
Beta Analytic Limited
EPA-HQ-OAR-2008-0508-0307.1
Table 2
( OMMI YI I K
\l 1 III All.
IK N
Michel R. Benoit
Cement Kiln Recycling Coalition (CKRC)
EPA-HQ-OAR-2008-0508-0467
Andrew T. O'Hare
Portland Cement Association (PCA)
EPA-HQ-OAR-2008-0508-0509.1
Table 3
( OMMI YM K
AITII.IAM.
IK N
James Greenwood
Valero Energy Corporation
EPA-HQ-OAR-2008-0508-0571.1
EP A-HQ-0 AR-2008-0508-0571.2
Charles T. Drevna
National Petrochemical and Refiners Association
EPA-HQ-OAR-2008-0508-043 3.1
EPA-HQ-OAR-2008-0508-0433.2
Table 4
( OMMIYIIK
Al 1 II.IATI.
IK N
Olon Plunk
Xcel Energy Inc.
EP A-HQ-0 AR-2008-0508-0444
Debra J. Jezouit
Class of '85 Regulatory Response Group
EP A-HQ-0 AR-2008-0508-0455.1
Table 5
( OMMI YIT K
Allll.l ATT.
IK N
Lisa I'.cnl
liners laic Nalural Gas Abbocialion of
America (INGAA)
LPA-11Q-0-\R-2008-0508-0480.1
Richard Bye
CenterPoint Energy, Inc.
EP A-HQ-0 AR-2008-0508-2124.1
Brianne Metzger
Spectra Energy Corporation
EP A-HQ-0 AR-2008-0508-0364.1
514
-------
Table 6
( OMMI.YH.K
Al 1 II.IA Tl.
IK N
Karin Ritter
American Petroleum Institute (API)
EPA-HQ-OAR-2008-0508-0679.1
James Greenwood
Valero Energy Corporation
EP A-HQ-0 AR-2008-0508-0571.1
William W. Cry gar II
Anadarko Petroleum Corporation
EPA-HQ-OAR-2008-0508-0459.1
Table 7
COM Ml'.NTIK
All-Ill All-
IK N
Johnny R. Dreyer
Gas Processors Association (GPA)
EP A-HQ-0 AR-2008-0508-0412.1
William W. Grygar II
Anadarko Petroleum Corporation
EPA-HQ-OAR-2008-0508-0459.1
Table 8
( OMMI YM K
AIIIIIAIT.
IK N
Pamela A. Lacey
American Gas Association (AGA)
EP A-HQ-0 AR-2008-0508-0709.1
Richard Bye
CenterPoint Energy, Inc.
EP A-HQ-0 AR-2008-0508-2124.1
Table 9
( OMMI.MI.K
Al 1 II.IA I I.
IK N
Cluii Hub soil
The Southern Company
EP A-HQ-0 AR-2008-0508-1645.1
Quinlan J. Shea, III
Edison Electric Institute (EEI)
EP A-HQ-0 AR-2008-0508-1021.1
Table 10
( OMMI YM K
AIIIIIAIT.
IKN
(!raig Holt Segall
Sierra Club
EP A-HQ-0 AR-2008-0508-063 5.1
Melissa Thrailkill
Center for Biological Diversity
EP A-HQ-0 AR-2008-0508-0430.1
515
------- |