£EPA
Air and Radiation EPA420-B-05-010
September 2005
United States
Environmental Protection
Agency
Questions and Answers on the
Clean Diesel Fuel Rules
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EPA420-B-05-010
September 2005
Questions and Answers on then
Clean Diesel Fuel RulesD
Assessment and Standards Division D
Office of Transportation and Air Quality D
U. S. Environmental Protection Agency D
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Introduction
The following are responses to questions received by the Environmental Protection Agency
(EPA) concerning the manner in which the EPA intends to implement and assure compliance
with the diesel fuel sulfur regulations at 40 CFR Part 80. This document was prepared by EPA's
Office of Air and Radiation, Office of Transportation and Air Quality, and the Office of
Enforcement and Compliance Assurance, Office of Regulatory Enforcement.
Regulated parties may use this document to aid in achieving compliance with the diesel fuel
sulfur regulations. However, this document does not in any way alter the requirements of these
regulations. While the answers provided in this document represent the Agency's interpretation
and general plans for implementation of the regulations at this time, some of the responses may
change as additional information becomes available or as the Agency further considers certain
issues.
This guidance document does not establish or change legal rights or obligations. It does not
establish binding rules or requirements and is not fully determinative of the issues addressed.
Agency decisions in any particular case will be made applying the law and regulations on the
basis of specific facts and actual action.
While we have attempted to include answers to all questions received to date, the necessity for
policy decisions and/or resource constraints may have prevented the inclusion of certain
questions. Questions not answered in this document may be answered in a subsequent
document. The Agency intends to provide any additional responses as expeditiously as possible.
Questions that merely require a justification of the regulations, or that have previously been
answered or discussed in the preamble to the regulations have been omitted.
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**New and Revised Questions**
The following questions have been revised and/or added since the March 2005 version:
Revised
• 3.2, 3.3, 3.23, (also, the second 3.23 that appeared in the original QAs is now 3.24,
3.24 is now 3.25, and 3.25 is now 3.26)
• 4.18, 4.35
• 9.5
• 10.7,10.10,10.14
Added
• 1.29-1.50
• 3.27
. 4.36-4.41
• 7.6-7.11
• 9.9
• 11.16, 11.17
• 12.26, 12.27
• 14.5-14.7
• 15.9
11
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Table of Contents D
List of Acronyms vD
1. Designate and Track (D&T) Issues ID
2. Handling/Downgrading Issues 26 D
3. Analytics R&D Issues/Test Methods 40D
4. Regulatory Clarification and Thoughts/Questions for EPA 48 D
5. Cetane Index/Aromatics Requirements 61D
6. Sulfur Standards 62D
7. Additives 64D
8. Credits 67D
9. Product Transfer Documents (PTDs)/Bills of Lading (BOLs) 73 D
10. Documentation 76 D
11. Testing 83 D
12. Enforcement 88D
13. GPA/Small Refiners 105D
14. Transmix/Interface Fuel 109D
15. General/Miscellaneous 113 D
in
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ivD
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List of Acronyms
ASTM
BOL
bpcd
CAA
CBI
CDX
CFR
CI
CTA
D&T
DTAB
EPA
FTC
GPA
HS
HW
IRS
ISO
kbpd
LDDV
LM, L&M
LSD
mmBTU
MV
MVNRLM
MY
NE/MA
NIST
NOV
NR
NRLM
American Society for Testing and Materials
Bill of Lading
Barrels per Calendar Day
Clean Air Act
Confidential Business Information
Central Data Exchange
Code of Federal Regulations
Cetane Index
Credit Trading Area
Designate and Track
Diesel (Fuel) Treated As Blendstock
Environmental Protection Agency
Federal Trade Commission
Geographic Phase-In Area
High Sulfur (generally refers to sulfur levels greater than 500 ppm)
Highway
Internal Revenue Service
International Organization for Standardization
Thousand Barrels Per Day
Light-Duty Diesel Vehicle
Locomotive and Marine Diesel
Low Sulfur Diesel (500 ppm sulfur)
Million British Thermal Units
Motor Vehicle (also, HW or highway)
Motor Vehicle Nonroad, Locomotive, and Marine Fuel
Model Year
Northeast/Mid Atlantic
National Institute of Standards and Technology
Notice of Violation
Nonroad Diesel
Nonroad, Locomotive, and Marine
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OECA
OMB
OTAQ
PADD
PBMS
ppm
FDD
PTD
SBA
SRM
RFG
SR
TCO
ULSD
VAR
Office of Enforcement and Compliance Assurance
Office of Management and Budget
Office of Transportation and Air Quality
Petroleum Administration Districts for Defense
Performance Based Measurement System
Parts Per Million
Previously Designated Distillate
Product Transfer Document
Small Business Administration
Standard Reference Materials
Reformulated Gasoline
Small Refiner
Temporary Compliance Option
Ultra-Low Sulfur Diesel (15 ppm sulfur)
Volume Accounting Reconciliation
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l.D Designate and Track (D&T) Issues
1.1: D When is EPA's Designate and Track (D&T) reporting mechanism expected to be
completed?
A: D D& T reporting will be an electronic reporting system, similar to the existing Tier
2 Gasoline Sulfur reporting program. Reports will be a flat file format based on
spreadsheet templates. Additionally, we are working with EPA 's Office of
Environmental Information on a pilot project for accepting Confidential Business
Information (CBI) through EPA 's Central Data Exchange (CDX). CDXwill
enable us to utilize digital signatures and eliminate our dependency on a hybrid
reporting system where electronic data must be accompanied by a hardcopy
printout and certification with a "wet ink" signature. The CDX pilot is scheduled
for completion February 2006. Reporting parties for RFG & Anti-dumping and
Tier 2 Gasoline Sulfur will be the first users of this system.
1.2: D We understand that many ULSD designated "facilities" are currently unregistered with
EPA. They must apply for a registration or permit number by December 2005 in order to
get a registration number by the NRLM rule's effective date. There is currently no
application mechanism.
A: D The RFG & Anti-dumping registration system will be the basis for ULSD
registration and similar procedures will apply. Companies that have an existing
Company ID with RFG & Anti-dumping may add ULSD facilities, while
companies not registered with RFG & Anti-dumping will need to request
Company and Facility IDs. Registration will be done using forms posted on
OTAQ 's Fuel and Fuel Additives Reporting Forms web page
^ttp://www.epa.gov/otaq/regs/fuels/dieselfms.htm|
1.3: D Section 80.535 of the NRLM rule allows refiners to produce early credit NRLM low-
sulfur (500 ppm) diesel. If undyed, this low-sulfur NRLM diesel is considered on-road
fuel UNLESS it is designated as NRLM or LM diesel fuel. The NRLM early credit rule
takes effect June of 2006. We will therefore need a registration number by June 1, 2006
in order to move early credit NR low-sulfur diesel fungibly with on-road. Is this correct?
A: D Yes. Refinery designation requirements begin June 1, 2006, as well as several
other provisions, including Product Transfer Documents (PTDs). Therefore,
facility registration would be required prior to June 1, 2006. This is not limited
to the NRLM early credit fuel.
1.4: D In addition, company software professionals will need at least 6 months to incorporate
any external reporting system into the company software. What is the anticipated process
and timing for developing the D&T reporting software? When will D&T software, or
standards, be available to develop systems to feed them?
ID
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A: D EPA is not developing reporting software. The reporting process will be similar
to the Tier 2 Gasoline Sulfur system -flatfile, text or spreadsheet submission.
Common practice is for EPA to share draft versions of forms with third party
software vendors and industry representatives (AOPL, API, NPRA, etc.) for
review and comment. Report Form instructions and templates for D& T are
available on the OTAQ Fuel and Fuel Additives Reporting Forms web page
^ttp://www.epa.gov/otaq/regs/fuels/dieselfms.htm|
1.5: D Most of the receipt and delivery facilities that pipelines operate do not have EPA
registration numbers required to implement D&T. If a terminal receives product from
several pipelines, each one will require a registration number for that custody transfer. Is
EPA ready to process the volume of applications required? When will the registration
applications be available?
A: D EPA will process ULSD facility registration applications in a timely manner and
anticipates no difficulty in doing so. Registration will be done using the forms
posted on OTAQ's Fuel and Fuel Additives Reporting Forms web page..
1.6: D If a pipeline does not handle 500 ppm highway fuel, it appears that they are still required
to file D&T reports, is this correct? Systems cannot opt out of D&T by handling only
certain products?
A: D All facilities are required to compile and file D&T reports if they handle any
designated fuel upstream of the point where taxes are assessed, and dye and/or
marker is added if required. This includes a pipeline that does not handle any
500 ppm highway die sel fuel. In that case, the D&T reports would confirm that
the pipeline did not handle this highway fuel, and did not violate any of the
restrictions on redesignating off-road fuel as highway fuel. The D& T reports
from this pipeline would also be used in evaluating compliance by the parties
before and after this pipeline in the distribution system. This pipeline is only one
step in a chain of fuel hand-off s, and the D&T system is designed to use
information from each party to a hand-off to ensure compliance by all of the
parties in the chain of distribution.
1.7: D Will refiners be required to provide data sheets, or other types of testing data to insure
pipelines receive the correct product?
A: D Refiners are required to maintain batch testing records which demonstrate
compliance with the applicable sulfur standard. The PTD that accompanies the
transfer of a batch of designated fuel from a refiner to a pipeline operator must
correctly identify the sulfur standard to which the fuel complies. However, there
is no EPA requirement that testing records accompany the batch of fuel when it is
transferred to the custody of a pipeline operator. Any private requirements
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established between refiners and pipelines, would be business decisions that are
separate from EPA 's regulations.
1.8: D What is the plain English clarification of § 80.598(b)(9)(vii)(B) and § 80.599(b)(5)?
A: D The regulations limit the volume of 500 ppm NRLM that may be redesignated as
highway 500 ppm by fuel distributors. Section 80.598(b)(9)(vii)(B) applies to
distributors other than truck loading terminals. To ensure that there are no
significant redesignations over the annual compliance period for these facilities,
the volume of 500 ppm sulfur highway dieselfuel that a facility discharges from
it's custody must be no greater than 102 percent of the volume of 500 ppm sulfur
highway fuel that the facility received during the annual compliance period,
taking into account inventory change. This provides pipelines and other parties
upstream of truck loading terminals a tolerance of 2% during the annual
compliance period to account for metering differences, volume swell, and the like.
See 69 Fed. Reg. 39070 (June 29, 2004). Section 80.599(b)(5) requires that
dieselfuel greater than 500 ppm sulfur must be designated as a fuel other than 15
ppm or 500 ppm highway or NRLM. For example, it can be designated as
heating oil or another dieselfuel that can lawfully be above 500 ppm. Requiring
a proper designation for high sulfur dieselfuel is the first step in ensuring that it
stays segregated from fuel that is supposed to meet the 15 ppm or 500 ppm sulfur
level.
1.9: D What are the Designate & Track Quarterly and Annual start and finish dates? The
Quarterly Compliance Periods listed in § 80.599 begin June 1, 2007 and end September
30, 2010, but the Quarterly Reporting listed in § 80.601 begins November 30, 2007 and
ends August 31, 2010. Why would the report period end before the compliance period?
There is a similar issue with the Annual report versus compliance dates.
A: D The dates for the quarterly and annual compliance periods and reporting dates
were incorrect in the Final Nonroad Rule regulations but were correct in the
preamble (69 FR 39100, June 29, 2004). This error was corrected in a technical
amendment to the regulations (which can be found on EPA 's web site at:
http://www.epa.gov/otaq/regs/fuels/diesel/diesel.htm#regs. July 7, 2005). The
correct preamble dates for the compliance periods and reporting dates are as
follows:
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Quarterly Compliance Periods and Reporting Dates
Quarterly Compliance Period*:
July 1 through September 30
October 1 through December 31
January 1 through March 31
April 1 through June 30
Report Due Date:
November 30
February 28
May 31
August 31
* The first quarterly reporting period will be from June 1, 2007 through September 30, 2007 and the last quarterly
compliance period will be from April 1, 2010 throughMay 31, 2010.
Annual Compliance Periods and Reporting Dates
Annual Compliance Period:
June 1, 2007 -
July 1, 2008 -
July 1, 2009 -
June 1, 2010 -
July 1, 2011 -
June 1, 2012 -
July 1, 2013 -
June 1, 2014 -
July 1, 2015 -
June 30, 2008
June 30, 2009
May 31, 2010
June 30, 2011
May 31, 2012
June 30, 2013
May 31, 2014
June 30, 2015
June 30, 2016
Report Due Date:
August 31
August 31
August 31
August 31
August 31
August 31
August 31
August 31
August 31
1.10:D Is downstream D&T no longer required in 2010 or in 2015 or ever?
A: D The downstream D&T provisions change over time, as the standards change and
more of the highway and off-highway dieselfuel becomes subject to the 15 ppm
refinery gate standard. In general, downstream parties will always have to
designate the dieselfuel they transfer, as part of the PTD requirements. However
over time there will be less need to track various kinds of die sel fuels and fewer
volume balances that will apply. After May 2014 the only tracking and related
volume balances that will apply downstream involve heating oil and 500 ppm LM,
to avoid improper transfer of low sulfur heating oil into the LM market.
1.11: D If only credit fuel is sold into the heating oil market, does a marker need to be added?
Does a pipeline need to track if not receiving heating oil into its system? Same for the
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marker in L&M, if only credit 500 ppm NR is received and no 500 ppm L&M, does it
need to mark and does it need to track?
A: D First, the requirement to mark heating oil is limited to heating oil used in certain
parts of the country. In general, the marker does not need to be added to diesel
fuel distributed from a terminal within the northeast and mid-Atlantic area and
Alaska, for use in those areas. That means the great bulk of the heating oil
market is not subject to a marking requirement. For heating oil produced or
distributed outside those areas, the terminal is required to mark heating oil prior
to distribution from the truck loading terminal. If the fuel is designated as
something other than heating oil, then it does not need to be marked, and will be
subject to the sulfur level applicable to its designation. Outside the areas noted
above, any diesel fuel that is not marked is presumed to not be heating oil, and
typically will be considered motor vehicle or NRLMfuel and subject to the
appropriate sulfur standard.
Therefore, if it is designated as NRLM, it is not treated as heating fuel, but rather
NRLM and it does not need to have the marker added. NRLM can always be used
as heating oil or LM diesel fuel, without any change in its designation, however
it remains subject to the sulfur standard that applies to its NRLM or LM
designation. If the NRLM is redesignated as heating oil, it would need to be
marked at the terminal. Similarly, if it is designated as NRfuel, and not L&M,
then no marker needs to be added unless it is redesignated as LM.
Any pipeline that receives designated fuels (including high sulfur NRLM, and
credit 500 ppm NRfuel) must comply with the designate and track requirements.
This information is essential for downstream parties to be able to demonstrate
their compliance with the marker requirements for heating oil and 5 00 ppm LM
fuel (from 2010-2012). It will also be used by EPA to verify the compliance of
parties who receive fuel from the subject pipeline by allowing us to compare the
volumes of designated fuels reported as received from the pipeline with the
volumes reported delivered by the pipeline.
1.12: D Do pipelines without truck loading terminals need to submit quarterly D&T reports or
just annual D&T reports?
A: D Pipelines without truck terminals must submit both annual and quarterly reports
prior to July 1, 2010. The quarterly reports will contain the information on
receipts and deliveries of designated fuel volumes. The annual reports will
contain information to show compliance with volume balance requirements over
the annual compliance period. Beginning, July 1, 2011, only annual reports need
to be submitted (see chart on quarterly and annual compliance dates, in question
1.9), and compliance with volume balance requirements continues to be on an
annual basis.
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1.13: D In the definition of facility, can a common carrier pipeline be aggregated with any other
non-common carrier terminals if they are all owned by the same parent company?
A:U Yes, if certain conditions are met. First, a single entity, in this case, the parent
company must maintain custody of the fuel at all times in the aggregated facility
(i.e. the parent company must maintain custody at all subsidiary/leased terminals
defined as part of that aggregated facility). If the parent company/entity fails to
maintain custody of the fuel at any point, that point cannot be considered part of
the aggregated facility. In addition, the choice to treat places as aggregated or
separate facilities may not be changed by the entity during any applicable
compliance period. If a refinery is part of the aggregated facility, the common
carrier pipeline may not be included as part of the aggregated facility.
1.14:D If an entity, for & facility (as those terms are defined in 40 C.F.R. § 80.502), chooses a
single registration number for its refinery, pipeline, and terminal (thus creating an
'aggregated facility'), does this mean that in the event of finding product in violation of
the diesel fuel regulations, only the registered entity will be subject to civil penalty, and
not all 3 portions of the system separately?
A: D It is dependent on the type of violation. For volume balances, liability falls on the
entity in relation to its facility. The volume balance is calculated over the entire
aggregated facility that is registered, and the entity that registered the facility will
be subject to the penalty. For other violations (such as violations of the
applicable sulfur level of a batch of fuel), the liability is not limited. The fact that
the terminal is aggregated with a pipeline and refinery for volume balance
purposes is only relevant to this violation because it means, by the definition of an
aggregated facility, that the entity has custody of the fuel at all locations.
However any other entity or person who takes custody of the fuel may also be
subject to presumptive liability.
1.15: D At the terminal, if a pour point depressant, conductivity improver, lubricity improver
which is compliant to the 15 ppm standard is injected, must the terminal operator register
as a refiner?
A: D Injecting such additives to a batch of fuel would not make a terminal operator a
refiner.
1.16: D Some pipeline and marine terminals receive fuel from multiple refineries. Will they need
separate facility ID numbers?
A: D The terminal owner must obtain a facility ID for its facility, subject to any ability
to lawfully aggregate into a larger facility. The fact that the terminal facility
receives fuel from various refineries does not change the fact that it is a still a
single place in the distribution system that is owned by a single entity. Similarly,
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a pipeline receives a single ID for a single facility notwithstanding how many
refineries supply fuel to that facility. Consequently, the terminal in this situation
would need only one facility ID number for its terminal operations. However, if
fuel is imported into the terminal, or the terminal acts as a refiner, the terminal
will need to state such activity, in addition to the other quarterly reporting
requirements of§ 80.601, and additionally will have annual reporting
requirements of§ 80.604. The party will also need to register as a refiner or
importer, and meet all applicable refiner or importer requirements, but that
would not change the facility ID that goes with the terminal facility.
1.17: D If a company has two (or more) refineries and transfers highway diesel blendstocks
between refineries, are they precluded from aggregating?
A: D Refineries are precluded from aggregating with other refineries.
1.18:D If a terminal has 15 ppmNo. 2 and 500 ppm kerosene (No. 1), can a truck blend the two
(winter blending) and take 500 ppm to the pump at retail? Who is responsible for the
downgrading accounting?
A: D The two fuels can be blended as long as the appropriate volume balances are met.
When the terminal received the 15 ppm No. 2, it would have been designated as
highway or NRLM. The limit on downgrading applies to No. 2 15 ppm highway
diesel fuel that the terminal receives, and restricts the ability of the terminal to
redesignate it as 500 ppm highway. Both the terminal and the truck transporter
would have to meet the anti-downgrading and any other applicable volume
balances, based on comparing the volumes and designations of fuel they received
to fuel delivered. Since accounting responsibility is keyed to what you received
and delivered, it will make a difference whether the blending occurred before or
after custody was transferred. For example, if the blending occurs before the
terminal transfers custody, then the terminal has to account for the blended fuel
in its delivery accounting. If blending occurred after the transfer of custody, then
the truck transporter will have to account for the blended fuel in its delivery
accounting.
1.19: D In attempting to balance reporting requirements, if a pipeline ticket is generated for a
particular amount of barrels/gallons, a terminal will have a natural gain or loss. Do you
have a tolerance or must it match exactly?
A: D The reported hand-off volumes must match - there is no tolerance. However, to
account for gains and losses in the system, the D&T provisions allow for a 2%
gain/loss over the course of the annual compliance period for pipelines. See
answer to question 1.8, above. For terminals, there is no such specific tolerance,
however, they have the ability to adjust by redesignating volumes accordingly.
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1.20: D Who is responsible for the product if it comes in to the terminal (from a pipeline) over 15
ppm?
A: D Presumptive liability under 40 C.F.R. § 80.612 applies to the party in possession
of the contaminated fuel (in this case, the terminal after it has taken custody) and
to all parties upstream of the facility where the violation is found (including, in
this case, the pipeline). Each party has an opportunity to establish a defense to
liability. Until it is proven which party is at fault, all parties involved in the
production and distribution of the product will be presumed liable.
1.21: D Please confirm that a terminal operator selling 500 ppm nonroad diesel outside the
(Northeast/Mid-Atlantic) NE/MA Area does not have to add the marker because that fuel
need not be differentiated from higher sulfur (greater than 500 ppm) nonroad diesel fuel
generated by credits.
A: D Only diesel fuel designated as heating oil need be marked if it is distributed from
either a terminal outside of the NE/MA Area or a terminal inside the NE/MA Area
for delivery outside of the Area.
Beginning in 2007, all heating oil must contain the marker outside the NE/MA
area. From 2010 to 2012, fuel designated as 500 ppm LMfuel also must contain
the marker. In this instance the terminal selling the 500 ppm fuel does not have
to add a marker unless it is either heating oil or, during 2010 to 2012, LMfuel. If
it is not marked, then it will be treated as subject to the appropriate sulfur
standard. The terminal selling the high sulfur fuel would need to mark the fuel if
it is heating oil. The high sulfur fuel could not be designated as 500 ppm LM, so
the LM marking requirement should not apply.
1.22: D A company owns a refinery and ships its product via a common carrier pipeline it owns
(and now exclusively uses) to a terminal that it owns. Can these facilities be aggregated,
or does the fact that the company's pipeline is a common carrier pipeline preclude
aggregation?
A:U As stated in the regulation (§ 80.502(b)(l)), facilities may be aggregated if
custody is maintained by one entity that owns those specific facilities. Per §
80.502(b)(2), refineries may only be aggregated with facilities that do not receive
fuel from other refineries or import facilities. In the case stated here, the
"common carrier" status of the pipeline does not matter if the pipeline is not
receiving fuel from other entities. The common carrier pipeline example that was
used in the regulations was only meant to refer to the typical case where an entity
receives fuel from various sources, and thus would not meet the criteria for
facility aggregation.
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1.23: D If a company redesignates, please explain how to restore volumes so that required
volume balances are met.
A: D The volume balance requirements limit certain types ofredesignations, unless the
volume balance is met over the compliance period. For example, during a
compliance period a terminal may redesignate NRLM as highway fuel as long as
over the compliance period the terminal meets the required volume balance. If a
terminal has been receiving fuel designated as NRLM and delivering some of it as
highway and some as NRLM, the volume balance on highway fuel could go
negative during that compliance period. To offset this, the terminal would have
to take delivery of the fuel designated as highway and redesignate enough of it as
NRLM to satisfy the volume balance.
1.24: D How will a terminal designate a mixture of transmix and "off-spec" fuel that might be a
combination of 15 ppm, all grades of 500 ppm, heating oil, and jet fuel? Will this
designation(s) limit the marketing options of a transmix handler beyond the limits that
would be imposed strictly by the sulfur content of the mixture alone?
A: D The designation is left to the terminal. The designation must be clear and
accurate, therefore the sulfur level of the mixture will limit the designation
options. Beyond that, the designate and track compliance calculations have been
designed to minimize, if not eliminate, any unintended marketing limitations.
1.25: D According to the preamble (page 39067), "EPA intends to work with industry subsequent
to this final rule to provide guidance regarding facility boundary and aggregation
decisions that will address the many unique situations." It appears from the discussion in
the preamble that such "unique situations" are present when the same entity owns and
operates a series of locations in the distribution system. Under the rule, the entity may
choose whether to aggregate or to treat the separate locations as separate facilities. It
would appear that such guidance might not be necessary, because an entity has the
flexibility under the rule to determine where to draw lines around its facilities, so long as
each facility meets the definition of "facility" under the rule. What is EPA's intent with
regard to such guidance? When can industry expect to become part of these discussions?
Has EPA developed a working list of the "unique situations"? Is EPA's intent with the
guidance to address the definition of a "facility" and to help the regulated community
understand the parameters of a facility?
A:U In addition to this Question/Answer document, EPA has released Small Entity
Compliance Guides (see http://www.epa.gov/cleandiesel/comphelp.htm) to assist
small entities in complying with the requirements of the rulemaking. It was our
intention that the presentations and discussions that occurred at the Clean Diesel
Fuel Workshop in November 2004 would help to clarify and address questions
and/or concerns that industry had regarding the definition of "facility. " We will
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also answer any other questions as they arise and will continue to work with the
fuel industry to ensure a smooth transition to ultra low sulfur diesel fuels.
1.26: D When will the new technology vehicles start being sold (i.e. what is the absolute target
date for ULSD at the pump)?
A: D Heavy-duty vehicle model years typically start on January 1. However, they
could start several months earlier and medium-duty vehicles often do. Light-duty
vehicle model years typically start even earlier. We designed the program with a
retail target date of September 1, 2006. The regulations set out the dates when
fuel must meet the sulfur standards at various points in the distribution system.
The regulations also prohibit selling anything other than 15 ppm sulfur diesel fuel
to 2007 or later model year highway vehicles.
1.27: D My company is co-owner of a single physical pipeline that is operated as if it were two
separate pipelines. Each of the co-owners has a set fraction of the pipeline's capacity and
has established its own tariff rates which it charges to its customers. May each of the co-
owners obtain a separate facility registration under the designate and track system with
respect to its operations on this pipeline?
A: D Section 80.502(b)(5) of the diesel fuel regulations states that a contiguous
pipeline may not be subdivided into more than one facility. Based on this, your
pipeline could not be subdivided into two facilities with separate facility
registrations. EPA adopted this requirement because we believe that allowing an
individual pipeline to be subdivided for D&Tfacility registration purposes would
severely impact EPA's ability to evaluate compliance and assign liability for
potential violations.
1.28: D My company imports diesel fuel into storage tanks that we lease at a terminal in New
England. Please explain the responsibilities of the importer and the terminal owner with
respect to the designate and track requirements related to the importation of diesel fuel.
A: D The importer must register separately for each terminal facility into which it
imports fuels. EPA will issue an import facility registration number for the
importer that is composed of a numerical entity code and a numerical location
code (the location being the terminal). The terminal owner will be provided with
a terminal facility registration number composed of a location number (same as
that supplied to the importer) and an entity registration number. Alternately, if
the imported fuel is certified before delivery to a U.S. terminal, then the importer
may obtain a registration for a "virtual" off-shore import facility. In such cases,
the importer will be given an import facility registration number applicable to the
importation of fuel into any terminal located in a single PADD. It has been the
practice for EPA to issue these types of "virtual" import facility registrations for
imported gasoline.
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The importer must appropriately designate all imported fuels. For each of its
registered facilities, the importer must also fulfill all of the record-keeping and
reporting obligations applicable to an importer. For example, the importer must
demonstrate compliance with the requirement that 80% of all highway dieselfuel
it imports meets a 15ppm sulfur standard (2006-2010).
The terminal owner must account for the volumes of designated fuels that are
imported into its terminal in demonstrating compliance with the volume balance
and anti-downgrading requirements.
1.29: D The regulations state that a contiguous pipeline may not be broken down into more than
one facility for the purposes of complying with the designate and track reporting
requirements. There is a break-out tank facility in our pipeline system where all of the
fuel in the trunk line feeding the facility (trunk line #1) typically enters break-out tankage
before being passed further down our system through another segment of our trunk line
(trunk line #2) or to several stub-lines. However, it is possible for some or all of the fuel
in trunk line #1 to bypass the subject break-out tank facility and to be fed directly into
trunk line #2. Could trunk lines #1 and #2 be considered separate facilities?
A: D The facilities described in the question could be registered separately. The
provisions in § 80.502(b)(5) are only intended to prevent the subdivision of a
pipeline for reasons not sufficiently related to a true physical division in a section
of a pipeline owned by one entity, such as the presence of a booster pump station
in the line. Break-out tank facilities are necessary at locations in a pipeline
system where pipelines of different diameters and flow rates are connected, and
where branching in the pipeline system takes place. Therefore, a break-out
facility is an appropriate location at which to draw a distinction between different
parts of the pipeline system with respect to compliance with the designate and
track requirements.
1.30: D My company owns certain distinct physical parts of a terminal (pipeline manifold,
several storage tanks, and the truck loading rack), whereas other parts of the same
terminal (several storage tanks) are owned by another company. Would EPA consider
allowing such a terminal to be subdivided for registration purposes under the designate
and track (D&T) provisions of the diesel sulfur regulations? Under such an approach,
each party would register, keep records, and demonstrate compliance for those physical
assets at the terminal which it owns. It would be inappropriate to force these parties to
become jointly responsible for the terminal as a whole.
A: D A facility is defined as the place or series of places at which an entity produces,
imports, or maintains custody of the fuel, extending from the point of initial
custody to the point that custody is transferred (§ 80.502(b)). Under this
definition, there would be two facilities at the terminal described in the question-
one associated with each owner/entity. Each facility would cover the part of the
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terminal where the owner/entity had custody of the fuel. This is also consistent
with § 80.502(b)(5), which provides that an individual terminal can not be
subdivided into more than one facility (without approval by EPA). That provision
applies to the process of voluntarily subdividing a facility after the physical extent
of the facility has been initially determined under § 80.502(b). This terminal
subdivision provision does not determine the physical extent of the location that
initially meets the definition of facility under § 80.502(b). It restricts the
voluntary subdivision of the facility once the extent of the facility has been
determined under § 80.502 (b). In this case, the definition of facility would lead to
the existence of two separate facilities. Section 80.502(b)(5) then means that
neither of these two facilities may be subdivided without approval by EPA.
It is important to note that this does not mean that joint ownership or an
owner/tenant relationship in a terminal would result in the terminal having more
than one facility. In such cases, the definition of facility leads to the initial
determination that the entire individual terminal is a single facility for the
owner/entity. In that case, approval of the Administrator would be required to
voluntarily subdivide the terminal into more than one facility, under §
80.502(b)(5).
1.31: D Will EPA please explain the registration and other requirements for marine vessel
owners?
A: D EPA will release a separate QA/guidance information on D&T for marine
vessels and other mobile operations.
1.32: D Can you please describe the requirements for a diesel marketer picking up fuel at a
terminal and making a delivery to a retail or wholesale purchaser-consumer site?
A: D If the fuel has already been dyed, taxed, and/or marked, there are no D&T
requirements for the marketer. The diesel marketer does not need to register with
EPA and meet the D&T requirements unless they intend to distribute MVNRLM
500 ppm diesel fuel on which taxes have not been assessed, NRLMfuel that is
undyed, or heating oil or LMfuel that is not marked (in those areas of the country
where the marker is required, per § 80.597(c)(l)). In either case, the marketer
has PTD requirements and would still need to maintain the integrity of the fuel
and, for defense purposes, should have an adequate quality control and sampling
and testing programs. The marketer is also still subject to the anti-downgrading
provisions of § 80.527.
1.33: D Is it possible to receive fuel from/deliver fuel to someone who is not registered? The
regulations state that everyone has to register, however what would happen in the case of
an importer who has never imported fuel to the U.S., and does not plan to do so, but just
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so happens to import a small batch of fuel. Such a party will not likely be registered with
EPA prior to importing the fuel.
A: D Per the regulations of § 80.597 (c), all parties in the die sel fuel production and
distribution system, up to the point where the fuel leaves the D&T boundaries
(i.e., dyed or taxed) are required to register. However, it is possible to receive
fuel from an unregistered entity or facility, as per the requirements and
limitations of§ 80.601 (a) (3). For this case only, the entity/facility ID 8888-88888
must be used.
There is no provision to transfer fuel to an unregistered entity or facility in the
D&T system (i.e., up to and including the truck loading terminal). In this case,
the unregistered entity/facility must contact EPA to request ID numbers. In the
case of the hypothetical importer in the question, it may transfer fuel into the
D&T system without immediately registering (subject to the previously mentioned
requirements and limitations of § 80.601(a) (3) on the recipient), but the importer
must also comply with recordkeeping and reporting requirements, such as annual
batch reports. This activity will require obtaining entity and facility IDs from
EPA.
1.34: D Please consider the following questions regarding situations where D&T may no longer
be applicable:
a)D How should deliveries across truck racks be reported? The trucking company or
retail locations are not registered, so there will be no entity or facility ID. Should
special codes be used to identify these?
A: D Designate and track ends at the point that fuel is dyed or marked (for
those areas of the country where the fuel is subject to the marking
requirement), or taxed- generally just before the fuel is given to a trucking
company. Thus, they will not be registered, nor will they have ID
numbers. There are still PTD requirements for these parties, and the
PTDs associated with such hand-offs will denote both the transferor and
transferee of the fuel, so special codes are not necessary. For reporting,
truck racks must still track total fuel volumes dyed, taxed, and/or marked
by grade. Truck terminals will also still be required to report deliveries
by volume, sulfur level, designation, etc. (§ 80.600(b)).
b) D D&T does not cover barrels of fuel after they leave the truck terminal before
delivery to retail and does not deal with retail stations, correct?
A: D Designate and track ends at the point that fuel is dyed, marked, or taxes are
assessed (for those areas of the country where the fuel is subject to the marking
requirement). The dye and marker can then be used to ensure that fuels are not
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inappropriately shifted to other markets, and thus D&Tis not necessary at that
point. The addition of the dye and/or marker will generally occur at a point
before the fuel exits the terminal, so D&Twill not cover fuel after it leaves the
terminal as long as it has been dyed, marked, or taxes assessed. Please note that
the fuel will still be subject to the anti-downgrading provisions of§ 80.527.
1.35: D Can a truck terminal and the pipeline that brings product to the truck terminal be
aggregated if that same truck terminal receives product from another common carrier
pipeline?
A: D Yes, the truck terminal and pipeline may be considered an aggregated facility if
they are both owned by the same party and if that party maintains custody of the
fuel while it is within the boundaries of the aggregated facility. (Only refineries
are precluded from aggregation in the case of a common-carrier pipeline.) For
reporting, the aggregated facility would need to report volumes received into the
pipeline as well as volumes received into the truck terminal from the common-
carrier pipeline.
1.36: D For a system with multiple truck loading terminals, terminal operators do not necessarily
know which volumes are highway diesel and which volumes are nonroad diesel until the
fuel is loaded. How can volumes be accurately reported at the truck loading terminal
level?
A: D The terminal operator is responsible for maintaining appropriate volume
balances. A recordkeeping system that captures individual batch data is required
for batches received into, as well as batches delivered out of, the terminal.
Reports submitted to EPA summarize, by product type, receipt and delivery
activities and results of compliance calculations for the applicable compliance
period. A terminal operator would report subsequent to the
loading/taxing/dyeing for that compliance period, so the fact that the designation
is unknown until the point that it is loaded does not pose a problem (though, the
individual deliveries must be tracked so that the terminal operator can accurately
report at the end of the reporting period).
1.37: D Can an entity register multiple facilities initially until a history or track record is
established and then in a subsequent compliance period register fewer facilities by
combining some?
A: D Yes, facilities may change their facility boundaries and register some aggregated
facilities in a subsequent compliance period (compliance periods are yearly), as
long as the aggregated facilities do not violate the facility/aggregated facility
provisions set forth in the regulations. However, a party's facility definition or
boundary may not change within a given compliance period.
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1.38: D Do facilities for RFG and ULSD have to be the same? Will EPA assign new ID numbers
for facilities that already have a facility ID under RFG? Will those existing facilities
have to register again?
A: D Facilities for RFG and ULSD can be the same, however they do not have to be the
same. EPA may issue a new number if the facility definition changes. Entities
should still contact EPA to update their registrations, even if you plan to use the
same facility and facility definition that was used for RFG.
1.39: D Can non-contiguous "terminals for hire" that are owned and operated by the same party
be aggregated? Also, can such terminals be aggregated if they receive product from
common-carrier pipelines?
A: D No. These terminals can only be aggregated if they are contiguous and if custody
is maintained by the terminal at all times throughout the aggregated facility.
1.40: D a) If a pipeline system does not transport 500 ppm HW diesel fuel and all NRLM is
dyed before entering the system, would this pipeline be required to comply with
the D&T requirements?
A: D D& T ends completely at the point that fuel is dyed/taxes are assessed
when fuel is being sold or sent off to retail for sale, the pipeline system
would not have to comply with the actual designation and tracking of such
fuels. However, in this case, the pipeline system would still have some of
the D&T requirements, though the requirements are somewhat less. The
pipeline would still need to follow the registration, reporting, and
recordkeeping requirements associated with D& T, and it would still need
to comply with the volume balance requirements.
While the limited fuels you noted would mean there are perhaps fewer
D&T requirements that apply, the pipeline system would still need to meet
several designation requirements depending on the type of fuel that is
delivered. For example, all 15 ppm highway or MVNRLMfuel has to be
designated (§§ 80.598(b)(2) and (3)); and certain high sulfur fuel has to
be designated (§§ 80.598(b)(5) and (6)). The pipeline is still subject to the
volume balance requirements (e.g., anti-downgrading restrictions would
apply if any 15 ppm highway needed to be downgraded to 500 ppm
highway at the point of delivery). The fuel limitation noted above removes
some, but not all, of the D&T requirements for the pipeline.
b)D Similarly, if terminals along this pipeline system do not receive, store, or terminal
any 500 ppm HW diesel fuel and all NRLM is already dyed when received, do
these terminals have to comply with the D&T requirements?
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A: D Similar to part (a), above, there are fewer D&T requirements but the
terminal would still need to meet some designation and volume balance
requirements. For example, 15 ppm MVNRLM received and delivered by
the terminal would still need to be designated, would be subject to the
anti-downgradingprovisions, and would still be subject to volume balance
requirements.
1.41: D What is the D&T responsibility of a truck carrier that hauls off-spec product that has
been neither taxed nor dyed back to a refinery or a transmix facility?
A:U The presumption in this case is that if the fuel is no longer classified as dieseIfuel
(and the PTD should reflect that), the fuel is no longer in the designate and track
system.
1.42: D A refinery produces a batch of diesel containing 10 ppm sulfur, and hands the batch off to
a common-carrier pipeline at 10 ppm. The refinery wants to include the batch in its 15
ppm production volume, but the pipeline tells the refinery that the batch must be
designated as 500 ppm diesel because the batch does not meet the pipeline's inlet sulfur
specification. May the refinery include the batch as part of its 15 ppm production volume
to demonstrate compliance with the 80/20 requirement for refiners and importers, but
designate the batch as 500 ppm when it is handed off to the pipeline? If so, does the
refinery or pipeline need to account for the batch in any downgrading calculations?
A: D Compliance with the 80/20 highway provisions is based on the designation of fuel
received. In the nonroadrule, 'production' refers to a volume of fuel delivered
rather than received. Thus, the pipeline's requirement that the fuel be designated
as 500 ppm highway diesel (and the refiner's designation of the fuel as such) at
the point of delivery to the pipeline means that this batch of fuel would be treated
as 500 ppm fuel for purposes of compliance with the refiner's 80/20
requirements; and downgrading, in this situation, would be the responsibility of
the refiner.
1.43: D Our company owns a refinery linked to company-owned terminal tanks outside the
refinery via a pipeline that is also owned by the refinery. What are the requirements to be
able to register the refinery and terminal separately, knowing that on a routine basis,
refinery production is sent directly (actively) to the terminal tanks? Only fuel
manufactured at our refinery is shipped on the pipeline. If the terminal and refinery
could be registered separately, what would be the requirements to meet in terms of
metering and analysis between the two facilities?
A: D The definition of facility starts with the assumption that a series of contiguous
places where an entity maintains custody over diesel fuel is treated as a single
aggregated facility. There are certain exceptions to this, for example a refinery
may not be aggregated with a pipeline or terminal that receives fuel from other
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refineries. In addition, the entity generally can voluntarily subdivide this
aggregated facility and register multiple facilities. In this case, assuming fuel
from another refinery is not brought into either the pipeline or the terminal, then
the combination of refinery, pipeline and terminal tanks could start off as one
aggregated facility. The owner could also subdivide this and separately register
more than one facility. For example, each component could be a separate
facility, the refinery and pipeline could aggregate as one facility and the terminal
as another, or the terminal could aggregate with the pipeline as one facility with
the refinery as another. While an entity can change its choice in subdivision of
facilities, this choice cannot be changed during a compliance period. Therefore,
the owner does have the option to treat their terminal as a separate facility. (See
§ 80.502.)
It is important to note that once the facility has been registered, it is treated as a
separate part of the distribution system for purpose ofD&T. All of the D&T
requirements apply for any dieselfuel received or discharged from the separate
facility, just as if it was owned and registered by another entity. It is also
important to note that if apart of the system is aggregated with the terminal, such
as the pipeline, then that entire aggregated facility is subject to the D&T
requirements that apply to terminals. Likewise, if the pipeline is aggregated with
the refinery, then that entire aggregated facility is subject to the refiner
requirements. (See § 80.502(b)(l).)
In this case, the hand-off point for purposes of D&T would depend on the facility
subdivision decided by the owner at registration. The decision on subdivision
will then dictate the metering and analysis requirements that apply under D&T.
For example, if the terminal is a separate facility, then the hand-off of custody
from the pipeline to the terminal would be the point at which volumes and
designations would be determined for purposes of D&T, for both the pipeline and
the terminal. If the refinery and the pipeline are separate facilities, then the
point at which custody is handed off from the refinery to the pipeline (the point of
delivery) is the point at which volumes and designations would apply for purposes
of D&T for both the refinery and the pipeline.
The refiner is responsible for certifying that the fuel meets EPA specifications and
would need to conduct tests to support this certification. Facilities downstream of
the refinery are not required to conduct tests to verify that the fuel meets EPA
specifications. However, as one element in establishing a defense to presumptive
liability should a violation be discovered, the regulations provide that
downstream parties must have a quality assurance program that includes
sampling and testing. If the refinery is aggregated with a downstream location,
(e.g., in this case, if the refinery and pipeline are registered as one facility) then
the aggregated facility is subject to the refinery requirements, and not to
downstream D&T requirements. (See § 80.502(b)(l)(i).)
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1.44: D § 80.520(b)(2) states "UntilJime 1, 2010, any #1D or #2D distillate fuel that does not
show visible evidence of dye solvent red 164 shall be considered to be motor vehicle
diesel...except for distillate fuel designated or classifiedas any of the follow ing:... (vi)
Diesel fuel that is produced beginning June 1, 2006, with a sulfur level less than or equal
to 500 ppm, and designated as NRLM or LM that has not yet been distributed from a
truck loading terminal or bulk terminal...". Does this mean that after June 1,2010
refineries must start dying the 500 LM, small refinery 500 ppm NRLM, and Credit 500
ppm NRLM? Will transmix processors be required to dye 500 ppm transmix derived
NRLM/heating oil? Will parties upstream of the terminal be required to dye segregated
interface derived 500 ppm NRLM/heating oil? Pipelines may be moving these products
until 2014 and in-use generated LM 500 ppm indefinitely. Does the 15 ppm NRLM need
to be dyed at the refinery at some point in the future or can it always be dyed at the
terminal? Please clarify the June 1, 2010 date in the dye requirements section.
A: D The dye provisions in § 80.520(b) do not directly require that dye be added at the
refinery gate. The dye provision establishes a presumption that fuel is highway
fuel if it is not dyed. As a result, in the past refiners have added visible evidence
of the dye to all fuel that did not meet the highway standard, so that it would not
be treated as subject to the highway standard. In the 2004 nonroadrule, EPA
dramatically limited the role that dyeing plays under the regulations, to allow for
more fungible distribution of diesel fuel. After June 1, 2010, there is no longer
any presumption that undyedfuel is highway fuel. Therefore after that date there
is no need for refiners to dye fuel to make sure it is not considered highway fuel
subject to the highway standards. At that point, EPA will rely on the designation
provisions to identify what the fuel is and what sulfur standard applies.
Prior to June 1, 2010, only a limited subset of diesel fuel must be dyed (in the
distribution system above the truck rack; fuel must still be dyed when leaving the
truck rack to meet IRS requirements) to avoid the presumption that it is highway
fuel. From the effective date of the nonroad diesel final rule (August 30, 2004)
until June 1, 2010, only heating oil and high sulfur NRLM must be dyed red at the
refinery gate to avoid being subject to the highway and nonroad sulfur standards.
Prior to August 30, 2004, all diesel fuel which did not meet the applicable
requirements for highway diesel fuel was required to be dyed red at the refinery
gate to avoid being subject to the highway standard. After June 1, 2010, there
are no EPA requirements to dye any diesel fuel at the refinery gate. Similarly,
there are no EPA requirements for diesel fuel produced downstream of the
refinery such as transmix or segregated interface-derived diesel fuel to be dyed
upstream of the terminal. In all cases, highway fuel is required to be free of
visible evidence of red dye.
Any diesel fuel which is required to contain the fuel marker solvent yellow 124
(heating oil beginning 6/1/2006 and LM diesel fuel 6/1/2010 - 5/31/2012; see §
80.510) is also required to contain visible evidence of dye solvent red 124. The
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fuel marker and associated red dye requirements apply prior to the distribution
from a truck loading terminal. The Internal Revenue Service requires that
untaxed dieselfuel (nonroad, locomotive, & marine, & heating oil) be dyed
before leaving the terminal. Thus, 15 ppm NRLM can be dyed just prior to
leaving the terminal.
1.45: D How will EPA deal with truck terminals located at a refinery? Are there any reporting
obligations under D&T (i.e., quarterly balances, etc.)? Current Q&A question 2.39
addresses the sale of another refiner's product over its own truck rack, but what about the
sale of a refiner's own product over that same truck rack?
A: D The manner in which the facility is registered will dictate reporting obligations of
the truck terminal.
If the truck terminal is registered separately from the refinery, then the refinery
must meet all of the requirements applicable to a refinery, and the truck terminal
must meet all of the D&T requirements applicable to a downstream truck
terminal. The requirements of D&T- including hand-ojfs and balance
calculations- must be reported, as appropriate, by the refinery and truck terminal.
If the truck terminal is aggregated with the refinery, then this single aggregated
facility is treated as a refinery, and must meet all of the requirements applicable
to a refinery. In this case, there would be no separate truck terminal D&T
requirement for the portion of fuel being delivered over the rack, so long as
requirements for dye/marker/taxes are satisfied. The hand-off from the truck rack
would be treated in the same way as a hand-off from a refinery. The refinery's
batch volumes and designations would be based on the hand-offs of fuel at the
point it is released from the truck terminal, as that is the point at which the
aggregated "refinery" would hand-off custody of the fuel. (See definition of
"batch " at § 80.502'(d).) In this special case, the refinery will have to provide
batch reports showing volume of marked, dyed, and/or taxed product that was
sold over the truck rack, as well as batch reports reflecting designation and
delivery volumes for any diesel fuel handed off to a downstream party separate
from the truck terminal, such as a pipeline. This will enable EPA to differentiate
between fuel that was sold over the truck rack versus fuel that was sent through
the D&T system.
1.46: D Consider the following scenario- fuel enters a pipeline at, or below, 15 ppm. At some
point in the pipeline, the fuel becomes off-spec. If this fuel is then delivered to a terminal
at that off-spec level, but is then put into a tank with fuel that is below 15 ppm, and thus
becomes 15 ppm (or less) again, how is this handled in D&T? Specifically, what do the
pipeline and terminal have to report?
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A: D In this situation, the pipeline needs to redesignate the fuel at the point it is
delivered to the next facility in the distribution system- the terminal, in this case.
The designation of the fuel by the pipeline at the point of delivery needs to
accurately reflect the sulfur level, therefore it will need to be redesignated as
something other than 15 ppm. The volume and designation of the delivered fuel
will need to be accounted for by the pipeline under its D&T requirements. For
example, if the fuel is redesignated from 15 ppm highway to 500 ppm highway,
this would need to be accounted for by the pipeline in showing compliance with
the anti-downgrading requirements. The terminal would then report a receipt of
500 ppm fuel. The terminal may redesignate that volume as 15 ppm once it
becomes 15 ppm fuel again. If the terminal 'upgrades' the fuel from 500 ppm NR
to 15 ppm HW, and delivers it as 15 ppm fuel, then the terminal will need to
account for this volume of 15 ppm fuel in showing compliance with its D&T
requirements and volume balances.
1.47: D Is there anything in the regulatory requirements that would prevent a downstream blender
from producing a batch of 15 ppm highway diesel fuel by mixing a batch of fuel
designated as 500 ppm diesel fuel (but with an actual sulfur level only slightly over 15
ppm) with a batch of fuel designated as 15 ppm (but with an actual sulfur level
considerably below 15 ppm)? Am I correct in that since no previously uncertified /
undesignated blendstocks were used by the blender, that they would not be required to
report as a refiner to EPA?
A: D There is nothing in the regulatory requirements to prevent a downstream party
from producing 15 ppm diesel fuel in the manner described. Since no previously
uncertified/undesignated blendstocks were used, the party commingling/mixing
the two fuel batches would not be required to report as a refiner to EPA.
However, the sulfur level of the resulting fuel would need to be measured, and the
fuel would need to be accurately designated based on its sulfur level. The
designation and volume of the fuel as delivered would need to be reflected in the
party's D&T requirements and volume balance calculations. If the 15 ppm and
500 ppm fuel used in the mixing operation described were both designated as
highway diesel fuel when they were received, and the resulting fuel was
designated as 15 ppm highway, there would be a neutral impact with respect to
demonstrating compliance with the motor vehicle volume balance requirements
(see section 80.599(b)). If the 500 ppm fuel used was designated as NRLM diesel
fuel, there would be a negative impact with respect to demonstrating compliance
with the motor vehicle volume balance requirements which would need to be
accounted for by the party to show compliance during the same compliance
period.
1.48: D If a parent company has wholly owned pipeline and terminal subsidiaries, can the
facilities be aggregated and reported by the parent if the facilities meet the contiguous
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facilities requirement? Can a parent report all facilities for its wholly owned subsidiaries
or must facilities be reported by legal entity?
A: D Each registered entity reports to EPA. If the parent company is the registered
entity for each of its facilities, then the parent company will report. If each
subsidiary facility is its own registered entity, then each of those entities must
report.
If the facilities are contiguous and custody is maintained by one entity (the parent
owner in this case), they may be aggregated. In that case the owner must register
as an entity, and the aggregated facility must also be registered (§ 80.597 (c) and
(d)).
1.49: D Will EPA require terminals to include language/provisions on compliance with the ULSD
rules in their contracts with tenants? (i.e., provisions that would have tenants confirm
that they understand their obligations as custodians and that they will not change the
designation of fuel stored in leased tanks.) Also, when terminals lease tanks, it would
appear that the fuel would be entirely under the control of the tenants of the leased tanks.
In enforcement, will EPA only look at the actions of the tenants, or will EPA take action
against the parent terminals?
A: D The diesel sulfur regulations do not require that terminals include language in
contracts to lessees, however terminal owners may find it useful to include such
language to ensure that lessees fully understand their obligations as tenants.
Whether or not a terminal owner includes such language in its leases, as stated in
the preamble, the terminal owner has full responsibility over leased tanks and
must ensure that its total volume balance- of all tanks within the terminal- meets
the required balance at the end of a reporting period (see § 80.601). Since the
terminal owner is the responsible party, EPA reserves the right to take any
appropriate enforcement action against the terminal owner. In addition, where
the lessees have committed a prohibited act, for example by causing the terminal
operator to commit a volume balance violation, or by distributing fuel that
violates the sulfur standard, then EPA reserves the right to take any appropriate
action against the lessees as well. As in all cases, EPA will evaluate each case
individually to determine the appropriate enforcement response.
1.50: D a) Would EPA consider allowing a terminal to be subdivided into more than one
facility for the purposes of registration under the D&T reporting and
recordkeeping requirements when the terminal owner leases some of its assets to
another entity? Under such an approach, the terminal owner and lessee(s) would
have the option of obtaining separate registrations for the respective parts of the
terminal that they control. Allowing industry this flexibility would be most
consistent with the business relationship between terminal owners and their
lessees. Unless the terminal owner and the lessee jointly agree that the lessee be
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covered under the terminal owner's registration, the terminal owner's
responsibility should end once the fuel is delivered to the lessee's storage tank.
There are currently no mechanisms by which terminal owners could receive the
necessary information from their lessees or control their lessees actions.
A: D Due to concerns that allowing multiple registrations for a single terminal
would greatly complicate EPA enforcement and compliance assurance
activities, we specified that terminals may not be subdivided for
registration purposes under the D&T system except under unique
circumstances as approved by EPA (§ 80.502(b)(5)). In most cases the
fuel goes through common piping/manifolds that are owned and operated
by the terminal owner prior to entering the leased tankage and/or after
exiting. Therefore, the terminal owner would still take custody of the fuel
and be required to report. The leased assets are typically operated by
employees of the terminal owner. Thus, it should not be unduly
burdensome for terminal owners to obtain the necessary information from
their lessees to comply with the reporting requirements under the D&T
system. The terminal owner could use contractual means to ensure that it
receives the necessary information from its lessees, and to ensure that its
lessees do not cause a violation of EPA requirements (and to recoup
potential damages should a violation occur).
Based on the above discussion, we continue to believe that it is
appropriate to preclude a terminal from being subdivided except under
unique circumstances as approved/defined by EPA. One such unique
circumstance where EPA believes it is appropriate to allow a terminal to
be subdivided is when refining activities are occurring within the terminal
by lessees, as discussed below. EPA will consider applications for the
subdivision of a terminal, or other unique circumstances, on a case-by-
case basis.
b)D Who should report in the following scenario? A terminal operator leases tankage
to another company. The lessee uses the tankage for blending purposes. The
lessee provides instructions to the terminal operator regarding tank blending, but
has the tank certified independently and does not provide the operator information
regarding the final product specification. Therefore, the terminal operator may
not have the information necessary for accurate reporting. Would EPA allow for
the subdivision of a terminal in this case?
A: D If the blending of previously undesignated blendstocks occurs in a
terminal, such blending operations are considered to be refining
activities. In such a case, one party must satisfy the refiner recordkeeping
and reporting responsibilities. If neither party met the refiner
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requirements, then both the lessee and the terminal could be liable under
the regulations for any refiner-related violation.
Where a lessee of terminal assets performs fuel blending operations that
make it a refiner, there are three different options that EPA believes
would be appropriate for addressing both the refiner and distributor D&T
responsibilities under the regulations. We have described these situations
below.
In the first option, the entity responsible for the terminal would state in its
registration form that it is also performing blending/refining activities and
would take on refiner responsibilities for the lessee's blending operations,
including the refiner responsibilities under designate and track. The
terminal entity/facility would satisfy the obligations of compliance,
reporting, and other D&T obligations for both its distribution activities
and the refining activities of the lessee. The terminal entity/facility would
then use contractual means to ensure compliance with the regulations.
While the terminal entity/facility is taking on more burden in this option,
EPA anticipates that there are a number of situations where this might be
the preferred option.
In the second option, the lessee would register as a separate facility only
for its refining operations (production of fuel from the blending of
blendstocks), and would receive a facility identification for its refining
facility. The entity responsible for the terminal would still be registered
as a distributor and would still be treated as one single entity and facility
for any volumes of previously designated fuel that the lessee merely
receives and distributes as a distributor, for purposes of downstream D&T
provisions (as in part (a), above).
The lessee, in its capacity as a refiner, would need to comply with the
D&T requirements applicable to refiners, including appropriately
designating all volumes of fuel that it produces by blending. The volume
produced would only include the volumes produced from previously
undesignated blendstocks. The lessee/refiner would be subject to all of the
refiner requirements for the fuel it produces, including batch sampling
and testing, and the 80/20 provision for highway dieselfuel. The lessee
would also have to report to EPA on the volumes of fuel that it produces
and distributes, including reporting the designation, volume, and the
recipient of the fuel. In most cases the recipient would be the terminal
entity/facility (whose manifolds and piping the fuel would go into). The
terminal entity/facility would then report volumes received from the
internal lessee/refiner (just as it would report volumes received from any
other external facility). The lessee/refiner would have to maintain
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accurate PTDsfor its deliveries of finished fuel to the terminal
entity/facility.
Where a lessee/refiner blends previously designated diesel with
undesignated blendstocks, the volume that is considered produced will just
be the additional volume added by the blendstock. Further, the properties
of the fuel (i.e., sulfur content) will be the sulfur content of the finished
blend. If the finished blend changes the sulfur content of the previously
designated fuel, this change would need to be reflected in the terminal
entity/facility's D&T volume balance calculations and documentation.
For example- if 1000 barrels of previously designated 15 ppm highway
diesel were blended with 1000 barrels of higher sulfur fuel that was not
previously certified (and the resultant volume of fuel now exceeds the 15
ppm standard), the entire 2000 barrels of blended fuel must now be
classified as 500 ppm highway diesel fuel. The lessee/refiner would only
count the newly produced fuel as 1000 barrels of 500 ppm highway diesel
fuel in its refiner D&T documents, and this volume would be reported as
fuel produced and delivered to the terminal entity/facility. The terminal
entity/facility would then report a receipt, from the lessee/refiner, of 1000
barrels of 500 ppm highway diesel fuel. Since the remaining 1000 barrels
of the blended volume was previously designated as 15 ppm highway
diesel fuel, the terminal entity/facility would treat it as a downgrade from
15 ppm highway diesel fuel to 500 ppm highway diesel fuel (and there
would be no hand-off from the lessee/refiner to the terminal entity/facility
of this portion of the resultant fuel since it was previously designated
before it was blended). The terminal entity/facility would need to account
for this downgraded volume in showing compliance with the 20%
downgrade limitation, assuming it was delivered from the terminal to
another downstream party as 5 00 ppm highway diesel fuel.
The added complexity in situations such as this may prompt the desire to
use the third option, discussed below, instead. However, this second
option may be preferred in situations where the ability to measure hand-
off volumes of previously designated diesel fuel between the terminal
entity/facility and the lessee is difficult or impossible.
In the third option, the lessee would register as a completely separate
facility. The lessee would check both "refining" and "distributing" on its
registration form, and would be responsible for both its refining
(production of fuel from blendstocks) and distribution (receiving and
distributing previously designated fuels) operations. The terminal
entity/facility would also be registered as its own facility. Assuming
common manifolds and piping (owned by the terminal entity/facility) are
coming into and out of the lessee's tankage, the lessee would report
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volumes received from and delivered to the terminal entity/facility under
the designate and track regulations. As with the second option, the new
lessee facility would be responsible for compliance with the fuel standards
and reporting to EPA as a refiner for the fuel it produces from
blendstocks. Unlike the second option, however, the lessee is also fully
responsible for compliance with the D&T volume balance requirements
and the anti-downgrading requirements as a distributor.
Anyone choosing options two or three must apply for approval. The most
appropriate way to apply is at the time of registration. For option three, a
letter should accompany the registration form, and should state the intent
to register as a separate facility within another party's terminal/on
another party's property. For EPA to allow the use of option two, a letter
from each party involved will need to accompany the registration form
indicating agreement to the responsibilities under option two. If
registration is issued, it will also be considered approval for subdivision
of a terminal (under § 80.502(b)(5)). Following registration, the lessee
will be issued an ID number that consists of the lessee's entity ID and the
terminal owner's facility ID.
As the details of situations where a lessee is performing blending
operations may differ for each case, and are often complicated, we
encourage anyone with this situation to talk with EPA prior to seeking
approval for subdivision of a terminal.
c) D Who should report if a terminal is owned by one company but operated by
another? The operator may not provide the owner detail needed to meet the
reporting requirements?
A: D The terminal owner could contract with the operator to report to EPA or
could obtain the necessary information from the operator to report
directly to EPA. In either case, the terminal owner would be the
registered entity, and is the party responsible for compliance. However,
in a situation where a terminal is completely operated by a lessee for the
lessee 's benefit only, we would allow the lessee to register the facility (or
facilities) and it would be responsible for all associated recordkeeping
and reporting.
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2.D Handling/Downgrading Issues
2.1: D As we understand it, the rule provides that interface/transmix may be sold as heating oil
or high-sulfur NRLM from June 1, 2007 through May 31, 2010. During at least a portion
of that time period, the sulfur standard for NRLM will be 500 ppm. Can the above-500
ppm transmix be blended into NRLM that has a sulfur content of 500 ppm or less? If so,
what happens if the blending causes the sulfur content of the entire tank to exceed 500
ppm?
A: D Blending of greater than 500 ppm NRLM fuel with 500 ppm NRLM fuel is
allowed. However, the entity performing the blending takes on the liability for
the blend meeting its designation. If the resulting blend is greater than 500 ppm,
then the entire batch of fuel must be designated as high sulfur die sel fuel. This
option is limited in certain cases by the volume balance requirements, which is
based on a comparison of the amount of high sulfur NRLM received to the
amount of high sulfur NRLM delivered.
2.2: D If the two products mentioned in question 2.1, above, cannot be blended, do the
regulations require the high-sulfur transmix to be loaded across a separate rack line and
to be labeled differently on the bill of lading?
A: D As discussed in 2.1, in many cases they can be blended. However, if they are not,
they would have different designations and require distinct product transfer
documents.
2.3: D How will Minnesota B2 (2% biodiesel) be treated under D&T?
A: D Minnesota B2 is die sel fuel, and is therefore subject to all of the requirements of
dieselfuel. Biodiesel must comply with the same sulfur specification applicable
to die sel fuel from any other source. If sold as ULSD or blended with ULSDfor
later sale as ULSD, the biodiesel would be required to meet the 15 ppm sulfur
specification applicable to ULSD. The terminal would be subject to presumptive
liability if their addition of biodiesel to ULSD caused the 15 ppm sulfur standard
to be exceeded.
2.4: D What is the terminal compliance date? August 1, 2006?
A: D The terminal compliance date for highway dieselfuel is July 15, 2006 for all fuel
they designate as 15 ppm dieselfuel.
2.5: D When do downgrade limitation dates start for pipelines?
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A: D Anti-downgrade limitations begin Oct 1, 2006for all entities in the distribution
system.
2.6: D What requirements are there for clean trucks? Will trucks be dedicated to ULSD service?
This will have major impact on where testing occurs.
A: D There are no EPA requirements to use dedicated tank trucks to transport ULSD.
It is the responsibility of the tank truck operator to ensure that whatever
contamination that might take place while the ULSD is in the operator's custody
does not cause the 15 ppm cap on sulfur content to be exceeded. Additional
quality control measures may be needed to limit sulfur contamination if an
operator chooses to use a tank truck compartment to alternately transport ULSD
and high sulfur products.
2.7: D What limitations, if any, are there on the marketing of transmix that has jet or exempted
product?
A: D The special provisions applicable to the sale of products produced by a transmix
processor using transmix as the feedstock are applicable regardless of the
composition of the transmix. As a result of common pipeline batch sequencing,
we anticipate that most transmix will contain some jet fuel and in certain areas
heating oil. From June 1, 2006 through May 31, 2010, 500 ppm dieselfuel
produced by processing transmix may be designated as highway dieselfuel and
sold into the highway diesel market (40 CFR 80.513(a)). This flexibility applies
to facilities that produce dieselfuel by processing transmix by distillation or
other refining processes, but do not produce dieselfuel by processing crude oil.
This flexibility only applies to the volume of diesel fuel produced by a transmix
processor by processing transmix, and does not apply to any diesel fuel produced
by the blending of blendstocks.
2.8: D Can a transmix processor produce 500 ppm diesel fuel for sale into the highway diesel
market after June 1, 2006? May the transmix processor blend the fuel produced through
the processing of transmix with a finished diesel fuel produced by a refiner (meeting a 15
ppm or 500 ppm sulfur cap) in order to ensure production of a final fuel blend that meets
a 500 ppm sulfur cap for sale into the highway diesel pool? Without the ability to
conduct such blending, the diesel fuel that transmix processors produce from transmix
may not always meet a 500 ppm sulfur specification. This may limit the market for
transmix-derived diesel fuel.
A:U In the case described in the question, the transmix processor could designate and
sell all of the 500 ppm fuel volume produced by blending processed transmix and
500 ppm dieselfuel into the highway diesel market, provided that the finished 500
ppm dieselfuel used for blending had already been certified by another refiner
and designated as highway dieselfuel. If the finished dieselfuel used for
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blending was designated as No. 1 or No. 2 15 ppm highway dieselfuel, then all of
the resulting 500 ppm dieselfuel could also be sold into the highway diesel
market. However, the anti-downgrading requirements would apply to any No. 2
15 ppm highway dieselfuel used for blending. If the finished fuel used for
blending was designated as something other than 500 ppm or 15 ppm highway
dieselfuel, then the special provisions described above only apply to that fraction
of the volume of the final fuel blend derived from transmix. For example: If
80,000 gallons of transmix was blended with 20,000 gallons of previously
certified 500 ppm diesel fuel designated as nonroad, locomotive, and marine
(NRLM) dieselfuel, then only 80,000 gallons of the finished fuel blend could be
designated as 500 ppm highway dieselfuel. The remaining 20,000 gallons could
be redesignated as NRLM diesel fuel (or heating oil). If the transmix was blended
with a blendstock, and not previously designated fuel, then that fraction of the
finished blend attributable to the blendstock would be subject to the standards
applicable to refiners (e.g. 80/20).
We believe that the above discussion addresses the questioner's concern about
the ability to manufacture 500 ppm diesel fuel from transmix. Furthermore, there
will be outlets for diesel fuel produced by transmix processors that does not meet
a 500 ppm sulfur specification during the time period when the highway diesel
produced by transmix processors is subject to a 500 ppm sulfur specification.
Such fuel may be sold into the NRLM market or into the heating oil market.
2.9: D Will a terminal have to wait for lab results before it can ship product to the rack or
another pipeline?
A: D A terminal acting merely as a distributor or carrier is not required to wait for lab
results before shipping dieselfuel. The regulations provide that, like other
downstream parties, to establish a defense to presumptive liability a terminal
must have a quality assurance program that includes sampling and testing, as one
element of its defense to presumptive liability.
2.10: D Very few truckstop operators have the ability to carry two grades of diesel fuel. The
industry is not likely to install new tanks/lines/pumps for a four year phase-in period. Is
there a minimum amount of each product that a marketer must carry and sell to qualify
for the 20% downgrade exemption?
A: D If a retailer makes 15 ppm dieselfuel available to its customers in a manner
consistent with the way it markets other fuels, then the retailer is not subject to
the anti-downgrading requirements for highway dieselfuel. Typically, this would
mean that the retailer would need to provide a fuel pump (or, pumps) and have
sufficient volumes of 15 ppm highway dieselfuel available so that end-users
wishing to purchase 15 ppm dieselfuel do not find it significantly more difficult to
refuel than customers who wish to refuel with 500 ppm dieselfuel.
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2.11: D At retail locations, will the diesel dispenser have a different size nozzle to prevent a
customer from misfueling?
A: D EPA did not require unique dispenser nozzles for 15 ppm diesel fuel. This is
something we considered on several occasions, but concluded, after discussions
with the relevant stakeholders that misfueling would not likely be significant
enough to justify the cost and burden of the vehicle and fuel pump changes. The
nonroad diesel rule includes labeling requirements for fuel dispensers and
vehicles to help prevent misfueling. The fuel dispenser labeling requirements
finalized in the highway diesel rule were super ceded by those in the nonroad
diesel rule (see 40 CFR 80.570, 80.571, 80.572, 80.573, & 80.574).
2.12: From an end-user viewpoint (trucking company):
a) What is the liability in the event of misfueling by a driver?
b) What effect does running ULSD in older equipment have on the engine?
c) What is the impact of running 500 ppm fuel in a new (2007+) engine?
d) Will companies with bulk fuel for use in their own equipment be subject to
testing?
e) Will existing tanks currently containing 500 ppm fuel be suitable for storage of
ULSD?
will tanks need to be purged and cleaned
will company need to install new tanks to segregate fuels until 500 ppm is
gone?
A: D a) See question 12.1. The trucking company is liable for misfueling but will
be able to meet defense if it can demonstrate that the violation was not
caused by the fleet operator or its employees (e.g., fueled from a retail
pump labeled as containing the appropriate fuel for the vehicle) and, if it
is from the company's own pump, it also needs to show PTDs account for
the fuel and show it was compliant.
b) D Generally, ULSD will be beneficial to engine operation and durability.
The only known concern is with the lubricity of ULSD, which will be
ensured through the use of lubricity additives to the fuel. ASTMhas
adopted a lubricity spec for diesel fuel to assure proper fuel lubricity.
c) D If a new (MY 200 7 or later) truck is misfueled once, it will have
significantly higher PM emissions during operation on that fuel, but there
should not be any significant long-term emissions or engine durability
concerns as long as the vehicle is then fueled with the proper fuel.
Constant misfueling would damage the after treatment/emission controls
on these newer vehicles.
d) D EPA will inspect wholesale purchaser-consumer facilities and take
samples from fuel pump stands and from vehicle fuel propulsion tanks.
e) ULSD can be stored in tanks currently storing other fuels, including 500
ppm fuel and high sulfur fuel. However, care must be taken when
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transitioning the tank to avoid contamination of the ULSD. If a rapid
turnover is desired, purging and cleaning the tank is an option, however it
is not required.
2.13: D It could take several loads of 15 ppm to flush out a retail tank, and this could take several
weeks. Is there a provision for downgrading the product during this transition?
A: D Yes. During the start of the program, the anti-downgrading provisions do not
start until October 1, 2006 (see § 80.527(c)(3)), allowing for a normal orderly
transition. Even after October 1, there is an allowance for 20% to be
downgraded. Since contamination at retail after the transition is expected to be
minimal, 20% over the course of the entire compliance period should be
sufficient.
2.14: D Regarding the 2 ppm adjustment factor- this applies downstream of the refinery and the
import location. Assuming a terminal has a single ULSD storage tank that receives
product from a refinery and also receives ULSD imports, both receipts would be
designated as 15 ppm on-highway diesel and would otherwise be fungible. Would this
tank be a downstream tank or an import tank? Would the 2 ppm adjustment factor apply
to this tank or not?
A:U As in other fuels programs, tanks downstream from the certification tank will
generally be considered "downstream " tanks and will be eligible for the 2 ppm
test result adjustment, per § 80.580(d). However, this would not be the case if a
company uses a tank as a downstream tank for refinery purposes and also uses it
as a certification tank for its imports. In such a case the tank would not be
eligible for the 2 ppm adjustment.
2.15: D What are the recordkeeping issues related to biodiesel used as lubricity additives for
ULSD?
A: D Recordkeeping in this case will be the same as any other blending component. If
the biodiesel provider designates the fuel as MVNRLM, then he serves as the
refiner. If the provider does not designate, then the blender serves as the refiner.
2.16: D In order to be in compliance with the lubricity requirements of the ASTM D 975 diesel
fuel specification, refineries will have to use lubricity additives, some of which may
contain sulfur. Most, if not all, pipelines will likely prohibit the use of these additives in
product that they transport. Therefore, these additives will be added to diesel fuel
downstream of the pipelines (either into tanks at the terminal or at the rack). Can
volumetric calculations be used to account for the sulfur content of these additives?
A: D No, volumetric calculations cannot be used to account for the sulfur content of
these additives.
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2.17: D During the initial phase, I deliver 15 ppm fuel to a customer. The product is
contaminated (and, as a result, no longer meets the 15 ppm standard) while in his
custody. The customer then ships the fuel back to me due to its contamination. Upon
receipt of the fuel, I reclassify it as 500 ppm- does this count against my 20%
downgrade?
A: D The owner of the facility where the contamination occurs is responsible for
redesignating off-spec fuel, and for accounting for it in its compliance
calculations. The product that is shipped back to your facility must be
appropriately designated and the product transfer document must reflect this
designation. When the product is returned to you, it should already be designated
as 500 ppm (since the party that caused the contamination is responsible for
redesignating fuel that no longer meets the applicable standard), so you would
not have to reclassify/redesignate the fuel and the downgrade would not count
against your balance.
2.18: D 50,000 bbls of 15 ppm is discharged from an on-spec vessel. On the way to the tank, it
became contaminated via pipeline. The receiving tank had 20,000 bbls in it, and the
50,000 bbls of contaminated fuel is put on top of the 20,000 bbls. What is charged
against the terminal's 20% rule if it is redesignated as 500 ppm highway fuel?
A: D Volumes are calculated based on receipts and deliveries for each custody holder.
In this hypothetical situation, there would be 70,000 bbls of fuel designated as 15
ppm highway fuel received by the terminal, but 70,000 bbls of 500 ppm highway
fuel delivered. (See 40 C.F.R. § 80.527(d).) This assumes that the 50,000 bbls of
fuel was in the custody of the terminal when the contamination occurred in
piping.
2.19: D Must diesel fuel treated as blendstock (DTAB) be off-spec, or can it be on-spec and
"treated" as blendstock?
A: D The DTAB provisions of § 80.512 may be used regardless of whether the diesel
fuel is "off-spec."
2.20: D The 20 percent downgrade restriction in the highway rule is going to be extremely tight
the second half of 2006 in large part due to refining production only being required 3
months in advance of retail sales and the first year being a partial year for the downgrade
standard and, most critically, this is the first year for tank transition with a lot of higher
sulfur distillate in the system. Many are planning on just in time delivery of ULSD from
the refineries which means transportation will be faced with considerable downgrade
during the transition period that limit downgrade to the on-road market to 20 percent.
While no retailer is required to sell ULSD, anyone that handles ULSD may not
downgrade more than 20% of the net volume received in any year into the on-road pool.
This is likely to be a problem, especially for those moving small batch volumes. EPA
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needs to delay the start date of the downgrade limit period or get rid of it all together for
this first year. Alternative, if all else fails, they should group the period with 2007.
A:U As finalized in the nonroadrule, the start of the first compliance period for anti-
downgradingwas delayed to Oct 1, 2006 to allow for the expected downgrade
during the initial transition to ULSD. The compliance period was also
lengthened to end on May 31, 2007, allowing a longer period over which
compliance can be averaged.
2.21: D If a pipeline does not have sufficient storage capacity for all grades of ULSD and
exempted product, will the pipeline be allowed to blend at the terminal to prevent
outages?
A: D Yes, pipelines/terminals may blend different grades of fuel subject to the anti-
downgrading limitations on highway ULSD and volume balance requirements for
highway diesel fuel, nonroad diesel fuel, and high sulfur NRLM as applicable (see
section 80.599).
2.22: D Please comment on the possibility of elimination of the red dye requirement for off-road
diesel with the introduction of 15 ppm highway fuel and allowing 500 ppm "non-road"
diesel to be shipped undyed as it leaves refining gate (to allow the distributors system to
accommodate 3 grades of diesel)- please confirm that off-road diesel meeting the 500
ppm requirements may be commingled with 500 ppm on-road diesel? Dye removal, and
the ability to commingle will greatly reduce the strains on limited tankage and will add
needed flexibility, thereby reducing potential distribution and supply disruptions. Dyeing
of "non-road" diesel would take place at terminal rack. A terminal could then handle 15
ppm highway, 500 ppm highway, and 500 ppm nonroad with two tanks common in
terminals today. It would also help pipeline companies. Also, can 500 ppm off-road
diesel be redesignated as 500 ppm on-road diesel? If so, are there any limits or special
testing or documentation requirements?
A: D While it does not eliminate the red dye requirement for nonroad diesel fuel, the
nonroad diesel rule's designate and track provisions (D&T) allow diesel fuel with
similar sulfur levels to be commingled and fungibly shipped up to the point of
distribution from a terminal, where NRLM must then be dyed. 500 ppm diesel
fuel designated as NRLM can be re-designated as 500 ppm highway diesel, but it
is subject to the limitations stated in §§ 80.598 and 80.599.
2.23: D Could a fleet operator that owns and uses only pre-model year 2007 motor vehicles
indefinitely use 500 ppm highway diesel fuel? Even after 2010? What if the fleet
operator also produces his own motor vehicle diesel fuel?
A: D The regulations at § 80.500(d)(4) state that beginning December 1, 2010 the
sulfur content standard of § 80.520(c) (i.e., the 500 ppm sulfur standard) shall no
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longer apply to any motor vehicle dieselfuel. After, December 1, 2010 all motor
vehicle dieselfuel must be 15 ppm or less. The regulations at § 80.530(b) state
that after May 31, 2010, no refiner or importer may produce or import motor
vehicle diesel fuel subject to the 500 ppm sulfur content standard.
2.24: D A refiner certifies all of its kerosene as dual Jet/No. 1 diesel at 15 ppm, and counts that
volume as 15 ppm motor vehicle diesel fuel and accounts for it in the 80/20 TCO. If all
the kerosene is then "downgraded" to Jet fuel, so none of it is available as 15 ppm motor
vehicle diesel fuel, is the refiner still complying with the 80/20 rule even though none of
the fuel is available as onroad diesel?
A: D If a refinery designates kerosene as motor vehicle dieselfuel, then sells the
kerosene as commercial jet fuel, then the reclassified volume of kerosene is not
subject to any downgrading limitation, and does not impact compliance with the
80% 15 ppm diesel fuel production requirement for the Temporary Compliance
Option.
2.25: D Terminal operators who import product from abroad are in most instances responsible for
compliance with the highway diesel fuel rule. These importers understand that if a cargo
of on-highway diesel fuel enters the U.S. and does not comply with the 15 ppm standard,
they can choose to blend the product to specification if it is possible. These importers
would then designate the product as compliant when it leaves the terminal gate. Would
EPA please confirm this interpretation.
A: D The nonroad diesel rule does contain a provision allowing importers to blend
near-compliant dieselfuel containing slightly more than 15 ppm sulfur with diesel
fuel containing less than 15 ppm sulfur to produce a compliant blend containing
less than 15 ppm sulfur- this fuel may then be designated as "dieselfuel treated
as blendstock", or DTAB (see § 80.512).
2.26: D If a terminal imports off-spec kerosene (higher than 15 ppm), terminal operators are
planning to blend the kerosene with diesel fuel so that the ultimate diesel fuel leaving the
terminal gate and entering into commerce meets the 15 ppm standard. Would EPA
please confirm that this process is permissible for an importer?
A: D The regulations at § 80.525 (d) state that kerosene that a kerosene blender adds,
or intends to add, to motor vehicle dieselfuel subject to the 15 ppm sulfur
standard must meet the 15 ppm sulfur standard. However, under § 80.521 (b),
kerosene containing more than 15 ppm sulfur may be blended into motor vehicle
dieselfuel at concentrations of one volume percent or less, provided the sulfur
concentration of the resulting blend does not exceed the 15 ppm sulfur standard.
The accompanying PTD must also accurately reflect this.
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2.27: D Refinery shipments by pipeline often occur with the producing company retaining title to
a volume of product in the pipeline, while the pipeline actually has custody of the
product. In this instance, do both the title holder and the custody holder have separate
20% downgrading potentials, or do they share a common 20% downgrading potential?
How does one determine who accepts responsibility and reporting for a downgrade that
may occur, such as pipeline interface, when the producing company may have title to the
product, but the pipeline has custody?
A: D As clarified in the nonroadrule regulations, the 20percent downgrade limitation
applies separately to each facility that has custody of the fuel when it is
downgraded. The downgrade provision allows each party in the distribution
system that is subject to it to downgrade a maximum of 20 percent of the highway
diesel fuel for which it has custody on an annual basis. The downgrade limitation
was incorporated to protect the availability of 15 ppm diesel fuel at the beginning
of the highway diesel program. Actual contamination and downgrade is expected
to be far less than 20%. However, 20% was selected to cover even the worst case
scenario.
2.28: D In situations where custody changes to/from related entities (such as Company A refinery
to Company A Pipeline to Company A Marketing), are these related entities each entitled
to a 20% downgrade? Or, since they are related, are they viewed as one entity and
therefore entitled to one overall 20% downgrade?
A: D As defined in the regulations with the nonroad rule, a downgrade is accounted for
on a facility-by-facility basis. Flexibility was included in the rule to allow
aggregation of facilities at industry's discretion subject to certain restrictions
(see § 80.502 (b).
2.29: D A downgrade occurs only when the designation of a motor vehicle diesel fuel is changed
from 15 ppm to 500 ppm. A change in designation to any other product, such as jet fuel,
home heating oil, No. 4 diesel, is not a downgrade?
A:U Correct. For the purposes of these requirements, "downgrade" refers to
redesignating 15 ppm motor vehicle diesel fuel to 500 ppm motor vehicle diesel
fuel. (See § 80.527(a)). Changing the designation of 15ppm motor vehicle diesel
fuel to any fuel that is not motor vehicle diesel fuel is not a downgrade, and is not
volume limited.
2.30: D A "retailer" is limited to a single 20% downgrade of 15 ppm highway diesel fuel to 500
ppm highway diesel fuel unless the "retailer" offers for sale both 15 ppm and 500 ppm
highway diesel fuels? Is the term "retailer" intended to apply on the individual service
station or truck stop level, or does "retailer" potentially apply to a grouping of related
retail outlets, such that if any one of the outlets offers 15 ppm diesel fuel, all outlets could
freely downgrade 15 ppm highway diesel fuel to 500 ppm highway diesel fuel?
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A: D Since the downgrade provision was intended to protect availability of 15 ppm
highway dieselfuel, a retailer or wholesale purchaser-consumer who sells, offers
for sale, or dispenses either only 15 ppm motor vehicle dieselfuel or 15 ppm and
500 ppm simultaneously throughout the calender year is exempt from the 20
percent downgrading limit. A retailer or wholesale purchaser-consumer who
does not sell, offer for sale, or dispense 15 ppm motor vehicle dieselfuel can
downgrade 15 ppm diesel in an amount no greater than 20 percent of the total
volume of motor vehicle dieselfuel it sells, offers for sale or dispenses annually.
The limitation applies separately at each facility. Only contiguous facilities can
be aggregated.
2.31: D We understand that during the period the temporary compliance option is in effect, a
party will base compliance with the 20% downgrade requirement on the incoming and
outgoing PTD records. Is the "incoming PTD record" reflective of the bbls input onto a
pipeline or the bbls received at a terminal?
A: D These provisions were clarified in the regulations finalized with the nonroad rule.
Specific answers can be found at § 80.599 (e). Calculations are based in all
cases on volumes received into the facility and volumes delivered.
2.32: D In the situation where a refiner owns and operates a proprietary pipeline, can 20% of the
pipeline movements be downgraded as provided by § 80.527 (c)? If a third party
operates the pipeline, can 20% of the pipeline movements be downgraded as provided in
§ 80.527(c)?
A: D As long as the pipeline is registered as a separate facility, the anti-downgrading
limitation applies to it regardless of ownership. If the proprietary pipeline were
aggregated into the same facility as the refinery, then the anti-downgrading
regulations would not longer apply. Rather, the refiner's production would be
based on the volumes delivered from the pipeline.
2.33:D If a refiner annually ships 100 units of diesel (20 units of 500 ppm diesel, 80 units of 15
ppm diesel) and the pipeline moves 3 units to 500 ppm diesel as interface, the terminal
receives 23 units of 500 ppm diesel and 77 units of 15 ppm diesel fuel. Is the terminal
now allowed to downgrade 16 units (20% of 80 units) or 15.4 units (20% of 77 units)?
A: D Each party in the distribution system is subject to the 20percent downgrade
limitation based on the amount of 15 ppm fuel for which it has custody on an
annual basis. Therefore, if the terminal only receives 77 units of 15 ppm sulfur
fuel. It may downgrade up to 20 percent of the 77 units of 15 ppm fuel for which
it has received custody to 500 ppm highway dieselfuel.
2.34: D Is there some limitation for how long or when a retailer must sell the 15 ppm highway
diesel before they would fall under § 80.527(e)(2) as opposed to § 80.527(e)(l)?
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A: D Retailers or wholesale purchaser-consumers who sell only 500 ppm motor vehicle
dieselfuel are subject to a downgrade limitation such that a maximum of 20
percent of the total volume of motor vehicle dieselfuel that they sell on an annual
basis can be composed of downgraded 15 ppm fuel. Under § 80.527(e)(l),
retailers or wholesale purchaser-consumers who sell, offer for sale, or dispense
15 ppm motor vehicle dieselfuel are exempt from the 20 percent downgrade
restriction. This includes parties who sell only 15 ppm, or sell both 15 ppm and
500 ppm simultaneously.
To best promote the purpose of the downgrade requirements, which is to account
for contamination without interfering with widespread availability of 15 ppm
highway dieselfuel, the exemption only applies to retailers or wholesale
purchase-consumers that sell, offer for sale, or dispense 15 ppm fuel continuously
throughout the year beginning January 1 (or for 2006, September 1).
"Continuously" here is meant to include normal business practices, including
short shut downs for repairs, or delays in sales based on delivery problems. If at
any time during an annual compliance period (calendar year) a retailer or
wholesale purchaser-consumer ceases to sell 15 ppm, he/she would be subject to
the 20 percent downgrade restriction of § 80.527 (c) over the remaining portion of
the compliance period.
2.35: D § 80.527 restricts the flexibility of all parties in the 15 ppm highway diesel fuel
distribution system to downgrade 15 ppm highway diesel fuel to other classifications. Is
it correct that retailers can choose to downgrade all, or a portion, of the 15 ppm diesel
fuel delivered, provided it is properly labeled and sold?
A: D The downgrade limitation was incorporated into the highway diesel program to
protect the availability of 15 ppm highway dieselfuel at the beginning of the
program. If distributors and retailers purchased 15 ppm highway dieselfuel in
large quantities and sold it as, or mixed it with 500 ppm fuel, assurance of the
availability of 15 ppm highway dieselfuel would be compromised. If retailers are
selling only 15 ppm highway dieselfuel, they are by definition not selling 500
ppm fuel and the provisions do not apply. If retailers are simultaneously selling
both 15 ppm and 500 ppm highway diesel, they are still satisfying the need for 15
ppm availability and thus, we chose not to apply the downgrade limitation to them
as well. Only retailers who are not selling any 15 ppm highway dieselfuel (that
is they are only selling 500 ppm fuel) are subject to the downgrade provisions
such that of the total volume of motor vehicle dieselfuel that they sell in a year,
only 20 percent of it may come from 15 ppm supplies.
2.36: D The rule states that 15 ppm highway diesel fuel found in violation of the 15 ppm standard
will be credited toward the 20% downgrade volume allowance. Could this fuel be
downgraded to off-road usage and not count toward the 20% downgrade allowance?
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A: D If fuel originally designated as 15 ppm motor vehicle dieselfuel subsequently
does not meet the 15 ppm standard, it can be either: 1) redesignated as 500 ppm
and counted toward the 20 percent downgrade limit for 500 ppm motor vehicle
dieselfuel, or 2) redesignated as NRLM dieselfuel (in unlimited amounts).
2.37: D Could 500 ppm highway diesel fuel in excess of the 20% allowable 15 ppm highway
diesel fuel downgrade be shipped back to a refiner and avoid a determination that the
downgrading entity is out of compliance?
A: D Compliance is on a facility-by-facility basis. The regulated parties must have
redesignated the excess downgraded 15 ppm highway dieselfuel as something
other than 500ppm highway dieselfuel to avoid exceeding the 20% downgrading
limit. If it is downgraded and redesignated as 5 00 ppm highway dieselfuel, then it
is a downgrade, even if it is shipped back to the refiner. If it is not re-designated
as 500 ppm highway fuel, then it would not count against the downgrade limit.
Compliance with the downgrading requirements is on an annual calendar year
basis. Any regulated party downstream of the refinery gate may downgrade more
or less than 20% of any batch as long as compliance with the 20% downgrade
limit is met at the end of the year.
2.38: D To allow for the learning curve necessary in a period of transition, would EPA consider a
delay in implementing the 20% downgrade rule for pipelines and terminals during the
time the distribution system is being converted to 15 ppm diesel fuel, perhaps up until
October 1, 2006, recognizing that distributors will have every incentive to minimize the
downgrade of 15 ppm diesel fuel given the anticipated product price differential?
A: D As amended in the nonroad diesel regulations, §80.52 7(c) (3) states that the anti-
downgradingprovisions begin on October 1, 2006.
2.39: D Can a small refiner who must produce 100% 15 ppm motor vehicle diesel fuel sell
downgraded 500 ppm fuel at its refining truck loading rack?
A: D The nonroad rule modified these provisions to define a refiner's production as the
volume delivered to the next entity. To allow for downgrade in the handoff, the
production requirement was modified to 95 percent. (This is discussed in the
preamble, but was inadvertently left out of the regulations. This error was
corrected in a technical amendment to the regulations (which can be found on
EPA 's web site at: http://www.epa.gov/otaq/regs/fuels/diesel/diesel.htmitregs.
July 7, 2005).) Any fuel produced and certified by another refiner can always be
brought in and sold over a refiner's rack. The refiner in this situation must also
report and maintain records as a fuel distributor under the designate and track
regulations.
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2.40: D There has been discussion on the "downgrading" provisions. What about upgrading? For
example can a terminal operator, marketer or third party earn and sell credits for
"upgrading" V500 to VI5? We assume that these do not employ any fractionators, and
are not "refiners".
A: D Only refiners and importers can generate credits per the regulations at § 80.531.
2.41: D If both 15 ppm and 500 ppm on-road diesel are both available at a terminal [facility
selling wholesale by the transport] is the terminal restricted to downgrading no more than
20% of its 15 ppm onroad diesel to 500 ppm onroad diesel?
A: D Yes. The regulations at § 80.527 (c) state that per sons who sell, offer for sale,
dispense, supply, store or transport diesel fuel may not downgrade a total of more
than 20% of the motor vehicle diesel fuel (by volume) that is subject to the 15 ppm
sulfur standard of § 80.520(a)(l) while such person has custody of such fuel.
Calculations to demonstrate compliance are found in § 80.599 (e).
2.42: D In doing my quality assurance check, I find that my supplier has given me 15 ppm
because he was out of 500 ppm. Can I upgrade the product that the PTD's say is 500 to
15?
A: D Yes.
2.43: D Consider the following issue - as a batch of fuel moves down the pipeline, volumes are
stripped off of the heart of the batch, since the interface at best stays the same or more
likely will grow in length as the batch moves down the pipeline, the volume of material
that must be downgraded at the end of the pipeline as a percent of the remaining batch
volume will be much larger than at facilities upstream on the pipeline. The concern is that
facilities at the end of the pipeline may have more difficulty in coping with the 20% limit
on down grading, on a facility-by-facility basis.
A: D The 20% downgrade limitation applies separately to each facility in the
distribution system. Facilities at the end of the distribution system only need to
comply based on the volumes of 15 ppm fuel that they receive. Any downgrade
that occurs upstream does not enter into their compliance calculations.
2.44: D Terminals have no financial incentive to downgrade product from 15 ppm to 500 ppm.
However, there is concern about contamination and the 20 percent downgrade limitation,
particularly within the first several months following implementation. Will EPA issue a
technical amendment that would allow the industry to downgrade the 15 ppm product
without limitation, or at least remove the limitation for the first six months of the
program.
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A: D EPA believes we have allowed terminals adequate lead time to identify and
correct potential sources of contamination for 15 ppm diesel. The 20%
downgrade limitation is on an annual basis, so if a terminal has to downgrade
more than 20% of its 15 ppm diesel at the beginning of the program, it has the
opportunity to compensate for downgrades greater than 20% by downgrading
less of its 15 ppm highway diesel later in the year. Further, the anti-downgrading
provisions do not begin until October 1, 2006, in order to allow for a normal
transition at the start of the program.
2.45: D Question 2.35 deals with restrictions on the flexibility of all parties to downgrade 15 ppm
motor vehicle diesel fuel to other classifications. If a small terminal has its supply of 15
ppm fuel contaminated with 500 ppm fuel, how much can the marketer use of that
contaminated fuel that the terminal has downgraded to 500 ppm? Our interpretation of
the rule is that the marketer handling 500 ppm can get only 20% of his 500 ppm supply
from downgraded 15 ppm. Is this correct?
A: D The regulations at § 80.527(c)(3) state that the 20% downgrading limitation shall
be on an annual or compliance period basis. The terminal may sell all of the
contaminated batch as 500 ppm fuel provided that the terminal's total annual
downgrade percentage for the compliance period does not exceed 20%. This fuel
would now be designated a 500 ppm by the terminal. As such, anti-downgrading
provisions would no longer apply to it for any marketers that received it.
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3.D Analytics R&D Issues/Test Methods
3.1: What rounding convention will be used for sulfur content tested by EPA?
A:U The sulfur specification is 15 ppm. Standard rounding conventions apply. For
example, a measurement of 15.49 would be rounded down to 15 ppm.
3.2: D The regulations at section 80.580(c)(l) include the following: "...is correlated with the
appropriate method specified in paragraph (a)(2) of this section.'" Is "(a)(2)" incorrect?
Should it be "(b)(l)" which references ASTM D 6428-99?
A: D Yes, the current citation in the regulations is incorrect. It should be "(b)(l). "
This error was corrected in a technical amendment to the regulations (which can
be found on EPA 's web site at:
http://www.epa.gov/otaq/regs/fuels/diesel/diesel.htm#regs, July 7, 2005).
3.3: D The regulations at section 80.580(c)(l) include the following: "...is correlated with the
appropriate method specified in paragraph (a)(2)(ii) of this section." Is "(a)(2)(ii)"
incorrect? Should it be "(b)(2)" which references ASTM D 2622-03?
A: D Yes, the current citation in the regulations is incorrect. It should be "(b)(2). "
This error was corrected in a technical amendment to the regulations (which can
be found on EPA 's web site at:
http://www.epa.gov/otaq/regs/fuels/diesel/diesel.htm#regs, July 7, 2005).
3.4: D ASTM and ISO frequently update their test methods; must an EPA approved method be
resubmitted to the EPA for approval if the modifications to the test methods (that are
made by ASTM and ISO) are minor and have no significant impact on the accuracy and
precision of the method?
A. D All EPA approvals are specific not only to a given test method and laboratory,
but also to a particular version of that test method. Thus, if ASTM or ISO
released a revised version of a test method, any EPA approvals for previous
versions of that same test method would remain valid and laboratories could
continue to use the previous version. If the laboratory intended to use the revised
version of the test method, formal approval must be sought from EPA. EPA is
exploring procedures in the context of the current regulations under which a
revision to a specific test method could be deemed inconsequential to its accuracy
and precision. If such a procedure can be developed, EPA may be able to permit
the qualification for the old version of a test method to apply also to the new
version of that test method.
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3.5: D Must a third party independent lab be "registered" with the EPA to get test methods
approved?
A: D Under §§ 80.584 and 80.585, each lab that will be testing fuel for compliance
with the diesel regulations must obtain EPA approval on a laboratory-specific
basis. The information required for approval is somewhat different depending on
whether the test method is one that has been approved by a voluntary consensus-
based standards body. However, there is no independent laboratory registration
per se, as there is under the RFG program under § 80.65.
3.6: D Are the EPA approved test methods for diesel automatically approved for use on
kerosene or heating oils, or must the test method be approved for each product?
A: D EPA does not require testing on heating oil. Consequently, there is no need to
seek approval from EPA regarding the method used for the testing of heating oil
properties. Any testing on#l diesel fuel (kerosene) used in highway diesel or
diesel nonroad, locomotive, or marine engines required by EPA must be
conducted using an approved test method. The test methods approved by EPA for
testing of the properties of #2 diesel fuel are also applicable for the testing of#l
diesel fuel.
3.7: D Under the performance-based test method approach adopted in the non-road diesel sulfur
rule, there is no designated sulfur test method as has been specified in previous
regulations. Methods developed by consensus bodies, as well as methods not yet
approved by a consensus body, qualify for approval provided they meet the specified
performance criteria, as well as the recordkeeping and reporting requirements for quality
control purposes. The rule specifies the precision and accuracy criteria that a laboratory
must demonstrate in order to qualify its particular method of choice. API believes that
the EPA enforcement lab should be required to meet or exceed the precision and
accuracy criteria imposed on industry and that this should be a prerequisite to pursuing
any enforcement action on a fuel parameter. Does the EPA Ann Arbor laboratory also
need to demonstrate that its sulfur method(s) of choice meets the precision and accuracy
criteria in the rule and maintain records for quality control purposes?
A: D The EPA lab in Ann Arbor currently performs testing of fuel samples for
enforcement purposes. EPA fully anticipates that its laboratory will have the
capability to run several different test methods meeting the precision and
accuracy criteria specified in the rule. However, whether we meet these criteria
or not, is not a "prerequisite " to pursuing any enforcement action. Per § 80.611,
evidence can be used in assessing whether a violation has occurred. Uncertainty
in our own test results is just one of the factors that would go into any decision to
take enforcement action.
3.8: D Will EPA test terminals or retail outlets?
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A: D EPA conducts sampling and testing of fuel at all points in the distribution system.
3.9: D A batch of diesel is produced, sampled and tested on the last day of the reporting period
but it is not shipped for several days until the next reporting period. With gasoline, the
production date is used as the reporting basis. Should the diesel batch be reported as part
of the earlier compliance period or alternatively as the "production" date which is the
date of shipment from the refinery?
A:U Under the ULSD regulations as finalized in the nonroadrule, a batch of diesel
fuel is defined as homogenous product that has been transferred to the next
facility in the distribution system. Consequently, the only batches of fuel that
should be reported are those that are transferred during the compliance period to
another facility.
3.10: D Can early release ULSD (prior to June 2006) be certified using designated or alternative
methods, or must a PBMS qualified method be used?
A: D If the refiner wishes to certify it as 15 ppmfuel and obtain early credits, it must
follow the PBMS requirements. For ULSD, the use of the designated and
alternative test methods expired on 12/27/2004, so the only way to measure 15
ppm sulfur diesel fuel is by using a method that meets the accuracy and precision
criteria at 40 C.F.R. 80.584 and is approved under the procedures set forth at 40
C.F.R. 80.585.
3.11: D Performance-based laboratory qualification misses the sampling piece of the equation.
D4057 allows several methods for manual sampling of tanks, if the method is not
specified then the results can be unrepeatable. Will the sampling method be specified by
the analytical methods?
A: No. The sampling method used under D4057 will be at the user's discretion.
3.12: D Will EPA consider allowing the volume accounting reconciliation (VAR) approach with
lubricity additives greater than 15 ppm sulfur?
A: D We have no intent to do so. The VAR approach was developed for the specific
situation of conductivity improver additives where no additive option existed with
less than 15 ppm sulfur and the additive was required to be added at the terminal.
3.13:D The nonroad rule does not explicitly exclude on-line sulfur analyzers for certification
purposes; and industry plans to utilize on-line analysis that meets EPA's rule for precision
and accuracy. Can on-line sulfur analyzers be approved for certification purposes if they
meet the precision and accuracy criteria stated in the regulatory requirements, and if not,
why not? Section § 80.581 (c)(l) allows the use of on-line analyzer test methods that
have been approved per section 80.580. However, sections §§ 80.580 and 80.585 do not
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reference on-line analyzers; do these sections apply to on-line analyzer approval as well,
or does EPA plan on issuing separate procedures for on-line analyzer approval?
A: D The intent of § 80.581(c)(l) was not to imply that on-line analyzers could be used
to certify a batch of dieselfuel. § 80.581(c)(l) states that the dieselfuel batch's
composite sample must be tested with a test method as described under the
provisions of § 80.580. The purpose of the provision is to provide the flexibility
to refiners to release a batch of diesel fuel prior to that batch's composited
sample being tested with a test method that: 1) is described under § 80.580, 2)
meets the accuracy and precision criteria described under § 80.584, and 3) is
approved under § 80.585. The test method that meets these three criteria on the
composited sample of the batch is the official test result. In order to allow for the
release of the batch of fuel prior to the composited sample being tested, we
believe it is necessary to require that on-line analyzers meet the accuracy and
precision requirements of§ 80.584 and are qualified under the process of§
80.585 (see also § 80.58l(c)(l)).
The Agency believes a regulation change would be required to allow on-line
blending systems (including on-line analyzers) to certify batches of diesel fuel.
However, before this issue could be addressed in a rulemaking, the Agency
believes that, at the very least, the following concerns would need to be
addressed: 1) Acceptable extent ofintra-batch variability during the course of a
blend; 2) Appropriate statistical demonstration of blending system's ability to
closely track results from bench analyses of composite samples; 3) Nature of on-
going statistical quality control of blending process needed to ensure that
measurement quality is maintained; 4) Nature ofrecordkeeping and EPA access
needed to permit audit oversight; and, 5) Size limits on batches.
3.14:D Section 80.581(c)(l) appears to require composite sampling/testing even though an
approved on-line analyzer method is used during blending. If this is true, why must the
on-line analyzer method be approved if the analyzer results are not used for compliance
purposes? Will the composite testing and reporting requirement be waived if the on-line
analyzers are approved? Will EPA consider on-line analyzer results as evidence in
establishing a defense in enforcement actions?
A: D Yes, § 80.581(c)(l) does require that a composite sample of a diesel batch be
taken, and the composite sample is required to be tested with a test method
described under § 80.580, which meets the accuracy and precision criteria under
§80.584 and is approved under the process at § 80.585. But the intent of§
80.581(c)(l) was only to provide flexibility to refiners that utilize on-line analyzer
equipment so they could release a batch of diesel fuel prior to its composited
sample being tested by a test method described under § 80.580. In order for a
refinery to have the flexibility to release a batch of diesel fuel prior to its
composited sample being tested with a test method described under § 80.580, §
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80.581(c)(l) does require that the on-line analyzer must meet the applicable
accuracy and precision under § 80.584 and be approved under the process at §
80.585. This is to help ensure that the dieselfuel leaving the refinery is compliant
with the applicable standard. Thus, on-line analyzer approval is required if a
refinery wishes the flexibility of releasing a batch of die sel fuel prior to that batch
of dieselfuel's composited sample being tested by an approved test method under
§ 80.585. Thus, EPA will not consider on-line analyzer test results as meeting the
requirement for refiners to test each batch of dieselfuel designated as 15 ppm
fuel.
3.15: D Given the results of the recent ASTM round robin testing comparing the repeatability and
reproducibility of the designated ASTM 6428 sulfur test and the alternative ASTM 5453
test, will EPA reconsider the issue and define the more precise ASTM 5453 test method
as the designated sulfur test method?
A: D The regulations finalized with the nonroad rule modified the sulfur test method
requirements. Instead of a designated method, there are now simply
performance-based requirements that must be met, allowing the use of multiple
test methods (see § 80.580 and 69 FR 39184).
3.16:D Given the reproducibility of even the most precise sulfur test method is no better than 6
ppm, will EPA revise the 2 ppm enforcement test tolerance?
A: D We believe that a small minority of the labs which have not yet taken steps to
improve their measurement procedures are the cause of continuing poor
reproducibility results. Once these labs take the steps to meet the accuracy and
precision criteria required in the regulations, their result should improve
considerably. We have asked API andNPRA to actively work with these labs and
offer our lab to anyone seeking assistance or wishing to compare test results.
3.17: D If in general pipelines can demonstrate that the percentage of sulfur tracks with gravity,
or sound velocity, or color, will that be a sufficient defense that the pipeline did not
contaminate a batch (assuming the pipeline can show what readings were when the valve
change were made)? Or will the pipeline need to have a lab analysis, go/no go test, or
on-line sulfur analyzer to defend? The treatment of pipeline interface will be important
to pipeline operations and the impact of 15 ppm diesel fuel implementation on fuel
supplies.
A: D The rule does not specifically require that pipelines use on-line sulfur analyzers
for quality assurance purposes. However, use of on-line analyzers may be
appropriate at certain locations on the pipeline. To ensure that the dieselfuel
meets the 15 ppm standard, the quality assurance program must include testing,
and at this time EPA believes such testing must measure the actual sulfur content
of the fuel. However, other relevant procedures that, for example, help a pipeline
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to locate an interface, could also be an important part of the quality assurance
program for a pipeline.
The rate of sampling and testing, and where product should be sampled, are a
function of the circumstances attendant to a particular distribution system. The
pipeline should use its knowledge of the system and exercise its best professional
judgment in determining the rate of sampling and testing and where samples
should be taken. Also, pipelines may act cooperatively with upstream and
downstream parties to share their testing information as part of the pipeline's
quality assurance program.
3.18: D Due to the known reproducibility problems in testing at a 15 ppm level, would EPA
consider letting downstream entities "average" the sulfur level tests within a range - say
no more than 20 ppm maximum and 15 ppm average - to avoid supply disruptions?
A: D No. As stated in the preamble to the final rule, the sulfur sensitivity of emission
controls that will be used on model year 2007 and later motor vehicles requires
that the sulfur content of highway die sel fuel dispensed into 2007 and later heavy-
duty vehicles not exceed 15 ppm. Consequently, under the rule, the 15 ppm sulfur
standard is a cap that must be met on a per-gallon basis.
To account for test variability downstream of the refinery gate or import facility,
the rule allows a downstream test adjustment of negative 2 ppm. The purpose of
taking testing variability into account in compliance determinations for fuel
sampled downstream of the refinery or import facility is merely to ensure that fuel
actually meeting the 15 ppm cap is not rejected and treated as noncompliant due
to concerns about testing variability. It is not expected to result in any increase
in the actual sulfur content of highway dieselfuel above 15 ppm at any point in
the distribution system. Note, however, that the rule does not limit the ability of
the fuel distribution industry to set a commercial pipeline sulfur content
specification. We acknowledge that pipelines may elect to set sulfur
specifications
3.19:D If a pipeline or terminal has test results indicating that motor vehicle diesel fuel sulfur
content is 15 ppm and EPA tests show the sulfur content is greater than 17 ppm, would
the pipeline's tests be an acceptable defense, or would the EPA's test results prevail?
This is of concern given the variability in test tolerance experienced during the round
robin.
A: D EPA would treat this as a violation.
3.20: D Pipelines require durable, easy-to-use test equipment that can quickly give test results.
We have been fortunate to find equipment that meets our needs in time for past rule
implementations. The EPA's field testing practice has been to use the same equipment
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pipelines use to conduct oversight. What are EPA's plans on field oversight in
implementation of this rule, and has the EPA made any selection of equipment that will
be used in the field?
A: D EPA does plan to conduct field screening of diesel fuel as well as testing diesel
fuel using the designated method for enforcement purposes. We have not yet
selected afield test instrument.
3.21: D ASTM updates test methods every five years. Will EPA issue a ruling that will allow the
latest (most up to date) version?
A: D The recent rule for non-road diesel contains a performance-based provision
specifically for diesel sulfur that allows the use of any diesel sulfur test method
that meets certain criteria for accuracy and precision. Under this approach,
industry would be able to determine on their own whether updated ASTM test
methods would be acceptable for compliance testing purposes.
3.22: D Accuracy can be compared to a gravimetric standard? Are NIST standards available?
A: D Several highly accurate standard reference materials (SRMs) are now available
from NIST.
3.23: D Is sulfur measurement at 15 ppm level practical at the pump? Do any of these methods
work for portable/field testing?
A: D Currently only for sampling at the pump and testing in the lab. However, a
portable MDWXRF instrument (ASTM method D 7039) is being considered for
field testing use.
3.24: D Low sulfur gasoline test method is D-2622 [WDXRF], low sulfur diesel will be tested by
D-6428 [5453 alternate]. Is there a chance that both test methods could be merged so that
one test method for both low sulfur gasoline and diesel would be permitted?
A: D The Agency has adopted a performance based test method approach which would
set forth criteria to determine the acceptability of use of voluntary consensus
standard based analytical test methods. Under this approach, industry would be
able to determine whether test methods allowed under the low sulfur gasoline rule
may also be utilized under the low sulfur diesel rule.
3.25: D If 15 ppm is required in the retail market, what will be the pipeline requirement for sulfur
at the refinery gate?
A: D EPA estimated that, on average, 7-8ppm sulfur would be needed the refinery gate
in order to produce 15 ppm sulfur at the pipeline 's end (see the highway diesel
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rule Regulatory Impact Analysis, chapter V, section C.I.a (this chapter can be
viewed on the web at http://www.epa.gov/otaq/regs/hd2007/frm/ria-v.pdf) for
additional discussion). Sulfur contamination during pipeline transport will vary
between distribution networks, and therefore refinery production sulfur levels can
vary as well.
3.26: D Terminal operators currently marketing ultra low-sulfur diesel fuel (15 ppm) are
concerned about the accuracy of the equipment available today in the field for testing.
Will EPA recommend which equipment industry should use for testing? What equipment
has the Agency decided to use to determine compliance?
A: D Presently we are utilizing several different instruments in our lab. We will use
whatever instruments over time we believe provide the best result.
3.27: D Is the Agency going to publish a list of sulfur analytical methods that had been deemed
equivalent under the rule?
A: D There is no designated method or equivalent methods for sulfur. We now have a
performance based system where labs have to meet precision and accuracy
criteria for whatever method they choose to use. A number of methods should be
able to be used to meet the precision and accuracy criteria, but this will be done
on a lab-specific basis.
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4.D Regulatory Clarification and Thoughts/Questions for EPA
4.1: D What, if any, grace or discretion will be afforded during start up of the enforcement
process?
A: D There are several provisions in the rule that provide flexibility during the
transition period. For example, the 20% downgrade limitation is an annual
compliance period requirement, such that any start up difficulties can be offset
later in the year. We also allow a 2 ppm downstream test adjustment on top of
the 15 ppm cap. Moreover, the rule provides substantial time periods for parties
at each stage of the distribution system to come into compliance during the initial
transition into the sulfur programs. Hardship provisions that are available to
qualifying refiners and importers address cases of extreme hardship or
unforeseen circumstances outside the control of the refiner or importer.
However, under the "hardship" provisions of the regulations, under no
circumstance may fuel having a sulfur content exceeding 15 ppm be sold or
dispensed for use in engines requiring 15 ppm fuel.
4.2: D The regulations talk about the requirements for PTDs for both the diesel fuel and the
additive, but it is unclear at what point an additive PTD is tied to a fuel PTD; i.e. you
would never know in which batch a high sulfur additive was used. Are we required to
re-certify 15 ppm diesel fuel downstream if an additive with more than 15 ppm sulfur is
used downstream of the refinery certification? Are we required to modify the diesel PTD
to include language stating that an additive with more than 15 ppm sulfur was used in the
product?
A: D There is no specific requirement to tie additive PTDs to diesel fuel PTDs.
Sections 80.521 and 80.591 set forth requirements for additives and additive
PTDs. The regulations also set forth prohibitions against selling diesel fuel
represented to meet the 15 ppm sulfur standard unless it does meet that standard.
The additive blender will be liable if it causes fuel it represents to meet the 15
ppm standard to exceed that standard. For an additive blender who uses an
additive having a sulfur content exceeding 15 ppm to meet its defense elements it
must, among other things, show that: it did not cause the violation, that product
transfer documents account for the product (both the diesel fuel and the additive),
and indicate the fuel and additive were in compliance while under the party's
control. Also note that §80.613(d)(2) will require, in most cases, that the blender
show that it tested every batch of fuel it blends such additive into. To establish
these defenses, the additive blender would likely need to have records that do tie
the additive blending to particular transfers of fuel. In the case of static
dissipater additives, a blender may use a volume reconciliation approach in lieu
of every batch testing.
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4.3: D Is there any economic hardship requirement escape clause for the distribution chain?
Given no field testing equipment available, insufficient tankage, commingled manifolds.
A: The economic hardship provisions in the regulations only apply to refiners.
4.4: D What recourse does a pipeline have that has received an off-spec batch of ULSD from
another pipeline?
A: D The PTDfor any given batch of fuel in the distribution system must accurately
reflect the sulfur content of that batch. If a pipeline accepts a batch of ULSD into
its system and later finds that the batch no longer complies with the sulfur
specification for ULSD, then that pipeline must ensure that the PTD that
accompanies the fuel as it leaves the subject pipeline's custody is accurate. If the
pipeline finds that the sulfur content of the subject fuel batch is less than 500
ppm, then the pipeline may redesignate that fuel batch as 500 ppm highway diesel
fuel (until 6/1/2010) provided that the pipeline remains in compliance with the 20
% downgrade requirements for 15 ppm highway diesel fuel and highway diesel
fuel volume balance requirements. The fuel batch may also be redesignated as
NRLM, LM, or heating oil provided that sulfur content of the fuel batch is
consistent with the applicable sulfur specification. There are no limitations on a
downstream pipeline's ability to receive such a batch of fuel.
4.5: D What are the provisions from the non-road rule that have been expanded to the highway
diesel rule, or that amend the highway diesel rule?
A: D The nonroad rule final regulations (69 FR 38958, June 29, 2004) identify all the
provisions that were amended from the highway diesel rule. Provisions that were
changed are specifically noted at the beginning of the applicable section.
However, please feel free to contact EPA staff if you have questions on a specific
section.
4.6: D The regulations require batch reports for small refiners for each compliance period from
June 1, 2007 through May 31, 2010 per § 80.604(d). For each batch, this includes "the
sulfur content andcetane andaromatics content of the fuel" (§ 80.604(d)(5)). This is not
consistent with the Agency's response to comments, May 2004, p. 10-32, 10.3.3.3
Aromatics Reporting Requirements.
A: D The regulations require batch reports for all refiners. This provision was
erroneously copied into the reporting provisions in the regulations. We agree
that the batch reporting ofcetane index or aromatics levels for off-highway diesel
fuel is not necessary. The regulations regarding a minimum cetane index of 40 or
a maximum aromatics content of 35 volume percent for highway diesel fuel do not
include any batch reporting requirements. This is also the case for sulfur content
where only the designation is required. We see no need to impose such batch
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reporting requirements on NRLMdieselfuel at this time. However, records
retained must contain this information. EPA does intend to correct this provision
in a subsequent action.
4.7: D What provisions exist in the ULSD rules for importing nonroad and highway diesel fuel
from Canada by truck?
A: D Provisions for diesel fuel transported into the U.S. by truck or rail car are found
in § 80.583. They are similar to the gasoline sulfur rule provisions for importing
gasoline into the U.S. by truck.
4.8: D How would distillate not used as fuel (i.e. for freeze protection) be accounted for?
A: D The possible designations for # 1 and #2 distillate are detailed in §80.598. An
entity would have the option to designate it as heating oil or blendstock if it did
not want to comply with the highway and NRLM standards.
4.9: D For terminal reporting, is it: quarterly reporting with quarterly compliance with 20%
downgrade limitation, or quarterly reporting with annual compliance with 20%
downgrade limitation?
A: D Quarterly reporting and downgrading compliance are separate issues. All
facilities in the D&T system have quarterly reporting requirements. Truck
Loading Terminals also need to provide required compliance calculations.
Downgrading calculations are a recordkeeping requirement, not a reporting
requirement. The downgrading compliance periods are listed in §80.52 7(c) (3).
4.10: D Current <500 pm kerosene blending into 500 highway diesel is an increase in the
highway diesel pool. Is EPA revising § 80.525 to allow for this increase?
A: D Section 80.525 contains the requirements applicable to kerosene blenders. The
provisions regarding the determination of compliance with the volume balance
for motor vehicle (highway) diesel fuel are contained in 40 CFR 80.599 (b). Each
facility must maintain a positive or neutral highway diesel balance during any
compliance period. The questioner is correct in that the addition of#l 500 ppm
diesel fuel not designated as highway diesel fuel (such as 500 ppm kerosene) to
500 ppm highway diesel could result in an increase in the highway diesel pool.
This is possible, but would have to be accounted for in calculating compliance
with the facility's highway diesel volume balance. We anticipate that 15 ppm #1
diesel fuel will be available for wintertime blending. The use of such 15 ppm fuel
for wintertime blending into highway diesel fuel will not adversely impact the
facility's ability to comply with the highway diesel volume balance requirements.
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4.11: D For consumers with a 2007 vehicle how will they be educated to look for sulfur content
at a station to prevent inadvertent use of 500 ppm?
A: D The fuel regulations require that all fuel pumps be labeled to inform the user
which fuel they are dispensing into their vehicle. These labels will state which
engines/vehicles that the specific fuel is suitable for use in. There will also be
labels on the 2007 engines, per § 86.007-35, stating which fuel should be used.
4.12: D Will it be legal for an Alaska refiner to dye its highway ULSD?
A: D The highway and diesel fuel regulations include no dye requirements or
restrictions for Alaskan fuel, provided the requirements of 40 C.F.R. §§ 69.51 and
69.52 are met. IRS has its own fuel tax requirements.
4.13: D Has EPA defined the quantitative amount of dye that is visibly dyed? And what does that
mean in a lower limit of dye?
A: D There is no set amount of red dye that must be added to fuel, EPA regulations do
not specify what concentration is required. The regulations only require that
"visible evidence" of red dye be present (§§ 80.510(d)(5),(e)(5), and (f)(5)), and
this amount may vary for different parties. This is the same visible evidence
criteria that was first implemented for non-highway dieselfuel in 1995 (§
80.520(b)).
4.14: D In an effort to maintain balance between nonroad and highway diesel fuel, EPA has
established rules pertaining to "shifts" in volume (anti-downgrading). Does this hinder
the establishment of new product distributors?
A: D We do not believe that the volume balance requirements will inhibit the
establishment of new product distributors. Any new fuel distributor need only
register and then comply for the portion of the compliance period in which they
were in business. New distributors would begin with a clean slate with respect to
demonstrating compliance with the volume balance requirements. In cases where
certain product distribution assets are sold to a new party in the middle of a
compliance period, EPA will provide guidance regarding how the previous and
new owners will work together to demonstrate compliance for the compliance
period in which the sale takes place. One option would be for the original owner
to be responsible for demonstrating compliance during the portion of the
compliance period during which it maintained ownership. The new owner would
then be responsible for demonstrating compliance during the portion of the
compliance period over which it exercised ownership. This would be EPA 's
default assumption regarding how the applicable requirements would be applied.
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4.15: D What is EPA's response to the distribution complexities outlined at the November 2004
workshop? Specifically, if the refiners are not producing ULSD until May 2006, what is
EPA's belief that 15 ppm ULSD can be supplied at the pump by September 2006?
A:U We believe that the rule provides ample time for transition. In most cases, retail
stations should have sufficient time to make the transition. However, there is no
requirement that retailers must sell 15 ppm ULSD. If their transition takes
longer, then they may continue selling 500 ppm fuel longer.
4.16: D When may importers begin classifying distillate product as DTAB?
A:U On the effective date of the regulation.
4.17: D Will annual attestation be required for ULSD like it is for RFG today?
A: There is currently no attestation requirement in the dieselfuel regulations.
4.18: D If the 80/20 provision allows for a 20% downgrade, can we assume that 100,000 bbl
ULSD can result in:
80,000 bbl to the pipeline,
64,000 bbl at the terminal, and,
46,000 bbl at retail?
A:0 The 80/20 (§80.530(a)(3)(i)(A)) and anti-downgrading (§ 80.527) are two
separate provisions. The 80/20 provision is the requirement that at least 80% of
a refiner's highway fuel produced is required to meet the 15 ppm standard. The
anti-downgrading provision, which does not apply to refiners, allows for up to
20% of an entity/facility's 15 ppm highway dieselfuel to be downgraded to 500
ppm highway dieselfuel (QA 4.20 also discusses anti-downgrading).
A refiner's production is defined as the amount of fuel that is actually delivered to
the next party. The volume of 15 ppm highway dieselfuel delivered by a refiner
to a pipeline will be reported to EPA based on the measured volume as received
by the pipeline operator. In such a case, there would be no downgrade reported
in moving the fuel from the refiner to the pipeline, as downgrading does not apply
to refiners. Each custody holder of 15 ppm highway dieselfuel may downgrade
up to 20% of the volume it receives to 500 ppm highway dieselfuel. There is no
restriction on the volume of 15 ppm highway diesel which can be downgraded to
products other than 500 ppm highway dieselfuel (e.g. heating oil, or 500ppm
NRLM diesel fuel). The 20% figure was set because we believed this would be the
greatest percentage any one custody holder would need to downgrade due to the
procedures necessary to limit sulfur contamination during the transportation of
15 ppm dieselfuel. We expect that most custody holders in the distribution chain
will downgrade a much lower percentage of the 15 ppm highway dieselfuel they
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receive. In most cases economic factors will limit downgrading to the bare
minimum. As a result, while the example is hypothetically possible, it is not a
realistic scenario.
4.19: D Has anyone given any thought as to what the other parameters will look like once ULSD
is fully produced (i.e. aromatics, cetane number, nitrogen, etc.)? Are there any issues
with respect to the energy content of diesel with the increased hydrotreating potential
"lightening" of diesel going down to 15 pm?
A: D There is a projected change in density and energy content per gallon, thus
leading to a small change in fuel economy. In most cases it should be
imperceptible- since the change still falls within the range of normal variations in
diesel fuel. While fuel economy decreases slightly, there is not an overall energy
loss, since refinery production volume increases to offset the energy density
change. There is also expected to be a slight improvement in the cetane number
of the diesel fuel resulting from a small decrease in aromatic content due to
hydrotreating.
4.20: D Please explain 20% downgrade provision in detail and specificity- how does it work at
each stage in the distribution system, especially if one company plays many roles?
A: D The anti-downgradingprovision is to prevent the intentional commingling of 15
ppm highway diesel fuel and 500 ppm highway diesel fuel that would result in no
availability of 15 ppm highway diesel fuel. The 20% limit is there to allow for
unintentional mixing/normal contamination during the compliance period. It
works the same throughout the distribution system, with the only exceptions being
the unique provisions for retail outlets found in §80.527 (e). Compliance is
facility-based, so the fact that a company serves multiple roles does not matter.
4.21: D Define "distributor" and "end user" from a reporting and recordkeeping standpoint.
A:D A "distributor" is any entity in the distribution system — they may or may not be
named specifically as a pipeline, terminal, barge, rail system, etc. The activity
that the distributor is engaged in will dictate appropriate reporting and
recordkeeping requirements.
An "end user " as addressed in the presentation, "Recordkeeping and Reporting
for NonroadDiesel Fuel", was specifically aimed at recordkeeping requirements
for ultimate consumers in Alaska (§§ 80.600(f) & (g) and80.554(a)(4) & (b)(5)).
4.22: D EPA's 2004 refiners' pre-compliance report concludes that there will be an adequate
supply of ULSD (at the refinery gates); however, the report does not address the
distribution of ULSD. Will ULSD be available in all parts of the country?
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A: D Based on the information that refiners provided in the pre-compliance
reports, as well as other discussions, we are confident that ULSD will be
available in all areas of the country. Unfortunately, to respect
confidential business information, we cannot provide more specific
information could not be given in the summary and analysis of the pre-
compliance reports on the exact locations that refiners would be
producing ULSD. We are currently working on a proposal for a plan for
Alaska that will address the unique situation found there.
4.23: D Will refiners produce No. 1 diesel fuel at 15 ppm sulfur? What other cold
weather-gelling strategies are available to the end-user?
A: D Yes, some refiners will produce No. 1 diesel fuel. There are also various other
cold-flow improver additives currently on the market as well.
4.24: D Section 80.592 specifies the data which must be kept and maintained for all diesel
batches but does not require submission to EPA unless requested. Section 80.604
requires annual submission of each batch of NRLM diesel or heating oil. However, the
June 29, 2004 Preamble, section V(G)(5)(b) requires batch reports to be submitted, but
does not specify between Highway or NRLM diesel. Please confirm that there are not
any additional quarterly or annual reporting requirements for individual batch data of
Highway diesel (15 or 500 ppm). In addition, does EPA plan on requesting this data?
A: D There are no additional requirements, and EPA does not plan to request
additional data at this time; the only requirements are volume and designation
information plus identification information.
4.25: D If a refinery receives a previously designated distillate (PDD), what options does the
refinery have for blending the PDD and how are any changes in fuel designation
handled? In other words, is there a provision similar to the gasoline rule where a
previously designated material may be debited from a compliance pool using a negative
volume? Does a similar provision exist in the distillate rule? Alternatively, is the
refinery to handle PDD as a terminal and be subject to the same downgrade rules as the
terminal?
A: D There is no similar provision to the RFG/anti-dumping regulations that would
treat previously designated distillate fuel as a negative batch when it is blended
with blendstock at a terminal blending facility or other refinery. A facility that
receives previously designated distillate must be registered as a downstream
facility and make appropriate records and reports regarding designation and
tracking of the previously designated distillate, including any downgrading or
other change in designation of that fuel volume. In addition, if the refiner blends
blendstock to the previously designated distillate, it must, in its capacity as a
refiner, properly designate that additional volume and is responsible for all
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refiner requirements for that added volume. For example, if 100 gallons of high
sulfur blendstock is added to 100 gallons of 15 ppm highway fuel, and the
resulting 200 gallons of product is sold as 500 ppm highway fuel, in its capacity
as a downstream facility, the facility would have to account for the downgrade of
the 100 gallons of 15 ppm fuel to 500 ppm highway fuel. In its capacity as a
refiner, it would be responsible for producing 100 gallons of 500 ppm fuel. If the
example above is changed such that the product blended is 100 gallons of
previously designated high sulfur fuel to 100 gallons of 15 ppm highway fuel, then
there is no refining activity; there is just a change in designation and downstream
downgrade of the 15 ppm fuel that is used for the blending to 500 ppm highway
fuel.
4.26: D Do the Credit Trading Area (CTA) regulations as defined in section 80.531 apply only to
importers?
A: D No, CTAs apply to both importers and refiners.
4.27: D Section 80.532(d) implies that credits cannot be traded from one CTA to another- does
this restriction apply only to imported fuel or can credits generated by a refinery located
in PADD 1 (CTA 1) trade credits with a refinery in PADD 2 (CTA 2)?
A: D This applies to both refiners and importers, and highway credits can only be
traded within a CTA.
4.28: D In earlier Q&As for gasoline, EPA designated that the Virgin Islands and Puerto Rico are
in PADD 6; Guam, American Samoa and the Northern Mariana Islands are in PADD 7.
Since CTAs are nearly identical to the corresponding PADDs why has EPA chosen CTAs
6 and 7 for Alaska and Hawaii, and will EPA reconsider these designations?
A: D EPA does not intend to modify the credit trading area designations, we believe
the current designations are clear and understandable.
4.29: D What value are the non-highway baselines that are discussed in § 80.533 since they are
not used in any credit generation equations or other compliances?
A: D § 80.533 explains that non-highway baselines are generated and used by small
refiners to comply with any of the options available to small refiners under §
80.554; and other refiners for the purposes of early credit generation.
4.30: D The preamble states (page 39061), " [the] rule allows terminal operators and others to
switch the designation of 500ppm sulfur NRLMdiesel fuel to highway dieselfuel on a
temporary but not a cumulative basis over time."
a) What "others" is EPA referring to?
b) What is temporary?
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c)D What if a party has not switched 500 ppm highway diesel back into the 500 ppm
NRLM market by 2012 when there is no longer a market for 500 ppm NRLM
(when NRLM must be at 15 ppm)?
A:U a) The word "others" in the sentence refers to pipeline operators.
b) "Temporary " is within the compliance period.
c) The party will be subject to quarterly compliance until 2010, and annual
compliance thereafter. Any noncompliance will be detected at the end of
each compliance period.
4.31: D Considering the likely contamination of large amounts of ULSD and the permissive
downgrading provisions, will ULSD continue to be the dominant fuel at the pump in
2006?
A:U Yes. Anti-downgrading allowances for each facility are 20%. However most
facilities will try to limit downgrading. For even the likely worst case facility,
downgrade through normal contamination is expected to be less than 10%, and
typically only a few percent or less. In total, downgrade due to contamination is
expected to average less than 5%. Consequently, it should not significantly
impact the availability of 15 ppm fuel.
4.32: D How will the end-user know whether they are refueling with fuel in excess of 15 ppm
sulfur?
A: D The regulations require that all fuel pumps be labeled to inform the user which
fuel they are dispensing into their vehicle. These labels will state which
engines/vehicles that the specific fuel is suitable for use in. These labels will
match comparable labels on 2007 and later highway vehicles. Distributors will
likely have tested fuel batches at retail to ensure that the fuel meets the applicable
standard that is on its pump label.
4.33: D If a retailer or wholesale purchaser-consumer does not dispense early credit 15 ppm
sulfur cap motor vehicle diesel fuel, is June 1, 2006 the effective date for the pump
labeling standards at § 80.570 per § 80.500(e)?
A: D Pumps which dispense on-roaddiesel containing 15ppm sulfur or less are
required to be labeled as such starting June 1, 2006.
4.34: D Under 40 CFR § 80.592(b) what is meant by a batch of diesel fuel and designating a
batch number? 15 ppm sulfur content highway fuel will typically be produced
continuously as the output from a distillate hydrotreater and is not blended like gasoline.
The concept of batch numbering and batch volumes does not seem to make sense based
on the production of this product. Please provide clarification.
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A: D Under 40 CFR § 80.2(nn), a batch of motor vehicle dieselfuel "means a quantity
of die sel fuel which is homogeneous with regard to those properties which are
specified for motor vehicle dieselfuel under subpart I of this part. " A batch of
motor vehicle dieselfuel is thus a discreet and identifiable quantity of such
homogenous dieselfuel. Thus, under the regulations, the volume and properties
of even continuous streams are only measured periodically and it would be best
to apply the measurements to the volume produced most closely to the time of the
measurement. In other words, a refiner should break up a continuous stream into
discrete batches to assure that the batch is a homogeneous mixture, and for
purposes of record keeping and reporting under §§ 80.592 and 80.593. It is our
understanding that dieselfuel is not generally produced by in-line blending
processes but is blended into a tank, where the volume and properties can be
measured. As with the RFG/anti-dumping rule, the refiner would have to be
consistent when calculating the volumes and properties of batches, consistently
basing them on either shipped volumes or produced volumes. Otherwise double
counting of volumes and properties could occur.
Assignment of batch numbers will be done the same way under the highway diesel
sulfur rule as is done under the RFG and anti-dumping regulations. See §§
80.592(b)(2) and80.65(d)(3).
4.35: D Diesel fuel retailers will not be making 15 ppm motor vehicle diesel fuel; we will only
be selling it to customers for use in their diesel-powered vehicles. What are a diesel
retailer's primary regulatory responsibilities under the 15 ppm highway diesel fuel
program?
A: D Responsibilities are similar to those under other fuels rules. While the
responsibility for producing or importing compliant 15 ppm sulfur content
highway dieselfuel resides with refiners and importers, retailers and all other
parties in the distribution system share responsibility for assuring that dieselfuel
subject to the 15 ppm standard is not contaminated or commingled with other
products, such as distillates having a sulfur content greater than 15 ppm. At the
retail dispenser, if the fuel subject to the 15 ppm sulfur standard does not meet the
standard, it is in violation, subject to a 2 ppm test result adjustment applied to test
results at downstream facilities. All parties in the distribution system are
presumed liable for such violations, including the retailer (§ 80.612). Each party
may establish a defense to the violation under § 80.613. A retailer may establish
a defense by showing it did not cause the violation and that product transfer
documents account for the fuel in violation and indicate the violating product was
in compliance when it was under the retailer's control.
In addition, retailers and wholesale purchaser-consumers are required under the
regulations to post labels on each diesel fuel pump stand, notifying customers of
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the type of fuel dispensed by each dispenser. The required language for these
labels is prescribed by § 80.570.
Per §80.610, retailers are prohibited from introducing, or permitting, the
introduction of noncomplyingfuel into motor vehicles. Per § 86.007-35, model
year 2007 and later diesel powered vehicles, which will require fuel meeting the
15 ppm sulfur standard, will have a label on the filler inlet and on the dashboard
stating "Use Ultra Low-Sulfur Diesel Fuel Only" or "Ultra Low-Sulfur Diesel
Fuel Only. " A retailer would clearly be liable for the action of a retail employee
introducing 500 ppm diesel fuel into a vehicle equipped with such a label.
Misfueling is addressed in more detail below.
Retailers must retain all product transfer documents, which identify the
applicable standard of the fuel, and must assure that this fuel is delivered into the
proper storage tank for sale to customers (see §§ 80.590, 80.591 and 80.59 2). If
a misdelivery does occur, retailers must immediately cease sales from the
dispensers served by the impacted storage tank and assure that the product in the
tank is brought back into compliance before resuming sales.
Retailers should train their employees, and work closely with distributors and
carriers who supply product to their outlets, so that the tank truck drivers will
have needed information about what types of product are sold at each outlet and
which storage tank corresponds to each type of product.
The truck distributors themselves should in turn work closely with the retail
operations, and ensure drivers know which product should be delivered to each
station, and what storage tank each type of product should be delivered to.
Truckers should ensure that high sulfur products previously carried in truck
compartments have been completely drained from the truck compartments and
hoses before 15 ppm product is loaded into those compartments.
Retailers are also subject to downgrading limitations of the regulations (§
80.52 7). This is addressed in more detail elsewhere. Retailers who downgrade
15 ppm highway fuel to 500 ppm highway fuel must keep records that
demonstrate compliance with the limitations and requirements of the
downgrading provisions (see § 80.527 (g)).
4.36: D How do you indicate whether a batch of fuel is marked or unmarked?
A: D The product's accompanying PTD should state if the product is marked or not.
Section 80.590(a) details the information that must be included on the product
transfer document that accompanies any transfer in custody or title ofMVNRLM
diesel fuel or heating oil. Section 80.590(a)(6)(ii) states that the PTD must
contain "an accurate and clear statement of the applicable designation and/or
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classification under section 80.598...and whether the fuel is dyed or undyed, and
for heating oil, whether the fuel is marked or unmarked."
Further, § 80.590(a)(7) contains additional requirements regarding the PTD
language for the transfer of fuel batches of a given fuel designation/classification
from one facility to another in the fuel distribution system where dieselfuel is
taxed, dyed or marked. These requirements also apply for any subsequent
transfers except for when the fuel is dispensed into an end-user's equipment.
4.37: D Can you clarify the PTD product code recommendation/requirements? Is there a specific
product code standard that EPA would like us to use in reporting? Also, must the
specific fuel designation be in the actual product code, or can it just be on the PTD
somewhere?
A: D We will no longer be requiring the fuel sulfur level (15, 500, or >500) to be in the
code of a PTD as long as the sulfur level is noted on the PTD somewhere. We
will be issuing a technical amendment to correct this. Please note that for
transfers to truck carriers, retailers, or wholesale purchaser-consumers, product
codes may not be used (§ 80.590 (d)).
4.38: D My company currently sells distillate blendstocks. Can we continue to sell blendstocks
given the new regulations?
A: Yes, you may continue to sell blendstocks. In addition, it would also be in your
best interest, for defense purposes, to identify any product that you ship.
4.39: D Has EPA developed a program that allows EPA to check balances between parties on
hand-offs? If so, could you provide the same tool to industry to enable companies to run
the tool to reduce errors before submission?
A: D No, EPA is not developing software to check hand-off balances. We will rely on
database reports to identify potential hand-off reporting problems. Specifically,
we will be looking at summaries of transactions, for a given quarter, between
individual hand-off partners (shipper and receiver) to verify that the product
volume shipped equals the product volume received, with zero tolerance.
4.40: D The Interstate Commerce Act requires shipper and volume confidentiality. Do the diesel
fuel rules protect these requirements?
A: D While the EPA rules regarding confidential business information were not written
for the Interstate Commerce Act, we do protect the confidentiality of submissions
to EPA and do not give confidential company information out to others. If a
company is concerned about the protection of its information, it may mark all
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reports and other submissions to EPA as "CBI" (Confidential Business
Information).
4.41: D Biodiesel manufactured from palm oil has a red tint. Would this be problematic with
respect to compliance with EPA red dye requirements (significant quantities of palm oil
are available and the price is attractive)?
A: D EPA requires that fuel marketed as highway dieselfuel contain no visible
evidence of dye solvent red 164. There is no regulatory requirement that would
preclude that use of palm oil-derived biodiesel as a highway dieselfuel
blendstock. EPA and other interested parties could use spectrographic analysis
in the field to determine whether the source of a red tint to dieselfuel resulted
from contamination with red dye 164 or from another source. Furthermore, we
do not believe that this will be an issue, as biodiesel will not go through pipelines.
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5.D Cetane Index/Aromatics Requirements
5.1: D In § 80.510(h), does EPA really mean that the cetane index (CI) doesn't have to be met if
sulfur is met with credits?
A: D The cetane or aromatics requirement only applies to NRLM fuel that is required
to meet either the 15 ppm or SOOppm std. If fuel is produced to uncontrolled
sulfur levels through, for example, credits or hardship provisions, that fuel does
not have to be controlled to meet EPA 's cetane or aromatics standards either.
However, industry standards will still apply.
5.2: D How can heating oil be used as NRLM when heating oil does not necessarily meet cetane
and aromatics requirements?
A: D The rule allows distillate designated as heating oil to be redesignated as high
sulfur NRLM provided that during any compliance period there was no net shift
of heating oil into the NRLM market (per § 80.598(b)(9)(viii)). Please refer to the
volume balance requirements for high sulfur NRLM and heating oil contained in
40 CFR 80.599(c). To meet these volume balance requirements, for any volume
of heating oil redesignated as high sulfur NRLM during a compliance period, an
equal volume of high sulfur NRLM would typically need to be redesignated as
heating oil during that same compliance period. Any volume of heating oil
redesignated as high sulfur NRLM would be required to meet the applicable
cetane and aromatics requirements.
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6.D Sulfur Standards
6.1: D In § 80.510(h), should it be "or" rather than "and". As currently written, only get
exemption if credits, SR, hardship, and temporary relief?
A: D Yes, it should say "or ". This was corrected in a technical amendment to the
regulations (which can be found on EPA 's web site at:
http://www.epa.gov/otaq/regs/fuels/diesel/diesel.htm#regs. July 7, 2005).
6.2: D Have refiners based their production forecasts on 15 ppm ULSD, or some much lower
pipeline spec?
A: D Our understanding is that production is set based on a range of factors and as
such, different refineries have different targets.
6.3: D If 15 ppm kerosene may be blended with 15 ppm ULSD, does the kerosene also have to
be certified as #1 ULSD?
A: D No, although 15 ppm kerosene not previously certified as #1 ULSD will count
against the party, provided that its highway volumes do not increase.
Consequently, we expect that most #115 ppm will be designated as motor vehicle
dieselfuel.
6.4: D Should 15 ppm max sulfur No. 1 diesel or dual certified Jet/No. 1 diesel that is
designated as 15 ppm diesel fuel when leaving the refinery be counted as 15 ppm diesel
fuel in determining compliance with the 80% 15 ppm diesel fuel refinery production
requirement for the Temporary Compliance Option?
A: D Yes, if a refinery designates either No. 1 diesel or dual certified Jet/No. 1 diesel
under as motor vehicle dieselfuel meeting the 15 ppm sulfur standard under §
80.520(a)(l), it is counted as 15ppm dieselfuel in determining compliance with
the Temporary Compliance Option.
6.5: D Subsequent sale of the 15 ppm max sulfur dual certified kerosene as commercial jet fuel
is permitted, is not subject to any downgrading limitation, and does not impact
compliance with the 80% 15 ppm diesel fuel production requirement for the Temporary
Compliance Option?
A: D Correct, if a refinery designates kerosene as motor vehicle dieselfuel, then sells
the kerosene as commercial jet fuel, then the reclassified volume of kerosene is
not subject to any downgrading limitation, and does not impact compliance with
the 80% 15 ppm diesel fuel production requirement for the Temporary
Compliance Option.
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6.6: D Many refiners currently make a jet fuel meeting <500 ppm requirements. If refiners
make a jet fuel meeting 15 ppm requirements, there may be compatibility (safety or
performance) issues for jet engine manufacturers. Have these manufacturers been
consulted in this rulemaking process? If so, what is their position on use of 15 ppm jet
fuel?
A: D The highway and nonroad dieselprograms do not require that refiners produce
15 ppm sulfur jet fuel and do not set sulfur limits for jet fuel that is not designated
as motor vehicle diesel fuel. This would be their decision. EPA believes
compatibility issues raised by 15 ppm jet fuel would be addressed by the refiners
and customers involved.
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7.D Additives
7.1: D Will there be an allowance for other additives - like cetane enhancer?
A: D New provisions were adopted in the nonroadfinal rule for anti-static additives
downstream at the terminal. These provisions were adopted because all known
anti-static additives were found to contain elevated levels of sulfur, and they
needed to be added downstream at the terminal. The provision allows the
addition of additives that exceed 15 ppm sulfur, but only if certain conditions are
met, as specified in § 80.521. We are not aware of any similar situation with any
other types of additives that would warrant similar consideration.
7.2. D Subsequent use of No. 1 Diesel or dual certified kerosene for winter blending in 15 ppm
diesel fuel is not an issue, but is winter blending into 500 ppm motor vehicle diesel fuel
subject to the 20% downgrading limitation by each custody or title holder on an annual
basis?
A: D Per § 80.527, the anti-downgrading limitations, as modified in the nonroad rule,
only apply to #2 15 ppm diesel fuel.
7.3: D Some refiners, and some distributors, blend additives into diesel fuel to improve
performance. Is EPA taking any steps to assure that these diesel fuel additives do not
contain sulfur at levels in excess of 15 ppm?
A: D The highway diesel fuel rule requires diesel additive manufacturers to label their
additives, both on the container (in the case of additives sold to consumers- see §
80.59l(d)(l) and (2)), and on the PTD (see § 80.59l(b)(2)), with information as
to the sulfur level in the additive. If the additive contains more than 15 ppm
sulfur, then it is the blenders' responsibility to assure that the use of the additive
does not result in diesel that exceeds the 15 ppm standard (see § 80.521).
Additives sold for consumer use in model year 2007 and later vehicles may not
contain more than 15ppm sulfur (see § 80.591(d)(2)).
7.4: D It is a common practice for diesel fuel to be blended with kerosene to improve
performance characteristics (particularly during cold weather), or other substances, such
as used oil to dispose of waste products. Can such practices be continued under the 15
ppm diesel fuel program?
A: D Under §80.522, used motor oil, or used motor oil blended into diesel fuel, may
only be used in the fuel system of model 2007 or later diesel motor vehicles if the
vehicle or engine manufacturer has received a Certificate of Conformity under 40
CFR Part 86, that certification is explicitly based on emissions data, and the
motor oil is added at a rate consistent with the Certificate of Conformity. Under §
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80.525, kerosene that a kerosene blender adds (or intends to add) to 15 ppm
sulfur diesel must meet the 15ppm sulfur content standard, as indicated by
product transfer documents or test results.
7.5: D Kerosene is used for residential heaters, city bus fleets, and jet fuel among other uses. It
is also used to winterize diesel fuel and home heating fuel. Today, kerosene comes in
two grades, < 500 ppm sulfur and < .3% (3000 ppm) sulfur. It may or may not be dual
purpose, i.e. suitable for jet fuel use. To minimize grades, refiners will likely produce
only one grade of winterizing fuel, 15 ppm nominal maximum. Will 15 ppm kerosene
that is used to winterize 500 ppm diesel fuel be considered a downgrade and count
toward the 20%?
A: D No, 15 ppm kerosene that is used for wintertime blending will not be considered
downgrading.
7.6: D The anti-static additive sulfur contribution to ULSD will be resolved and tracked through
VAR. All other non-complying additives will require analysis. We have been asked by
some customers to acquire the anti-stat additive and blend it into packages they already
purchase. The packages will be less than 15 ppm but of course addition of the additive
can make them exceed the 15 ppm limit. Thus the question becomes, will EPA allow this
combination package to be resolved via the VAR methods or will testing be required?
A: D Multi-functional additive packages that contain a>15 ppm anti-static additive
may use the VAR method. However, the other components in the additive
package must be < 15 ppm. If any component of a multi-functional additive
package other than an anti-stat is > 15 ppm, then the VAR method may not be
used (§ 80.614). However, if the entire package is under 15 ppm, then the VAR
method is not required.
7.7: D There are no restrictions on blending 15 ppm kerosene with ULSD. Is this statement
modified depending on how the 15 ppm kerosene is designated?
A: D Yes. Unless the 15 ppm kerosene was designated as #1MV diesel fuel, it would
count against the blender in meeting their highway volume balance requirement
under the D&T regulations. We expect that most refiners will choose to designate
15 ppm kerosene as No. 1 MV diesel fuel.
7.8: D Kerosene with a sulfur level in excess of 15 ppm can be blended with ULSD up to a max
of 1% volume provided it does not alter the quality specs of the ULSD (and sulfur level
of the ULSD does not exceed 15 ppm). I assume because of the 1% volume limitation
that it doesn't matter what the designation of the plus-15 ppm sulfur kerosene is. True?
A: D No, this is not correct. Kerosene that is blended with ULSD must meet the 15
ppm standard, as stated in § 80.525.
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Kerosene is not an additive ((per § 80.2(xx)), nor is it considered as such with
respect to the 1% additive blending provisions. § 80.525 states that kerosene
blended with MVNRLMmust meet the applicable standard of the MVNRLM. The
accompanying PTD must also state that the kerosene meets the applicable
standard, and the kerosene blender must have test results indicating that the
kerosene complies with that standard. (See also QA 7.4.)
7.9: D There are no restrictions on blending 500 ppm kerosene into LSD. Is this statement
modified depending on how the 500 ppm kerosene is designated?
A: D The only restriction is on a party's volume balance- the volume of 500 ppm
highway dieselfuel cannot go up, so blending 500 ppm kerosene will count
against a party's volume balance requirement under the D&T regulations.
7.10: D Are there any rules regarding the blending of plus-500 ppm kerosene into LSD similar to
the 1% volume rule for ULSD?
A: D As stated in 7.8, above, § 80.525 restricts the blending of plus-500 ppm kerosene
into LSD. Further, the 1% volume rule does not apply, as kerosene is not an
additive. Blending kerosene that exceeds the applicable fuel's standard would
result in the need to redesignate the finished fuel. Such blending could also
impact the blending party's highway diesel volume balance.
7.11: D The title of 40 CFR 80.614 is, "What are the alternative defense requirements in lieu of§
80.613(a)(l)(vi)for static dissipater additives exceeding the 15ppm sulfur standard but
that contribute less than 0.05 ppm sulfur when added to MVNRLM diesel fuel?" The way
I interpret this is that if your static dissipater additive contributes less than 0.05 ppm
sulfur you can use the calculation method to prove compliance. If the static dissipater
additive would contribute more than 0.05 ppm sulfur, this additive could still be used but
would have to prove compliance through testing as outlined in § 80.613(a)(l)(vi). Is this
correct?
A: D Yes, this is correct- static dissipater additives that contribute more than 0.05ppm
to the sulfur level of the finished fuel could still be used. However, one would
need to follow the provisions in § 80.613 to establish affirmative defense to
presumptive liability. The alternate provisions in § 80.614 only apply to static
dissipater additives that contribute less than 0.05 ppm to the sulfur level of the
finishedfuel.
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8.D Credits
8.1: D § 80.599(b)(6) states "Calculations in paragraphs (b)(4) and (b)(5) of this section may be
combined for all facilities wholly owned by an entity.'" May this combination include
facilities in different Credit Trading Areas? [§ 80.599(b)(6)]
A: D Yes. The Credit Trading Area restriction on highway dieselfuel credit generation
and use only applies to refinery production and not to subsequent movement of
the fuel through the distribution system or downstream compliance under the
designate and track provisions.
8.2: D In § 80.535, the regulatory language covers generation of high sulfur credits for early
production of 500 ppm NRLM and generation of 500 ppm credits for early (2009)
production of 15 ppm NRLM. Can a refiner with some facilities that will be producing
15 ppm NRLM starting in 2006 generate high sulfur credits for early production of 15
ppm NRLM in 2006, as long as it does not double count these credits?
A: D No- in order to receive NRLM credit, the fuel must be designated as NRLM.
Further, to receive high sulfur credits, the fuel must at least meet the 500 ppm
sulfur standard. Per §80.598 (a)(3)(iv), any fuel designated as 15 ppm untilJune
2009 must be designated as motor vehicle dieselfuel in order to maintain the
intended benefits and integrity of the highway program. Such fuel can always be
used for NRLM purposes. However, in order to receive NRLM credit in the
situation described in the question, the fuel would have to be designated as 500
ppm NRLM by the refiner even though it met the 15 ppm standard.
8.3 :D For each of the four compliance periods between 6/1/2006 and 12/31/2009, an
interpretation of § 80.530(a)(3)(i)(A) is the following:
VSQO < [0-2 x (V15 + V500)] + credits from the same Credit Trading Area, where the units
are gallons.
Is this algebraic interpretation correct?
A:U Yes. For each compliance period between 6/1/2006 and 12/31/2009, inclusive,
the volume of diesel produced or imported at 500 ppm is limited to the sum of any
credits properly generated and used by the refiner or importer, or properly
transferred to and used by the refiner or importer from within the same Credit
Trading Area, plus 20 percent of the total volume of VI5 and V500 diesel
produced or imported. There are also certain additional requirements on the
generation and use of credits. See §§ 80.531 and 80.532.
8.4: D For the compliance period from 1/1/2010 through 5/31/2010, an interpretation of §
80.530(a)(3)(i)(B) is the following:
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V5oo — credits from the same Credit Trading Area, where the units are gallons
Is this interpretation correct?
A:U Yes. For the period 1/1/2010 through 5/31/2010, the volume of diesel produced
or imported at 500 ppm is limited to the sum of any credits properly generated
and used by the refiner or importer or properly transferred to and used by the
refiner or importer, from within the same Credit Trading Area. There are also
certain additional requirements on the generation and use of credits. See §§
80.531 and 80.532.
8.5: D Carryover of a small deficit is permitted, if two conditions are met in the immediately
following compliance period. There is a limit on the size of this deficit. § 80.530(a)(6):
"... However, for any compliance period prior to and including 2009, a refiner and
importer may exceed the volume limit in paragraph (a)(3) of this section by no more than
5 percent of the volume of Vt of diesel fuel produced or imported during the compliance
period, . . ." An interpretation of this 5 percent limit is the following:
V5op > [0.2 x (V15 + V500)] + credits,
if two conditions are met in the immediately following compliance period and if V500 -
([0.2 x (V15 + V500)] + credits) < 0.05 x (V15 + V500), where the units are gallons and the
credits must be generated in the same Credit Trading Area that they are used.
Is this algebraic interpretation correct?
A: D This algebraic formula correctly calculates the volume of deficit that can be
carried over under § 80.530(a) (6). The volume of 500 ppm diesel produced or
imported in any compliance period may exceed the volume limit of 500 ppm
diesel allowed in that compliance period provided that 1) the volume of 500 ppm
diesel does not exceed 5 percent of the total volume of VI5 and V500 diesel
produced or imported during the compliance period, and 2) in the succeeding
compliance period, the refiner or importer meets the volume limit for that year on
V500, and produces or imports 15 ppm diesel, or uses credits, equal to the
volume of the exceedance in the preceding compliance period.
8.6: D The definition of V500 is included in § 80.53 l(a)(2): "V500 = the total volume in gallons
of diesel fuel produced or imported that is designated under § 80.598(a) as motor vehicle
diesel fuel and subject to the 500 ppm sulfur standard under § 80.520(c) plus the total
volume of any other diesel fuel (not including V15, diesel fuel that is dyed in accordance
with § 80.520(b) at the refinery or import facility where the diesel fuel is produced or
imported, or diesel fuel that is designated as NRLM under § 80.598(aY) represented as
having a sulfur content less than or equal to 500 ppm." (emphasis added) Please explain
the underlined text above. What is this "other diesel fuel"?
A: D "Other diesel fuel" means any distillate products that meet the definition of diesel
fuel, such as kerosene, that is represented to have a sulfur content less than or
equal to 500 ppm. Any volume of refined distillate products containing less than
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500 ppm sulfur that is not designated as motor vehicle dieselfuel, should not be
included in the total volume of motor vehicle dieselfuel.
.7: D The federal temporary compliance option (TCO) includes a credit trading program with a
relevant restriction: if a refinery produces diesel fuel for a state 15 ppm sulfur cap
program for a greater volume than the federal requirement, then that fuel is excluded
from the federal credit program. See § 80.53 l(a)(5)(iv). This restriction applies to both
motor vehicle diesel fuel produced in that state or imported directly into that state.
8.7a: D The Texas Low Emissions Diesel (TX LED) rule (with its 15 ppm sulfur cap for
highway and non-road diesel in three ozone nonattainment areas and 95
eastern/central counties beginning on June 1, 2006) possibly excludes a
significant volume of ULSD from the federal TCO credit generation program
beginning on June 1, 2006. On October 15, 2001, EPA Region 6 approved the
TX LED program as necessary for Houston-Galveston ozone attainment; this
approval was published in the Federal Register on November 14, 2001 (66 FR
57196). If it meets the requirements in § 80.531, will 15 ppm TXLED be
included in the federal TCO credit program beginning on June 1, 2006 because,
although the 15 ppm TX LED rule includes non-road diesel fuel and excludes the
federal temporary compliance option, the 15 ppm TX LED volume is not
expected to be greater than the federal 15 ppm diesel fuel requirement in the
state? Will early 15 ppm sulfur cap TX LED produced before June 1, 2006
qualify as an early federal TCO credit if it meets the requirements in § 80.531?
Or will § 80.53 l(a)(5)(iv) exclude all motor vehicle diesel (TX LED and other
diesel) produced in or imported into Texas beginning on June 1, 2006 from the
federal TCO credit program because "no motor vehicle diesel fuel produced in
that state or imported directly into that state may generate credits under this
subpart, . . ." even though this Texas diesel sulfur regulation will only apply to
part of the state?
A: D The highway diesel program limits the ability to generate credits for fuel
produced or imported directly into a State with its own dieselfuel
requirement that requires a greater volume of 15 ppm or lower fuel than
the Federal program. Upon evaluating the Texas LED program in the
context of § 80.531(a)(5)(iv), we have concluded that, while the Texas
program is more stringent for a portion of Texas, it does not appear to
require a greater volume of fuel on a statewide basis to be 15 ppm than
will be required under the Federal program. As a result, in this specific
instance, the limit on credit generation in § 80.531(a)(5)(iv) does not
apply to the Texas program.
8.7b: D On February 24, 2000, CARB approved the Public Transit Bus Fleet Rule and
Emissions Standards for New Urban Buses. This includes a diesel fuel sulfur cap
of 15 ppm for transit agencies effective July 1, 2002. Does this CARB 15 ppm
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diesel fuel for public transit bus fleets qualify for the federal TCO credit program,
if the conditions in § 80.531 are met, because California is not subject to the
waiver of federal preemption provisions in the Clean Air Act? Or does §
80.53 l(a)(5)(iv) exclude all motor vehicle diesel fuel produced in California from
the federal TCO credit program because "no motor vehicle diesel fuel produced in
that state or imported directly into that state may generate credits under this
subpart, . . ." even though this CARB diesel sulfur regulation only applies to
public transit bus fleets?
A: D The § 80.531(a)(5)(iv) restriction does not apply to fuel produced prior to
June 1, 2006. Credit for fuel produced prior to then is subject to the
provisions in § 80.531(b) and (c). Given that this program covers less
than half of the diesel fuel sold in California, it would also not be
considered to require a greater volume of 15 ppm diesel fuel than the
Federal program under the provisions of§ 80.531(a)(5)(iv).
8.7c: D On September 15, 2000, the South Coast Air Quality Management District
(SCAQMD) adopted a diesel sulfur content cap of 15 ppm effective on October 1,
2005. Will this SCAQMD 15 ppm diesel fuel qualify for the federal TCO credit
program, if the conditions in § 80.531 are met, because California is not subject to
the waiver of federal preemption provisions in the Clean Air Act? Or will §
80.531(a)(5)(iv) exclude all motor vehicle diesel fuel produced in California
beginning on October 1, 2005 from the federal TCO credit program because "no
motor vehicle diesel fuel produced in that state or imported directly into that state
may generate credits under this subpart, . . ." even though this SCAQMD diesel
sulfur regulation will only apply to part of the state?
A: D Please refer to responses a and b, above. The SCAQMD issue is similar
to the Texas LED issue. Given that this program covers less than half of
the diesel fuel sold in California, it would also not be considered to
require a greater volume of 15 ppm diesel fuel than the Federal program
under the provisions of§ 80.531(a)(5)(iv). However, since CARB has
subsequently adopted a similar state-wide program for 15 ppm diesel fuel
(for highway and off-highway use), it requires a greater volume of 15ppm
diesel fuel than the Federal program and the restrictions in §
80.531(a)(5)(iv) apply.
: D Credits must be designated by refinery or importer-port of import, year of generation, and
Credit Trading Area (1-7) of generation. In 2005 and 2006, is it necessary to further
designate credits generated before June 1 versus after May 31 because § 80.531(c) has an
early credit period from June 1, 2005 through May 31, 2006?
A: D For reporting purposes, it is not necessary to distinguish between credits
generated before June 1, 2006 (early credits) versus credits generated after June
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1, 2006. Specifically, § 80.593 states that annual compliance reports must
contain information regarding credits for each refinery or, in the case of
importers, by Credit Trading Area. For record keeping purposes, refiners and
importers must keep information on credits separately for each calendar year
compliance period and separately for each refinery (or in the case of importers,
for each Credit Trading Area). However, § 80.592 (b) also specifies that refiners
and importers must keep documentation on the calculations used to determine the
number of credits generated. Since there are three ways to generate credits
under the program, credit calculations must be appropriate for the given time
period in which the credits are generated.'
8.9: D For reporting the percentage of motor vehicle diesel fuel produced meeting the 15 ppm
sulfur standard after the inclusion of any credits, an interpretation of § 80.593(a)(4) is the
following:
% = 100x[(V15 + credits)/(V15 + V50o)]
where the credits must be generated in the same Credit Trading Area that they are used.
Is this algebraic interpretation correct?
A: D Yes, this algebraic formula correctly calculates the percentage of fuel that must
be reported under § 80.593(a)(4), where VI5 and V500 have the meanings
provided in § 80.531(a)(2), and "credits" means credits that are properly
generated and used under the regulations.
8.10: D Adequate volume of 15 ppm highway diesel fuel produced today for the testing of the
distribution system is key to resolving uncertainty in a timely manner and working out
implementation issues. What is EPA doing to encourage refiners to produce test batches
of 15 ppm highway diesel fuel so that downstream parties can test models and
assumptions while there is still time to modify systems prior to 2006? Is it possible to
credit current production?
A: D To ensure a smooth transition to large-scale production and distribution of 15
ppm highway diesel fuel beginning June 1, 2006, the program allows for refiners
to generate early credits. From June 1, 2001 through May 31, 2005 refineries
and importers may generate credits based on the volume of 15 ppm sulfur
highway diesel fuel that is used in vehicles with engines that are certified to meet
1. From June 1, 2001 through May 31, 2005 refineries and importers may generate credits based
on the volume of 15 ppm sulfur highway diesel fuel that is used in vehicles with engines that are
certified to meet the model year 2007 heavy-duty engine PM standard under 40 CFR 86.007-11.
2. From June 1, 2005 through May 31, 2006 refineries and importers may generate credits based
on the volume of 15 ppm sulfur highway diesel fuel that is dispensed at retail outlets or wholesale
purchaser-consumer facilities.
3. From June 1, 2006 through December 31, 2009 refineries and importers may generate credits
based on the volume of 15 ppm sulfur highway diesel fuel produced above the 80 percent
threshold.
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the model year 2007 heavy-duty engine PM standard under 40 CFR 86.007-11.
From June 1, 2005 through May 31, 2006 refineries and importers may generate
credits based on the volume of 15 ppm sulfur diesel fuel that is dispensed at retail
outlets or wholesale purchaser-consumer facilities (i.e., the volume of 15 ppm fuel
that is kept segregated and uncontaminated all the way through the distribution
system and to the end user).
Under the existing regulations, diesel fuel used to test the distribution system does
not generate early credits unless it meets the above criteria. However, based on
recent discussions with interested stakeholders, the Agency is also investigating
whether it would be appropriate to allow early credits for test batches of 15 ppm
sulfur diesel fuel which, while starting out as 15 ppm may end up at a higher
sulfur level prior to sale to the end user. The Agency is in the process of
developing a proposal to allow this.
. 11: D Can credits generated by meeting the 15 ppm highway diesel sulfur standard early be
used in the gasoline program?
A: D No. However, the regulations at § 80.540 allow a GPA refiner to extend its sulfur
standards for gasoline from December 31, 2006 to December 31, 2008 if the GPA
refiner produces 95% of its on-road diesel as 15 ppm diesel (at a volume that is at
least 85% of its baseline volume) by June 1, 2006. Also, the regulations at §
80.553 allow a small refiner to extend its sulfur standards for gasoline to
December 31, 2010 if the small refiner produces 95% of its on-road diesel as 15
ppm diesel by June 1, 2006 (at a volume that is at least 85% of its baseline
volume).
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9.D Product Transfer Documents (PTDsVBills of Lading (BOLs)
9.1: D Please verify that the "product document requirements" of §80.590 do not apply to
transfers where an entity maintains custody of a batch of diesel fuel from one place in the
distribution system to another place (e.g., from a refinery to a pipeline or a pipeline to a
terminal), all owned by the same entity. It is understood that records must be retained
under §80.600(a)(7).
A: D Product transfer documents must be exchanged when a product changes custody.
A facility is defined as a location or series of location where custody does not
change, therefore product transfer documents do not need to be exchanged
between locations within a single facility.
9.2: D Must BOL's contain the exact words of this section? (§§ 80.590, 80.598)
A: D For parties upstream of the retail outlet or wholesale purchaser-consumer, the
PTDs required under the regulation may use product codes, except that the sulfur
content standard must appear in numeric form (15, 500 or >500). For PTDs to
retail outlets or wholesale purchaser-consumers, the exact language must be
used.
9.3: D Can codes be used to designate facility IDs on PTDs, or does the entire facility ID need
to be on the PTD?
A: D To ensure accurate handoff accounting under D&T, PTDs require the disclosure
of the full 9 character Facility ID (EPA assigned 4 character Company ID plus
EPA assigned 5 character Facility/Activity ID).
9.4: D Are separate PTD documents required for diesel or will general procedures currently in
place to meet gasoline PTD requirements be sufficient to meet PTD requirements for all
grades of diesel?
A: D While there is substantial overlap in PTD requirements for gasoline and diesel,
the requirements are not identical.
9.5: D What data points will EPA want/need to allow pipelines to develop necessary PTD
language?
A: D The information required on commercial PTDs includes identification of the
transferee and transferor (including names and addresses of the parties, and
registration number of transferor and transferee (as amended in the July 7, 2005
technical amendment to the regulations), the volume of product, the date and
location of the transfer, and identification of diesel fuel distributed by use
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designation (for use in motor vehicles, NR equipment, LM equipment, or NRLM
equipment) and the sulfur standard to which the fuel is subject. PTDs must
indicate the type of fuel- whether dieselfuel, heating oil, kerosene, exempt fuel, or
other. PTDs must also state if fuel is No. 1 or No. 2; dyed or undyedfuel; and
marked heating oil, marked LM, or unmarked fuel. Where a party delivers or
receives fuel that has two different designations (but a uniform sulfur content),
parties must use separate PTDs for each usage designation. At the point where
fuel is taxed or dyed/marked, and for subsequent transfers, the PTD must indicate
the applicable fuel uses as well as the standard. This is not an exhaustive list of
the requirements, a complete and detailed description of the specific requirements
is located in §80.590.
9.6: D On the designate and track approach, is any specific information required to be written on
the Bill of Lading (BOL) at the truckload rack?
A: D Section 80.590(d) provides that product codes may be used if such codes are
clearly understood by each transferee (so long as the sulfur content standard,
stated numerically in parts per million, is included), except that the information
required by § 80.590 to be conveyed to truck carriers, retailers, wholesale
purchaser-consumers and mobile refuelers must be stated verbatim. See also §
80.590(g).
9.7: D If a retailer or wholesale purchaser-consumer does not dispense early credit 15 ppm
sulfur cap motor vehicle diesel fuel, is June 1, 2006 the effective date for the product
transfer document (PTD) requirements at § 80.590 per § 80.500(e) or § 80.592(a)(l) or §
80.530(a)(2)?
A: D The PTD requirements apply to all motor vehicle dieselfuel under the highway
diesel rule (both 15 ppm and 500 ppm) as of June 1, 2006. Prior to June 1, 2006,
the PTD requirements apply only to transfers involving early credit fuel. Under §
80.590(h) and (i), starting June 1, 2001, any highway dieselfuel transfers that are
subject to the early credits provisions of§ 80.531(b) or (c) are subject to the PTD
requirements. The 5 year retention period under § 80.592(a) applies to all
required PTDs under the rule, including PTDs required under the additive
provisions (see § 80.591).
9.8: D Some pipelines operate a fungible batch system and some operate a segregated batch
system. A shipper on a segregated batch system receives the batch that it tendered at the
origin point. The pipeline has the responsibility to maintain batch quality while the batch
is in its custody. If the pipeline delivers to third party tankage, the terminal operator is
responsible for segregating interface and delivering to tankage. It is unclear where the
pipeline's responsibility begins and where it ends, which could drastically affect the
pipeline's sampling and testing program. (How is responsibility divided under the current
500 ppm program?)
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A: D Pipelines are carriers under the regulations and as such have responsibility to
ensure the product meets the standards while the pipeline has custody or title, and
to provide appropriate product transfer documents to any downstream parties to
whom it transfers custody. The responsibility to account for downgrade is a
function of the point at which custody of the fuel is deemed to take place. This
point is a function of contracts between the different entities. Each entity is
responsible for all downgrading that occurs when it has custody.
9.9: D At truck loading terminals what additional information needs to be provided to
implement ULSD? Specifically, what information needs to be printed on the tickets and
what information needs to be included in the quarterly report?
A: D The information detailed in §§ 80.590 and 80.591 needs to be included on all
PTDs. The information that must be included in quarterly reports is stated in
detail in § 80.601 (a). PTDs can serve as commercial documents (such as
"tickets "), as long as they contain all of the information that is required by EPA.
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10. D Documentation
10.1: D Section 80.600(a)(10) says, "Any refiner or importer shall maintain copies of all product
transfer documents required under §80.590. If all information required in paragraph
(a) (6) of this section is on the product transfer document for a batch, then the provisions
of this paragraph (a) (10) shall satisfy the requirements of paragraph (a) (6) of this
section for that batch." Does that mean that if a refiner or importer has a PTD containing
the information no other record is required? That seems unneeded. Does that paragraph
mean something else?
A: Section 80.600(a)( 10) first requires that product transfer documents under §
80.590 be maintained by refiners and importers. It then states that if such
product transfer documents contain all the information required under paragraph
(a) (6) of § 80.600 for each batch, then no other separate recordkeeping is
required for that batch in order to satisfy the requirements of paragraph (a) (6).
10.2: D Must records be retained if only #2D 15 PPM is received? In general, are requirements
of § 80.600(b) applicable if the distributor only receives #2D 15 PPM? [§§
80.600(b)(l)(ii) and 80.600(b)(2)]
A: D Yes, records must be retained for this fuel (unless the fuel is dyed, marked, and/or
taxed or in the Northeast/Mid-Atlantic Area or Alaska) for at least five years. In
this case, the D&Treports would confirm that the distributor did not handle any
other fuel and did not violate any of the restrictions on redesignating fuel. The
D&T reports from this distributor would also be used in evaluating compliance
by the parties before and after this party in the distribution system. This
distributor is only one step in a chain of fuel hand-offs, and the D&T system is
designed to use information from each party to a hand-off to ensure compliance
by all of the parties in the chain of distribution. Further, parties should retain
records for defense purposes.
10.3: D a) Are diesel batch numbers kept separate from gasoline batch numbers?
b) Must numbers be chronological and contiguous?
c) Are zero volumes allowed? [§ 80.602(b)(2)]
A:U a) Yes. §§ 80.592, 80.593, 80.602(b)(2) and80.604 require that the batch
numbering conventions set forth in § 80.65 (d) (3) be used for diesel fuel.
The regulations require batch numbering for diesel fuel to be separate
from batch numbering for purposes of the gasoline rules (RFG/anti-
dumping, gasoline sulfur), using the same batch numbering conventions
for diesel as are used for gasoline.
b) D Numbers must be chronological and contiguous- under § 80.65(d)(3), the
1st batch for the year is number 1, with ". . . each subsequent batch during
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the calendar year being assigned the next sequential number. " Each
batch number also includes the EPA company and facility registration
number and the last 2 digits of the year in which the batch was produced.
c) D Yes, zero volumes are allowed. For example this would be appropriate
where a batch is tested, then re-blended and retested before any of it is
transferred. Back-up records should be kept so that an adequate
explanation exists regarding why there was a zero volume.
10.4: D A tank truck common carrier picks up a load of ULSD at a Shell terminal and delivers it
to a Flying J truckstop. The carrier only provides a transportation service, does that
carrier have any registration or reporting duties?
A: D No, the carrier does not have registration or reporting duties as long as taxes
were assessed (in the case of highway fuel) or dye was added (in the case of
NRLM) at the terminal. There are recordkeeping andPTD requirements,
however. These requirements are listed in detail in §§ 80.590 and 80.592 of the
regulations.
10.5: D A trucking company stores ULSD at its terminal for use in its own truck fleet. Does it
have any registration or reporting requirements?
A: D No, but there are recordkeeping requirements; and such an arrangement may be
considered, by definition, a "Wholesale Purchaser-Consumer ".
10.6: D Is it correct that below the rack, the primary recordkeeping mandate is production and
retention of PTDs with no reporting obligations?
A:U Yes, if requisite dye/marker has been added and/or taxes were paid (see QA 10.4,
above).
10.7: D Do product codes have to contain the sulfur amount if a description accompanies the
code? Will EPA provide examples of code structure?
A: D The numeric designation of 15, 500, or >500 must appear on all product transfer
documents for MVNRLM. The rule (at § 80.590(d)) currently requires that the
numeric designations appear in the PTD 's code, however, we intend to revise that
provision in a subsequent technical amendment to allow the designation to be
stated anywhere on the PTD, not just in the code (but the numeric designation
must be clearly marked on the PTD somewhere). We will also allow product
codes on PTDs to contain another 'symbol' in place of the numeric designation if
that symbol is defined somewhere on the PTD (e.g., to denote that a fuel meets the
15 ppm standard, "X" can be included in the code in place of "15", as long as it
is clearly noted on the PTD somewhere that "X = 15 ppm ").
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10.8: D What compliance and reporting requirements are there if a company throughputs
highway diesel at a 3rd party's terminal?
A:U Under the D&T regulations, the custody holder is the responsible party, and must
comply with all recordkeeping and reporting requirements. In this example, it
would in most cases be the terminal owner. However, in order to ensure
compliance for the terminal as a whole, they may need to place their own
compliance requirement(s) on the lessee.
10.9: D Must individual batch reports be submitted for highway diesel (15 or 500 ppm)? Is this
requirement for NRLM diesel only?
A: D With respect to highway diesel, batch reports are required for participants in
early credit generation and/or refiners covered under a Temporary Compliance
Option, per §80.581.
10.10: Is registration for an EPA number at a terminal required, and is it in addition to present
TCN#?
A: D Yes, registration is required. The TCN # is used for the IRS system; the EPA
D&T system is not based on the IRS model, but rather on our existing gasoline
reporting programs. Facility ID numbers are assigned by facility, however, an
aggregated facility or a single facility that serves many roles would need to state
those activities (such as: refinery, importer, breakout (passthrough) terminal
and/or pipeline, and truck loading terminal) in its reporting documentation.
Please see the "Diesel Fuel Reporting Forms" page for registration forms and
information, at:
http://www.epa.gov/otaq/regs/fuels/dieselfms.htm
10.11: a) What is the difference in reporting requirements for additives containing greater
than 15 ppm, as well as those containing less than 15 ppm, sulfur? D
b) Will batch recertification change based on additive sulfur content? D
A: D a) There is no reporting requirement for additives, onlyMVNRLM.
b) D Redesignation of a batch due to downgrading is limited to 20% of volume
by facility. Additives having a sulfur content greater than 15 ppm that are
used in ULSD must meet the standards and identification requirements of
§ 80.521(b).
10.12: What registration and reporting requirements exist for 3rd party terminals and other
service providers that never actually own the product with regard to ULSD?
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A: D Under the designate and track regulations, custody holders are the responsible
party for registration, recordkeeping, and reporting.
10.13: Since all entities in the distribution system will be required to report data, this creates
double reporting as both the transferor and transferee would be reporting the same
volume. Are there any plans or safeguards to be in place to allow a reporting entity to
check and/or verify volumes that other entities have assigned to their entity or facility?
A: D There are no plans/requirements being put in place by EPA. Businesses may
handle such a program themselves, as they see fit, as part of a quality assurance
program.
10.14: Has EPA defined the reporting application or process for the designated volumes reports?
Will alternate methods, such as EDI or spreadsheet be allowed for submissions?
A: D Please see the "Diesel Fuel Reporting Forms " page for applications, and all
other reporting forms, at:
http://www.epa.gov/otaq/regs/fuels/dieselfms.htm
Alternate methods- spreadsheets or flat files- may be used for submissions.
10.15: Will paper (bubble) reports continue to be required for individual batch submissions or
will alternate methods, such as EDI or spreadsheet be allowed for submissions?
A: D No, as stated above in question 10.14, paper/bubble reports will no longer be
required. Submissions will be in spreadsheet/flat file format.
10.16: Will EPA want electronic copies of quality control testing charts?
A: D EPA will want the original records (including test records). The original charts
can be provided electronically, or we will accept paper printouts of electronic
copies (or other hard copies).
10.17: In the preamble, EPA states, "the reporting forms can be standardized and the review
process automated in such a fashion as to minimize the Agency resource requirements"
(page 39062). What is EPA's intent with regard to such standardization? According to
EPA, commenters stated that the information needed for D & T is already kept as part of
normal business practices (pages 39061, 39069). What is EPA's understanding of
"normal business practices" and the way this information is already kept? How does this
mesh with EPA's statement on standardization? What are EPA's expectations of D & T
documentation? How will EPA address the different ways that facilities "already keep"
the documentation? What is EPA's expectation with regard to PTDs? Is EPA looking to
create or require a standard PTD? Will EPA request electronic copies of PTDs?
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A: D We are proposing a flexible reporting system which historically has been well
received by industry because of its ease of use. No special software will be
required (reports should be submitted in spreadsheet or flat file format).
10.18: What kind of local record keeping (at the terminal) will be required versus a centralized
record keeping process?
A: D Sections 80.592(e) and 80.602(e) require that the required records be made
available "on request by EPA. " The location where the records must be kept is
not specified by the regulations. EPA interprets this requirement to require that
records should normally be made available the same day they are requested. If
they are stored off-site, EPA may request photocopies or facsimile copies be
supplied pending receipt of original records, or EPA may visit the off-site facility
to obtain the records. If voluminous records are requested by EPA, they must be
provided within a reasonable time, which will generally be specified in the
information request.
10.19: Will the terminals or pipelines have to provide consignees to interconnecting pipelines
any documentation, or can they forward documentation from the source, or is no
documentation an option?
A. D When a party transfers custody of designated fuels in the distribution system the
transferor must provide a PTD to the new custodian. PTDs contain a variety of
information, some of which will not be included in information generated by prior
sources of the fuel. No documentation is not an option in cases where a PTD is
required.
10.20: Where (specific certified and express mailing addresses at EPA) should refiners and
importers send the 2003, 2004 and 2005 pre-compliance information required in §
80.594?
A: D Certified mailing address for pre-compliance reports is,
Attn: Diesel Sulfur (6406J)D
1200 Pennsylvania Avenue NWD
Washington, DC 20460 D
Express (overnight/commercial carrier) mailing address for pre-compliance
reports is,
Attn: Diesel Sulfur Pre-compliance ReportD
c/o: Chris McKenna (202-343-9037)0
1310 L St. NWD
Washington, DC 20005 D
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Also, please send electronic copies of all documents, if possible, particularly the
spreadsheet template that EPA developed for reporting estimates of 15 ppm production,
500 ppm production and credit generation and usage. Electronic copies can be
submitted on a disk or e-mailed to mckenna. chris@epa.gov.
10.21: Not all on-road diesel fuel must be 15 ppm starting in 2006. tte phase-in, small refiner,
and geographic provisions of the final rule seem to assure that at least some 500 ppm
diesel fuel will be in the market post-2006. But, for retailers and wholesale purchaser
consumers, whether 500 ppm will be available in substantial quantities in their marketing
areas is an important factor in deciding whether to invest in additional tankage in order to
be able to offer customers both 15 ppm and 500 ppm diesel fuel. How can retailers and
wholesale purchaser consumers gain information on the amount of 500 ppm that will be
produced in their PADD post-2006?
A: D Refiners and importers are required to annually update EPA on their progress
toward producing 15 ppm sulfur diesel fuel through the pre-compliance reports.
We will produce a summary and analysis document of the pre-compliance reports
submitted each year (the Summary and Analysis of both the 2003 and 2004 pre-
compliance reports can be found at: http ://www. epa. gov/otaq/diesel .html The
annual summary and analysis reports will provide information, summarized and
aggregated on a PADD basis, describing the volumes of 15 ppm and 500 ppm
highway diesel planned to be produced, and estimates of the number of credits
that refineries expect to generate or use. Further information on the business
plans for individual parties in individual markets would need to be pur sued
directly by retailers and whole sale purchaser consumers.
10.22: EPA released its status report on the on-road diesel sulfur rule earlier this year (2002).
From a retailer's point of view, there wasn't much helpful information in this status report
in terms of which refiners are going to make 500 ppm in 2006 and beyond and in what
qualities. Will these reports by refiners to EPA provide estimates of 15 ppm diesel fuel
production? Or of 500 ppm diesel fuel production?
A: D Refiners and importers are required to submit annual pre-compliance reports
under the highway rule from 2003 through 2005, and under the nonroadrule as
late as 2011. These reports must contain estimates of the volumes of 15 ppm
sulfur fuel and 500 ppm sulfur fuel that will be produced at each refinery, and, for
those refineries planning to participate in the trading program, a projection of
how many credits will be generated or must be used by each refinery. These pre-
compliance reports must also contain information outlining each refinery's
timeline for compliance and provide information regarding engineering plans
(e.g., design and construction), the status of obtaining any necessary permits, and
capital commitments for making the necessary modifications to produce low
sulfur highway diesel fuel. Much of this information will be claimed as
confidential business information (CBI). As a result, we will be unable to release
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individual refiner plans unless they give permission to do so. However, we do
report the information in an aggregated, non-confidential format. Refiner-
specific information will have to be pursued through individual business
relationships.
10.23: What is the purpose of requiring record keeping and reporting for early compliance. If
EPA is seeking to encourage early compliance these requirements may be burdensome
for certain marketers?
A: D Record keeping and reporting for early compliance is required to ensure that 15
ppm credits are valid, as per § 80.531.
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11. D Testing
11.1: D Per § 80.604(d)(5), must aromatics be reported (and run) if compliance is based on cetane
index?
A: D No. Under §§ 80.510 and 80.520, MVNRLMdieselfuel may comply with either
the cetane index or the aromatics standard.
11.2: D For testing purposes at a terminal level, must each tank that is filled be tested or is it
sufficient to test just the incoming pipeline shipment?
A: D There are no testing requirements downstream of the refiner and importer to
verify that the sulfur content fuels received by a distributor is consistent with that
reported on the PTD. However, every party in the fuel distribution chain that has
had custody of a fuel batch with a sulfur content found to be excess of the sulfur
standard reported on the PTD could be held presumptively liable for the resulting
violation if they lack sufficient affirmative defenses. The issue of whether testing
the sulfur content of the incoming pipeline shipment rather than that of each
storage tank into which the fuel is delivered to establish the sampling and testing
element of a terminal owner's affirmative defenses will be evaluated by EPA on a
case by case basis. In instances where the tanks being filled with 15 ppm diesel
fuel have been dedicated to 15 ppm diesel use, it will be more likely that pipeline
receipt testing would be sufficient and that a test on the tank after the
introduction of the fuel would not be necessary. In cases where the tank is
alternately used to store higher sulfur fuel as well as 15 ppm diesel fuel, a test on
the tank after the introduction of the fuel may be needed.
11.3: D Do terminals need to test every batch?
A: D Terminals are not required to test terminal tanks after every receipt of product.
However, to establish a defense to presumptive liability to a violation, a terminal
must establish each defense element. One such defense element is that the
terminal had a quality assurance program, including a periodic sampling and
testing program. Since terminals receive very large volumes of product in each
receipt, an appropriate quality assurance program might require sampling and
testing after each receipt of 15 ppm product. Note that terminals would have to
test every batch in order to establish a defense if it is adding greater than 15 ppm
sulfur content additives (or conduct the VAR approach under § 80.614, if the
additive is a static dissipater additive).
11.4: D Should testing at a terminal be done at the rack after injection of any additives?
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A: D There are no sulfur testing requirements downstream of the refiner/importer.
However, to meet their affirmative defense to presumptive liability, parties that
blend > 15 ppm sulfur additives into diesel fuel subject to the 15 ppm sulfur
standard must conduct aperiodic sampling and sulfur testing program after the
additive is added to the fuel (see 40 CFR 80.613(d). Alternative affirmative
defense requirements exist for blenders of > 15 ppm anti-static additives that are
based on a volume accounting reconciliation system (see 40 CFR 80.614).
11.5: D Will EPA be testing diesel for compliance at the retail/vehicle level?
A: Yes, EPA will be testing diesel for compliance at the retail/vehicle level.
11.6: D Please elaborate on fuel tests at retail- what frequency would be recommended?
A: D Retailers are not required to perform testing in order to have a defense to
presumptive liability. However, to establish a defense to a violation distributors
must, among other things, conduct aperiodic sampling and testing program. For
a truck distributor, the best place to take samples may often be the tanks of retail
outlets it delivers to. Retailers should probably sample and test after tank
transition from a higher sulfur product to 15 ppm product, to confirm that the fuel
in the tank is meeting the 15 ppm standard. Otherwise, if a violation is detected
for some time subsequent to a tank transition, it may be difficult for the retailer to
demonstrate that it did not cause the violation.
11.7: D When does the 2 ppm tolerance apply?
A: D The 2ppm downstream sulfur test tolerance (§ 80.580(d)) applies at all locations
downstream of the re finer/importer.
11.8: D If XYZ Refining has a branded retailer who independently owns his/her XYZ Gas
Station, does XYZ Refining have a duty to test ULSD at XYZ Gas Station?
A: D A branded refiner is not required to test gasoline at its branded retail outlets
whether or not the retail businesses are owned by independent third persons.
However, under § 80.612, branded refiners are liable for violations at branded
retail outlets. Under § 80.613, for branded refiners to establish a defense to such
violations, it must, among other things, show that it has aperiodic sampling and
testing program at the branded retail outlets.
11.9: D At what point in the distribution/receipt of ULSD will terminals need to sample/test for
sulfur? If terminals do not test for sulfur content at the rack will they be able to assert an
affirmative defense in the event that contaminated fuel is discovered at the retail level?
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A: D Under the diesel sulfur program, there is no one time or physical location that a
distributor must utilize for sampling. The party must use its knowledge of the
distribution system, and information regarding each receipt of product (e.g.,
whether the shipment may include fuel that is very close to an interface with
higher sulfur product) to determine when and where to sample. However, as a
general matter, we believe that a terminal should take samples during and/or
after receipt of new product into the tank so that if there is a problem, it can be
discovered and remedied before the product is distributed further downstream. If
there is reason to believe that piping or a tank may contain high sulfur product
then that may affect both sampling strategy and actions to prevent a potential
violation. This is but one example of many possible situations. In regards to
terminals not testing for sulfur content at the rack, if a terminal does not conduct
a sampling and testing program, it will likely be difficult to be able to establish a
defense to presumptive liability.
11.10: If tests are done upon receipt from the pipeline, how will PTDs reflect sulfur
contamination added by the terminal through common piping, manifolds or at the rack?
A: D These tests would not address contamination by the terminal. Also, PTDs do not
need to specify the precise sulfur content of the fuel, only that the fuel is
compliant with the applicable sulfur standard. If minor contamination occurs,
but the fuel still meets the applicable standard, it is not considered a violation,
nor does EPA require it to be reported on a PTD.
11.11: With regard to test methods, would EPA consider the following two approaches to be
equally sound in terms of a defense to presumptive liability? (1) qualify the test method
chosen for downstream oversight purposes per the precision and accuracy criteria in the
rule; or, (2) correlate the test method chosen for downstream oversight purposes to a test
method qualified per the performance based test method criteria? The methods appear to
be equivalent and acceptable approaches.
A: D No, for the testing of fuel for compliance with the 15 ppm sulfur standard, we do
not consider the two approaches to be equivalent. The second approach listed is
not an option for approval of a test method under the diesel fuel regulations, and
therefore testing with methods not approved under § 80.581 and § 80.585 would
not be considered an adequate defense to presumptive liability. Test results from
test methods that have not been approved under the regulations might be
considered as evidence of compliance or noncompliance with the standard, but
use of the unapproved method would not be considered as meeting the periodic
sampling and testing requirement for defense purposes; nor would use of an
unapproved method be considered to have fulfilled the requirement for refiners
and importers to test every batch. Testing for 500 ppm fuel has a different
situation.
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11.12: Is there a process, or a need, to certify a tank of 15 ppm sulfur content highway fuel that
is not located in a refinery? Is it a single sample or Top-Middle-Bottom samples? Must
it be by lab analysis?
A: D Parties in the distribution chain downstream of the refiner or importer are not
required to test motor vehicle dieselfuel. However, in order to establish a
defense to any violation, downstream parties must conduct a quality assurance
program, including sampling and testing. The fuel must meet the standard on a
per-gallon basis. An appropriate field method may be used for downstream
quality assurance testing. The regulations do not specify which testing method
must be used for downstream quality assurance testing. The sampling methods
prescribed by the rule in § 80.580 would be appropriate for purposes of quality
assurance sampling under § 80.613(d)(l).
11.13: Terminal operators believe it is appropriate for them, even when acting as a "downstream
facility," to ensure that the diesel fuel leaving the terminal gate complies with the 15 ppm
sulfur standard. Terminal operators recommend that EPA determine compliance when
the product leaves the facility, not when the product is still in tank before distribution.
However, if such testing and determination is to be conducted on product in storage, the
EPA should use an "average" of the sulfur content of the tank to determine compliance.
A: D Fuel represented to meet the 15ppm standard that is stored, transported,
dispensed, sold, offered for sale, supplied or offered for supply at a terminal must
meet the 15ppm sulfur standard on aper-gallon basis (not on an average basis).
Terminals are not required to perform sampling and testing except as a defense to
liability, but we strongly concur that responsible terminal operators will conduct
regular sampling and testing - and that the appropriate frequency will probably
be after each receipt of product.
11.14: Will EPA have an oversight testing program for 15 ppm motor vehicle diesel fuel similar
to the RFG gasoline survey program?
A: D The RFG survey program is a statistically valid sampling and testing program
that is performed by an independent contractor who is paid for by participating
refiners. Its purpose is to show whether the RFG in each control area meets
standards on average. No such program exists under the highway or nonroad
diesel regulations. However, as with other fuels programs, EPA plans to conduct
its own sampling and testing at all levels of the distribution system to monitor
compliance with the dieselfuel standards.
11.15: As EPA is aware, terminals often serve in two different capacities - (1) as an import
facility; and (2) a downstream facility when product is received from a U.S. refiner or
importer. As such, terminal operators believe that the 2 ppm testing tolerance would only
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apply to those operations of the terminal when it is acting as a "downstream facility."
Would EPA please confirm this interpretation.
A: D The 2 ppm test result adjustment of§ 80.580 (d) does not apply for fuel at a
facility that is acting in the capacity of an import facility. However, fuel that is in
a terminal tank downstream from the refinery or import facility is eligible for the
2 ppm test result adjustment.
11.16: Does other testing need to be done to ship No. 1 diesel and redesignate it as jet to get
ULSD credit?
A: D No other testing would need to be done. However, the anti-downgrading
provisions would apply if a downgrade (to 500 ppm highway diesel) were to
occur. The situation that the question is asking about would not affect the
person's volume balance; if the reverse were to occur-jet fuel was redesignated
as No. 1 diesel fuel- the volume balance would be affected.
11.17: Are there regulations that require sampling and testing by each facility, or do you just
need a sampling and testing program to establish a defense?
A: D In general, the only parties that must sample and test are refiners and importers;
under § 80.581, they must sample and test each batch of motor vehicle or NRLM
fuel subject to the 15 ppm sulfur standard that is produced or imported.
However, a downstream party redesignating kerosene fuel for use as 15 ppm
motor vehicle or NRLM fuel when such fuel is not accompanied by a PTD stating
that it meets the 15 ppm standard, must have test results (see § 80.525). Likewise,
any party remedying a contamination of fuel originally designated as 15 ppm
fuel, or upgrading fuel not designated as 15 ppm fuel to fuel that meets the 15
ppm standard must sample and test before distributing the fuel as fuel that meets
the 15 ppm standard.
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12. D Enforcement
12.1: D What will happen if you refuel a 2007 truck with contaminated fuel? Are there any
engine or aftertreatment issues? If a 2007 truck is misfueled, is there any legal liability
for the end-user?
A: D If a MY 2007 or later truck is misfueled once, it will have significantly higher PM
emissions during operation on that fuel, but there should not be any significant
long-term emissions or engine durability concerns as long as the truck is then
fueled with the proper fuel. A wholesale purchaser-consumer or end user faces
presumptive liability if it misfuels vehicles or equipment with fuel not meeting
applicable standards. However, a vehicle operator fueling at a retail outlet from
an appropriately marked pump is not liable for the misfueling caused by the
retailer or other party. A wholesale purchaser-consumer (fleet operator with its
own fueling facility- see definition at 40 C.F.R. § 80.2) may be able to establish a
defense if the fuel was contaminated by an upstream party and the wholesale
purchaser-consumer can otherwise establish in its defense elements that it did not
cause the violation and that product transfer documents account for the product
and demonstrate the product was compliant.
12.2: D EPA appears to focus enforcement on the custodian of the fuel, even though a
compliance violation may well have occurred further upstream. Will EPA automatically
require custodians to raise a defense and overcome a presumption of liability for simply
possessing off-spec fuel?
A: D The facility where the violation is found and all parties in the distribution system
upstream of that facility will be presumed liable. However, each party has the
opportunity to establish a defense to the presumptive liability. For example, an
upstream distributor who takes custody of a fuel would be presumed liable, and
would need to demonstrate that it did not cause the violation- that product
transfer documents account for the fuel and show that the fuel was apparently in
compliance when it was in its custody and that it has an adequate periodic
sampling and testing program (regardless of whether or not it tested that specific
batch of fuel). However, if the fuel custodian is a retailer or wholesale
purchaser-consumer, they would not be required to have aperiodic sampling and
testing program in order to establish a defense.
12.3: D The regulation requires an entity to conduct an investigation into the cause of a quality
control testing violation. What evidence will EPA require for purposes of establishing
that an adequate investigation was conducted?
A: D EPA is not in a position to discuss what may constitute an adequate investigation
in every conceivable scenario. An adequate investigation is whatever is required
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to correct the cause of the deviation and to assure that the method performance
has been restored to statistical control.
12.4: D The rule states that a party that is initially deemed liable for a violation of the rule will
not be deemed liable if the party demonstrates: (1) the violation was not caused by the
party; (2) product transfer documents show that the violating product was in compliance
when it was under the party's control; (3) the party conducted a quality assurance
sampling and testing program. The regulations, at § 80.613, do not specifically require a
party to prove all three factors (there is no "and"). However, the preamble (page 39104)
says that a party must show 1, 2 "AND" 3. It should be enough to show that the party did
not cause the violation (first prong). How will EPA apply this test?
A: D The preamble is correct- a party that is presumed liable must establish all three
elements (except for retailers and wholesale purchaser-consumers, which are not
required to have aperiodic sampling and testing program). This is consistent
with all of the fuels rules in Part 80, and was corrected in a recent technical
amendment (July 7, 2005). For example, where a truck distributor drops 500
ppm sulfur content fuel into a retailer storage tank that supplies a 15 ppmpump
stand, both parties will be presumed liable. However, the retailer may establish a
defense- even if it subsequently sold the fuel as 15 ppm fuel- if it can demonstrate
that it did not cause the violation and that the PTDs account for the fuel as being
15 ppm fuel, and thus show the fuel to be in violation. (In this example, if the
party in question was not a retailer, it would also need to demonstrate- regardless
of whether or not it tested that specific batch of fuel- that it has an adequate
sampling and testing program in place). If the product transfer document stated
that the fuel was 500 ppm fuel, then the retailer cannot establish a defense unless
it immediately stopped sale and took actions (probably in association with the
distributor) to remedy the violation. If the retailer sells the product as 15 ppm
fuel even though the product transfer document shows 500 ppm fuel was dropped,
then it cannot meet the second element of its defense.
12.5: D Under the rule, sampling and testing is voluntary for downstream parties, however, to
establish a defense to presumptive liability, they will engage in periodic testing. If a
downstream party is not in the midst of periodic testing and is found in possession of an
off-spec batch, then the party will not be able to meet all of the three elements required
for establishing a defense (see question 12.4, above). It would appear that it might be
impossible to rebut the presumption if a party is not in the midst of scheduled QC
sampling and testing. Is this correct?
A: D If a party conducts no quality assurance/sampling and testing, it cannot establish
a defense. However, a party can satisfy the periodic sampling and testing
element of its defense by demonstrating that its periodic sampling is done at a
frequency that is appropriate given all of the circumstances. It is not necessarily
required that the product EPA finds to be in violation was actually sampled and
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tested. However, for parties such as terminals, an adequate sampling frequency
may require sampling after each receipt of product. EPA will investigate whether
other parties may be liable, but each party must be able to establish a defense.
12.6: D The end user has no way of knowing whether they are refueling with diesel in excess of
the 15 ppm sulfur regulatory limit. Is there a way to introduce some flexibility in the
enforcement of the requirement that no fuel in excess of 15 ppm sulfur be introduced into
a 2007 (or later model year) truck?
A: D Flexibility inherently exists in the fact that everyone involved in the production
and distribution chain of each batch of fuel is presumptively liable, which will
help to limit the occurrence of fuel that does not meet the 15 ppm standard (or
other applicable designation).
A person fueling a vehicle at a retail outlet self-serve pump will not be liable for
misfueling if the person does not cause the violation. For example, if the
misfueling occurs because the retail outlet has mislabeled the pump stand or
because the retailer or its distributor have contaminated the fuel with high sulfur
product, the retailer and parties upstream may be liable, but the self-serve
customer will not be liable unless it played some part in causing the violation.
However, if, for example, a person fuels a 2007MYtruck at a self'serve pump
labeled as dispensing 500 ppm fuel, the end user is liable.
12.7: D Will testing documentation from a receiving pipeline be sufficient evidence of
compliance with the sulfur standard to continue delivery? Will this document track
through to a truck load without additional testing and be sufficient to establish a defense
to liability for a violation of the sulfur standard?
A: D EPA will sample and test diesel fuel at all levels of the distribution system. If, for
example, the sulfur test result for a particular sample downstream of the refinery
exceeds the 15 ppm sulfur standard (after the adjustment under 40 C.F.R. §
80.580(d)), that fuel will be in violation regardless of any prior test result
demonstrating compliance. Note that fuel from each refiner and each pipeline is
frequently commingled in the fungible distribution system. Fuel may be
contaminated in the pipeline or in storage tanks during shipment.
Where a violation is found, the party having custody of the fuel that is found in
violation, and any party upstream of the facility where the violation is found is
presumptively liable. However, each party may establish a defense by meeting
each of its defense elements. For example, a distributor may establish a defense
to a violation found at a retail outlet if it can show that: it did not cause the
violation; product transfer documents account for the fuel and indicate that the
violating product was in compliance with applicable requirements when it was
under the party's control; and the party conducted a periodic sampling and
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testing program and other quality assurance efforts. Under § 80.613(d)(4), truck
carriers can rely on sampling and testing conducted by another party, but must
make other appropriate quality assurance efforts to meet this defense element.
Parties other than tank truck carriers will need to conduct their own periodic
sampling and testing, and will not be able to rely in whole on testing by parties
upstream in the distribution system.
12.8: D Will appropriate processes and QA/QC oversight be acceptable defenses against
enforcement for off-spec product? Testing shows that the pipeline does not add sulfur
from the steel. If base testing is done to identify protection volumes, and operational
records support no accidental contamination, will this be sufficient? Could this preclude
many proprietary and batched pipelines from needing on-line analyzers and extensive
sampling process?
A: D Parties are presumed liable for a violation if a noncompliant fuel is found to be in
their control, or if they are in the distribution system upstream of the facility
where the violation is found. Downstream parties have a defense to presumptive
liability if: (1) the party did not cause the violation; (2) PTDs establish that the
fuel was in compliance while the fuel was under the party's control; and (3) the
party conducted an adequate QA program, including sampling and testing.
While refiners, importers and transmix processors are required to test each batch
of product represented to meet the 15 ppm sulfur content standard, most
downstream parties are not required to test every batch. Testing for downstream
parties is voluntary. Downstream parties may conduct periodic sampling and
testing for quality assurance purposes in order to establish a defense to liability
for alleged violations.
Each company should consider its distribution system and its own operations in
determining the appropriate sampling and testing frequency. Factors that EPA
believes are relevant include: the results of previous sampling; the volume of fuel
in a particular shipment (the larger the volume, the greater the justification for
testing); the degree of confidence in the quality of the product when it was
received; and the opportunity for violations while the fuel was in possession of
the party (e.g., the opportunity for commingling with higher sulfur product). For
example, the volume of shipments into terminals are normally relatively large. A
terminal that samples and tests after each receipt of 15 ppm sulfur content
product will likely be able to meet its periodic sampling and testing defense
element, and will have significant evidence regarding the "didn 't cause " defense
element as well. However, it should be noted that a terminal could demonstrate
that all product received meets the applicable specifications, and still cause a
violation to occur subsequent to receipt. Also note that there are variations to the
defense elements for certain parties, such as parties who blend additives having a
sulfur content exceeding 15 ppm to fuel subject to the 15 ppm standard.
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Note that the rule requires QCfor sulfur measurement instrumentation. If
instruments are out of control requirements, then all samples taken since the
instrument was last in control must be retested. QC records must be retained for
5 years.
12.9: D Will pipelines have an exempt refiner defense if higher than standard sulfur is located in
their systems?
A: D The fuel sulfur level of a batch of fuel must conform to the way it is designated. If
a pipeline has fuel that is designated as 500 ppm or 15 ppm sulfur, and it does not
meet the designated level, then it is noncomplying. It is not a defense to claim the
fuel should have been designated otherwise by an upstream party.
12.10: What steps must a retailer/distributor take to assure that it is not liable for the sale of
off-spec motor vehicle diesel fuel subject to the 15 ppm standard?
A: D As discussed in questions 4.35 and 12.18, retailers have certain affirmative
requirements, including properly labeling pump stands, maintaining product
transfer documents and records regarding downgrading of 15 ppm diesel fuel.
Retailers must not cause the 15 ppm fuel to be contaminated by misdelivery of
high sulfur product into a storage tank for 15 ppm sulfur content product.
Retailers should carefully inspect product transfer documents at the time of
delivery to assure that the proper product is being delivered into each storage
tank.
We believe that retailers and distributors should work closely together to assure
that misdeliveries do not occur.
The liability and defense provisions of the 15 ppm motor vehicle diesel rule are
similar to those of previous fuels rules. Under § 80.613(a), a retailer and any
distributor or carrier in the distribution chain are deemed liable for a violation
found at the retail outlet (see § 80.612). A retailer will not be deemed in violation
if it can show that it did not cause the violation, and product transfer documents
account for the fuel found to be in violation and indicate the violating product
was in compliance with the 15 ppm sulfur standard when it was under the
retailer's control.
A distributor must also show that it did not cause the violation, that the product
transfer documents account for the product, and show that the product was in
compliance when it was under the distributor's control. A distributor could cause
a violation by various actions, including by misdelivery of high sulfur product or
commingling high sulfur product with 15 ppm product in a storage tank or
transport truck. To establish a defense, a distributor must also demonstrate that
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it has conducted a quality assurance program, including periodic sampling and
testing of the fuel it transports and delivers (see § 80.613(d)).
12.11: Many retailer/distributors use common carriers, rather than their own trucks, to transport
and deliver diesel. Under the diesel rule, what potential liability and defenses to liability
are in place for common carriers? If a common carrier does not follow the supplier's or
the retailer's location and/or delivery instructions, is the common carrier liable for the
misdelivery or the retailer?
A: D As with other EPA fuels programs, the highway and nonroad diesel sulfur
regulations utilize a presumptive liability structure. When a violation is found,
the party who owns, leases, operates, supervises or controls the facility where the
violation is found, and every party upstream of that facility, who supplied the fuel
to the facility where the violation is found, is presumed liable, absent a complete
defense to the violation.
Under the hypothetical, initially both the carrier and the retailer would be
deemed in violation. The carrier who delivers 500 ppm product to a retail outlet
tank when 15 ppm product has been ordered would not be able to establish it did
not cause the violation, and thus would remain liable.
The distributor who hired the common carrier would be liable if the product
transfer documents and other paperwork demonstrated that 15 ppm product was
ordered and 500 ppm product was delivered, and the distributor failed to take
reasonable steps to address the situation.
A retailer may establish its defense by 1) demonstrating it did not cause the
violation; and 2) and demonstrating that product transfer documents account for
the fuel found to be in violation and indicate that the violating product was in
compliance with the standards. A retailer does not have to conduct a quality
assurance sampling and testing program to meet its defense requirements.
However, a retailer must check the product transfer documents and properly
direct deliveries to the proper storage tank. In this hypothetical, the retailer may
have been able to detect the misdelivery at the time of delivery if it had checked
the PTD provided by the carrier. If the retailer does not check the PTD at the
time the misdelivery occurs (and if doing so would have shown that a misdelivery
had occurred), and sells the product as 15 ppm fuel, the retailer would not be
able to establish a defense.
12.12: How about after-hours deliveries? CMany retailers also are not open 24 hours a day and
received diesel deliveries during the night while its stores are closed. If a misdelivery is
made, what are the retailer's defenses?
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A: D As discussed above, regardless of when the delivery occurs, the retailer must
properly direct deliveries, and it must check the product transfer documents.
Where the retailer's employees will not be present during deliveries, both the
retailer and the trucker should take special care to prevent misdeliveries. A
product transfer document must be provided to the retailer with every transfer of
custody or title of the dieselfuel. The retailer has the responsibility to check the
transfer document to determine that fuel meeting the appropriate standards was
delivered to the appropriate tank. Therefore, if a misdelivery is made after-hours,
the retailer's employee should discover this misdelivery upon opening the outlet
the following day through an inspection of the product transfer document left by
the carrier (or possibly earlier if a transfer documents were received earlier). If
the retailer did not cause the misdelivery, and it discovers the misdelivery
through inspection of product transfer documents, and locks the pumps before
any dieselfuel is sold, then it will not be held liable for the violation.
Assuming the retailer properly instructed the distributor or carrier to deliver 15
ppm fuel to the appropriate storage tank, the carrier would not be able to
establish a defense. The distributor would also be liable for a violation if the
paperwork shows that a misdelivery was taking place (e.g., that 15 ppm fuel was
ordered but 500 ppm fuel was being delivered).
12.13: Refiners will produce diesel fuel that meets the 15 ppm standard at the refinery gate.
However, the rule mandates that the sulfur content remain at 15 ppm or below throughout
the distribution system until it is dispensed into a vehicle's fuel tank. Assume the PTDs
of the product are in order and properly identify the diesel as 15 ppm fuel, what potential
liability could a retailer have if the batch has been contaminated — in the pipeline, at the
terminal, or in the transport truck — so that the diesel received by the retailer exceeds the
15 ppm spec?
A: D In this case, a retailer would initially be presumed liable for the violation, but
could establish a complete defense to liability if the PTDs account for the fuel in
violation and show that the product was in compliance with the 15 ppm sulfur
standard; and the retailer did not cause the contamination. There may be cases
where an unscrupulous retailer purposely receives violating product delivered by
"midnight drops. " In some cases no product transfer documents cover the
product. The retailer in such cases would not be able to establish a defense, since
it would have caused the violations, and since not all product would be covered
by its product transfer documents.
Once the retailer becomes aware that the sulfur content of diesel product subject
to the 15 ppm standard exceeds the standard, it has an obligation to shut down its
retail pumps affected by the contaminated product until the violation can be
corrected. If the retailer did not shut it off, it would be liable for selling or
dispensing noncomplying dieselfuel.
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12.14: There is no field testing equipment commercially available to measure accurately sulfur
at these low levels and almost no retailers or wholesale purchaser consumers have the
type of on-site laboratories to conduct the testing. Thus, a distributor conducting a
quality assurance plan (QAP) would be forced to send a sample to an outside laboratory
for analysis and may not receive the test results for 24 to 48 hours. By this point, most if
not all of the off-spec fuel would have been sold by the retail outlets, making it
impossible to correct the non-compliance. Shouldn't a retailers or wholesale purchaser
consumers QAP under the 15 ppm motor vehicle diesel program be limited to examining
PTDs? If not, how does EPA expect distributors to comply with this defense
requirement?
A: D Retailers are not required to show an appropriate sampling and testing program
to establish a defense to liability. See § 80.613(a)(1)(Hi). However, distributors,
including truck distributors, who take title to the gasoline and deliver product to
their retail outlets, must conduct a quality assurance sampling and testing
program. These requirements are the same as in other fuels rules. A truck
distributor could rely, in part, on a proper quality assurance sampling and testing
program conducted by the terminal. But since there may be opportunities for the
trucker to obtain improper product (e.g., 500 ppm fuel instead of the 15 ppm fuel
that was ordered), or commingle high sulfur products with 15 ppm product, or
otherwise cause violations, sampling at locations downstream from the truck
loading terminal would be appropriate.
If a distributor must utilize an outside laboratory to obtain test results, and if it is
impossible for the distributor to obtain results quickly, the periodic sampling and
testing quality assurance program would still be useful in as much as it would
show if any violations are occurring and based on those findings the distributor
and retailer should act immediately to prevent future violations, and to remedy
the present violation if it still possible to do so by shutting down the affected
pump stands until the product meets standards. In this situation, if a violation
occurred and is discovered through the quality assurance testing, the distributor
and retailer may not be able to establish a defense to the violation based on the
delayed test results. However, EPA may take any such unavoidable delay into
account in its evaluation of the case. Moreover, the distributor could, as stated
above, limit its exposure, by obtaining as many terminal test results as possible.
Whether the distributor and retailer could meet the causation element andPTD
element would depend on the specific facts.
12.15: What responsibility, if any, does a retailer have to "police" its customers to assure that
they do not misfuel their vehicles — e.g., dispense 500 ppm diesel, if offered at the retail
outlet, into a 2007 or newer heavy duty truck? In many cases, diesel retail outlets are
large with multiple fueling locations and are staffed by entry level employees earning just
over the minimum wage. Does EPA expect these employees to "police" customers at the
retail outlet to assure that these customers are fueling properly? Also, please provide
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further clarification of the term "permit." at § 80.610(d)(l). For example, if a marketer
tells a self service customer that he can't fuel with 500 ppm but the customer continues, is
the marketer "permitting" the introduction of 500 ppm into a 2007 or newer model year
vehicle requiring 15 ppm? When exactly is a marketer "permitting" misfueling?
A:U Under the regulations, no per son shall "[ijntroduce, or permit the introduction
of, dieselfuel into model year 2007 or later diesel motor vehicles, and beginning
December 1, 2010 into any diesel motor vehicle, which does not comply with the
standards and dye requirements of§ 80.520(a)and (b). " Nor shall any person
"introduce or permit the introduction into model year 2007 vehicles, motor
vehicle dieselfuel that is identified as other than dieselfuel complying with the 15
ppm sulfur standard.... " Nor shall any person cause another person to commit
an act in violation of these prohibitions. 40 CFR § 80.610(d) and (e).
Therefore, a retailer will be liable if it, or its employees, introduce noncomplying
fuel into vehicles, or permit such introduction of noncomplying fuel into vehicles
or cause another person to violate the stated prohibitions. A retailer must
properly label pump stands and assure that product represented byproduct
transfer documents as meeting the 15ppm standard is delivered to the
appropriate storage tanks, and that product subject to the 500 ppm sulfur
standard is not delivered to such storage tanks. Moreover, a retailer should train
its employees that may fuel diesel vehicles regarding these prohibitions and the
pump stand labels and the corresponding labeling of filler inlets and dashboards
on model year 2007 and later diesel vehicles. Because there may be many
scenarios regarding how misfueling violations occur at retail facilities, a
retailer's liability for misfueling that occurs at its facilities will be evaluated on a
case-by-case basis.
Where a retailer has made reasonable efforts to prevent self-service customers
from misfueling (e.g., by cutting power to the pump as soon as the misfueling is
perceived) and has not in any way caused the misfueling (e.g., through
mislabelingpumps) the retailer would not be liable for "permitting" misfueling by
a self-service customer.
12.16: What about intentional misfueling by a customer? Cm the past, as new fuels have been
introduced in different parts of the country (CARB II Diesel in California; RFG in
Milwaukee), negative reactions by customers has been significant. Given the fact that
truckers may believe that use of 15 ppm diesel fuel will result in lower fuel economy, less
power, or mechanical problems with engine seals, some portion of customers might
refuse to purchase 15 ppm fuel for their new trucks. How can EPA expect a retailer to
stop a customer from intentionally misfueling his or her 2007 truck?
A: D A retailer is not responsible for misfueling by the customer unless the retailer or
its employees have introduced the fuel, or permitted or caused the violation.
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While intentional misfueling by a customer normally does not meet this criteria,
there may be scenarios where retail outlet employees' actions or failure to act
may permit or cause violations, even though the vehicle operator may actually
dispense the fuel into the vehicle.
We believe that responsible retailers will take reasonable actions to make
misfueling less likely to occur at their retail outlets. For example, a retail
employee could remotely shut off the fuel supply to a customer that it does see
misfueling, and explain to the customer that the retailer cannot permit misfueling
of vehicles at its stations since the retailer is potentially liable for such violations.
12.17: What about intentional misfueling by a fleet customer? CFor example, if a distributor's
fleet customer orders a load of 500 ppm on-road diesel fuel, which the distributor
delivers, and then the fleet customer intentionally fuels MY 2007 vehicles with the 500
ppm diesel, what is the distributor's potential liability? Does the distributor have the
responsibility to "police" its fleet customers to assure there is no intentional misfueling?
A: D A distributor is not responsible for misfueling by fleet customers unless the
retailer or its employees have introduced the fuel, or permitted or caused the
violation. Intentional misfueling by a fleet customer normally does not meet this
criteria. However, there may be scenarios where a distributor could be liable for
permitting or causing misfueling violations by a fleet operator. For example a
distributor who knows a fleet customer only has one diesel fuel storage tank, and
knows that the fleet operator has model year 2007 or later vehicles, may be liable
for permitting or causing misfueling if it delivers 500 ppm product to that
customer's storage tank, even if the customer ordered the 500 ppm product. We
believe distributors and carriers should work with retail and fleet customers to
ensure that fuel is delivered to the appropriate storage tank.
By "permitting" we mean that a retail station does not take reasonable actions to
stop the intentional misfueling that it witnesses a customer perform.
12.18: With the 15 ppm maximum sulfur requirement (with the 2 ppm downstream testing
adjustment under § 80.580(d)) applying at all levels of the distribution system, from
refinery to retail outlets, how much service station, delivery truck, terminal testing and
other quality assurance testing does EPA view as necessary to constitute a presumptive
liability defense?
A: D A quality assurance program, including a sampling and testing program, is one of
the defense elements under the presumptive liability scheme (see § 80.613(a)(l)
and (d)). The liability and defense provisions under this rule are like those of
other fuels rules. What constitutes a valid sampling and testing program varies
depending on the type of party, as discussed below, and also varies depending on
the particular circumstances involved. Factors that EPA believes are relevant in
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designing any sampling and testing program include: the results of previous
sampling and testing; the volume of fuel being handled by a facility and the
volume of individual batches being processed by a facility (the greater the volume
of a batch the greater the justification for sampling and testing that batch); the
degree of confidence in the quality of the fuel received based on all
circumstances; the opportunity for violations to occur while the fuel is in
possession of the party (e.g., the opportunity for commingling of 15 ppm fuel with
500 ppm or high sulfur distillates); and the opportunity for misdeliveries of
product.
Retailers and wholesale pur chaser-consumers-
Retailers and wholesale purchaser-consumers are not required to conduct
sampling and testing programs. See § 80.613(a)(l)(iii). However, during the
period when storage tanks are being turned over from 500 ppm fuel to 15 ppm
fuel, retailers should take steps to assure the product in the tanks meets the 15
ppm standard before making the fuel available for sale as 15 ppm fuel.
Terminals and Pipelines-
An acceptable periodic sampling and testing program for terminals will probably
require sampling and testing after every receipt of product into a terminal storage
tank, given the stringent sulfur standard, the potential substantial emissions
consequences of violations, and the potential for contamination of product with
high sulfur distillates (and especially in the early years of the program, high
sulfur gasoline). Appropriate pipeline testing will depend on many factors,
including the length of the pipeline, the nature of the product in the pipeline cycle
on either side of the 15 ppm motor vehicle dieselfuel, the opportunities for
contamination as product enters the pipeline or offloaded to terminals, etc.
Carriers such as pipelines may, in addition to appropriate testing of their own,
rely on testing by other parties, such as the refiners who deliver product to the
pipeline.
Distributor s-
Distributors of motor vehicle dieselfuel who take title to the fuel must conduct a
periodic sampling and testing program as part of the quality assurance element of
their defense to presumptive liability. The appropriate frequency of sampling
would depend on the circumstances, as noted above. A truck distributor who
delivers fuel to retail outlets may be able to rely on tests conducted by the
terminal it loaded product from, if the sampling and testing program is properly
performed, in order to show fuel picked up from the truck loading terminal met
standards. However, if for example, the distributor delivers both 500 ppm
product and 15 ppm product, periodic sampling at the distributor's facility
(especially if the distributor has storage tanks) and at retail outlets it delivers to
would be important. In addition, a truck distributor should employee procedures
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to prevent misdelivery of 500 ppm product into 15 ppm product storage tanks,
and to prevent contamination in delivery tanks.
Truck Carriers-
Under § 80.613(d)(4), a tank truck carrier may conduct certain other oversight
activities in lieu of sampling and testing. Truckers should develop procedures to
assure that 15 ppm sulfur content product they handle is not contaminated by
higher sulfur products and to assure that 500 ppm fuel, or other high sulfur
product, is not misdelivered into a storage tank for 15 ppm fuel. Truckers should
have procedures to assure that high sulfur product is completely drained from a
truck compartment and hoses before that truck compartment is used to carry 15
ppm motor vehicle fuel. Alternative oversight activities in lieu of testing include
driver training; periodic review of records; providing drivers with specific
information regarding which customers, and which storage tanks at customer's
facilities, require fuel meeting the 15 ppm standard and which have 500 ppm fuel
storage tanks (or nonroad storage tanks), etc. Truck carriers may also rely on
the sampling and testing programs of other parties as part of their quality
assurance program (e.g., sampling and testing conducted by their immediate
supplier).
Branded Refiners-
A branded refiner must conduct a quality assurance sampling and testing
program at branded retail outlets as one aspect of the quality assurance program
defense element to branded refiner liability under § 80.612(a)(3). The branded
refiner must assess the specific factors that apply to its branded retail outlets and
the distribution systems that supply them in determining the appropriate sampling
and testing rate.
In addition to the factors listed above, branded refiners should also consider the
historical compliance of branded facilities in a marketing area, and whether there
is reason to believe that particular downstream facilities do not comply with
contractually imposed requirements designed to prevent violations. Moreover, in
the first year the 15 ppm standard is in effect, a relatively high sampling rate
would probably be necessary to assure that retail tanks are successfully
transitioned to 15 ppm fuel by September 1, 2006. In subsequent years, it may be
appropriate to raise or lower this sampling rate, depending on the extent of
compliance demonstrated by the program. In areas where problems are found,
the sampling rate should be increased, and efforts should be made to discover the
causes of the problems and correct those problems. The specific facilities where
violations were found should be reinspected frequently.
Refiners and Imyorters-
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Under § 80.613(a)(l)(iv), a refiner or importer must conduct testing of every
batch to meet the quality assurance periodic sampling and testing element of its
defense to presumptive liability.
See § 80.613(a)(l)(iv) and (v), and § 80.613(d)(2)for special situations.
12.19: Marketers frequently have disagreed with EPA actions regarding waivers or enforcement
discretion with respect to the RFG program. Some have predicted on-road diesel supply
shortages when this rule takes effect in 2006. If such supply disruptions — whether
caused by underproduction; refinery, terminal, or pipeline problems; or, weather — do
occur, what will EPA's reaction be?
A: D It is difficult to discuss possible enforcement discretion issues that may occur.
However, we note that, especially after 2010, when all highway diesel fuel must
meet the 15 ppm sulfur standard, we do not foresee any practical way to
distribute motor vehicle diesel fuel having a sulfur content greater than 15 ppm
into the motor vehicle diesel fuel market.
Of course, we realize that temporary supply disruptions may occur due to an Act
of God, or other unforeseeable event. The regulation, and the Agency's inherent
discretion, provide mechanisms for EPA to consider whether a supply disruption
is one for which relief is appropriate. However, we believe it would be very
difficult now to address a variety of crises that may or may not occur in the
future.
12.20: There will likely be significant adjustments for the diesel fuel distribution system to
make to assure that 15 ppm highway diesel is available on-spec for truckers and other
customers. The rule mandates that this fuel be distributed in mid-2006 despite the fact
that the demand for this fuel will be sparse prior to 2007. Would EPA consider providing
a period of enforcement discretion after mid-2006 for companies in the distribution chain
if good faith efforts to meet the 15 ppm standard are made?
A: D The regulations created a 3-step implementation process that is expected to give
all levels of the distribution system, including the retail outlet and wholesale
purchaser-consumer level, enough time to bring storage tanks into compliance in
time to meet the regulatory deadlines. Refiners and importers must be in
compliance with the 15 ppm standard by June 1, 2006. All facilities downstream
of the refiner or importer, except retail and wholesale purchaser-consumer
facilities, must be in compliance by July 15, 2006, if they choose to market 15
ppm fuel. Similarly, retailers and wholesale purchaser-consumers must be in
compliance by September 1, 2006, if they choose to market 15 ppm fuel. These
entities downstream of the refinery have built-in flexibility in that they can
continue to market 500 ppm fuel if they so choose until 2010.
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12.21: With the recent buying and selling of refining and marketing assets, branded retail outlets
may no longer be supplied by refineries with the same name. E.g., Refiner A may now
have retail outlets with Refiner B's brand and Refiner A may not supply the outlets.
Given this situation, EPA's branded retail defense requirements no longer seem
appropriate.
A: D Branded refiner/importer liability under the regulations is not based on whether
the branded refiner actually supplies the fuel to the retail outlet. Under § 80.612,
any refiner or importer whose corporate, trade or brand name, or whose
marketing subsidiary's corporate, trade or brand name appears at a facility
where a violation occurs, is deemed liable for the violation and must establish its
defense to branded refiner liability to avoid liability.
12.22: In the fuel marketing industry "branded" means an exclusive supply contract between the
brand and the retail outlet. In this sense some stations are branded for gasoline but not
for diesel even though the "brand sign" flies above the property. Does branded refinery
liability apply to diesel fuel sold at such a station?
A: D Under § 80.612, if the brand name "appeared at a facility " where a violation
occurred, the branded refiner would be liable under the branded refiner liability
provisions. Where gasoline and diesel fuel are sold at a retail outlet on the same
premises, and the facility is branded as defined by the regulation, the gasoline
and diesel operations would generally be considered branded since they would
usually be part of the same facility.
12.23: Where a branded jobber owns & supplies its branded retail outlet, who is potentially
liable for violations found at the retail outlet and what quality assurance sampling and
testing is the branded refiner and jobber/retailer responsible for?
A: D The branded refiner would be liable for any violation that occurs at the branded
facility. To establish a branded refiner defense, the branded refiner must, among
other things, establish that it had an appropriate quality assurance sampling and
testing program. See questions 12.18 and 4.35 for liability and defense
provisions for retailers and distributors.
12.24: For an owner of a retail outlet or a fleet fueling facility (a wholesale purchaser-consumer
facility), if the product transfer documents account for all product in the storage tanks
and show that the product is in compliance with the 15 ppm standard, am I still at risk for
penalties?
A: D Where PTDs account for all product and show the product is in compliance with
the diesel standards, and where the pumps are properly labeled, and the retailer
or wholesale purchaser-consumer has not caused the violation, (e.g., has not
misdirected noncomplying product into the 15 ppm diesel fuel storage tank or
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otherwise caused the contamination or misdelivery to occur) it will generally be
able to establish its defense to liability. However, if for example, a retailer or
wholesale purchaser-consumer were to purchase fuel that it has reason to believe
does not comply with the 15 ppm sulfur standard, even though the PTDs account
for all product and state that the product does meet the standard, the retailer
would be liable since it would have caused the violation.
12.25: During the lead phasedown in gasoline, EPA mandated that larger nozzles be installed on
gasoline dispensers with leaded fuel and that restrictor plates be installed on the fill pipes
of vehicles' fuel tanks, preventing the fueling of cars designed for unleaded gasoline with
unleaded gasoline. Is EPA considering a similar alteration in nozzle sizes to prevent
accidental or intentional misfueling under the 15 ppm diesel fuel program?
A: D We did not finalize any provisions beyond fuel pump labeling requirements. We
recognized that some potential for misfueling would still exist and continued to
discuss options in meetings and workshops with industry to explore simple, cost-
effective approaches that could further minimize misfueling potential. Through
these discussions, however, no consensus was developed such that the magnitude
of the potential misfueling problem would justify the cost and burden associated
with additional regulatory controls.
12.26: For presumptive liability it has been indicated that EPA will look along the chain of
hand-offs; however, in the case of misfueling, will pipeline PTDs be required to establish
liability, or for upstream parties to establish a defense?
A: D Where a retailer's or wholesale purchaser-consumer's fuel pump is properly
labeled as dispensing 500 ppm product, but the fuel is dispensed into a vehicle
requiring 15 ppm fuel, EPA would not take enforcement action against any
person upstream of the retail outlet or wholesale purchaser-consumer unless such
party caused the violation. Therefore, EPA could establish liability for the
appropriate parties without inspecting pipeline PTDs.
If the misfueling was caused because a fuel pump labeled as dispensing 15 ppm
fuel actually dispensed fuel with a sulfur content exceeding that standard, then
presumptive liability would apply to the retailer or wholesale purchaser-
consumer and to all upstream parties (and to the branded refiner, if applicable).
For each of these parties, one of its defense elements is that it demonstrate that it
has PTDs that account for the product and show it was in compliance when in the
possession of that party.
12.27: Assume a terminal tank contains diesel fuel meeting the 15 ppm sulfur standard and that
fuel is contaminated by a delivery of off-spec diesel fuel represented to meet the 15 ppm
standard such that the terminal's test results after receipt show that the sulfur content of
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diesel fuel in the terminal tank is now greater than 17 ppm. What are the consequences
and what options are available to the terminal?
A: D Finding that fuel represented to meet the 15 ppm standard exceeds 17 ppm at a
downstream location such as a terminal has consequences regarding compliance
with both the standards and with the "designate and track"provisions.
Liability and Remedial Action
Under the presumptive liability scheme the facility where violating product is
found, and all facilities upstream, are presumed liable for a violation of the diesel
fuel standards. In this scenario, the truck loading terminal, the pipeline, and the
facility of any other entity that distributed fuel in the terminal tank is liable. Each
party, including the party owning the facility where the violation was discovered,
has an opportunity to establish a defense to liability by meeting each of its
defense elements. For most parties, to establish a defense the party must
demonstrate that it did not cause the violation, that it had an appropriate quality
assurance program (including periodic sampling and testing), and that product
transfer documents account for the product and demonstrate that the fuel in
question was apparently in compliance while in its custody. In addition, once the
party discovers that the product is out of spec it must take appropriate actions to
either redesignate the product to an appropriate designation or remedy the
violation by blending in lower sulfur content fuel such that the resulting mixture
meets the standard.
A terminal that discovers it has noncompliant product should immediately lock
out the tank until it takes appropriate action. While the product is in violation
until remedial action or downgrade, such action does allow the product to be
transferred without additional violations. As in all of our other fuel programs, if
you discover off-spec product and are taking some sort of remedial action, EPA
will not issue a notice of violation (NOV). The product transfer documents and
designation records must be changed to reflect the appropriate designation (if a
change in designation is appropriate) and records should be kept to document the
circumstances that gave rise to the violation and to document the remedial action
or change in designation. If product is blended with other diesel fuel to bring it
back within compliance with the 15 ppm sulfur standard, the product must be
tested before it is transferred, to assure that such blending was successful.
Designate and Track Issues
For "designate and track" purposes, if a pipeline transfers product designated as
15 ppm to a terminal but it is subsequently discovered that the product did not
meet the 15 ppm standard, then in addition to the standard violation there is also
a designate and track violation. To remedy this violation, the parties must
indicate in their records and on product transfer documents the appropriate
revised designation at the time of transfer. In this example, the pipeline and
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terminal must revise the designation of the fuel as it was transferred from the
pipeline to the terminal. If the terminal elects to classify the product as 500 ppm
highway fuel then, in this scenario, the pipeline must revise the designation for its
hand-off to 500 ppm highway product and count the product against its anti-
downgrade accounting.
The terminal may elect to upgrade the violating product (by blending it with
product having a sulfur content less than 15 ppm) to meet the 15ppm standard
rather than downgrading the entire tank to 500 ppm fuel. If it does so, it may
designate the resulting product as 15 ppm highway or nonroadfuel (but the
designation of the product for the transfer from the pipeline to the terminal would
be 500 ppm product).
If a terminal causes 15 ppm product to fail to meet the 15 ppm standard, and it
conducts remedial action before shipment to bring the product to 15 ppm, for
designate and track purposes, the product would still be counted as 15 ppm
product when transferred to the terminal and 15 ppm product when transferred to
the next facility. This is the case because designations are based on the product
at the time that custody transfers from one facility to another, and not on the
fuel's status while in storage. However, there would be a standard violation
unless the terminal immediately changed classification of the product as soon as
the contamination occurred (or immediately locked out the tank pending test
results, then changed the classification or remedied the violation by blending in
lower sulfur fuel).
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13. D GPA/Small Refiners
13.1: D EPA expanded the GPA (66 FR 19296). The GPA map on 66 FR 19300 is not consistent
with the list of individual counties in Washington at 66 FR 19306. The map includes
Klickitat County in the shaded area in Washington. However, the list of individual
counties in Washington at § 80.215(a)(2)(i) does not include Klickitat County. Would
you confirm that Klickitat County is in the GPA and your intention to include Klickitat
County in a revised § 80.215(a)(2)(i)?
A: D In a direct final rule published on April 13, 2001 (66 FR 19296), we amended the
Geographic Phase-in Area (GPA) to include counties and tribal lands in states
adjacent to eight original GPA states. While Klickitat County appeared on the
map on page 19300, it was inadvertently omitted from § 80.215(a)(2)(i) and
should be included in the list of GPA counties. This inconsistency will be
corrected in a future Federal Register notice.
13.2: D A refinery approved by EPA to produce gasoline subject to the interim GPA standards in
2007 and 2008 must demonstrate that by June 1, 2006 it will produce enough 15 ppm
highway diesel fuel to meet the minimum 85 percent of its baseline volume requirement.
See § 80.594(c). When is this demonstration due for GPA refineries? Is this
demonstration part of another report (i.e., the 2003, 2004 and 2005 pre-compliance
reports) or is it a separate, stand-alone submission?
A: D Under §80.594(c), a refiner or importer approved to produce gasoline in the
GPA subject to the gasoline sulfur standards under § 80.540 must demonstrate
that by June 1, 2006 it will be producing a volume ofon-road diesel fuel
containing 15 ppm sulfur or less that is equal to or greater than 85% of its
baseline volume (see § 80.540(e)). Under § 80.540(b) the demonstration of future
production volume required under § 80.594(c) was due December 31, 2001, with
the application under § 80.540 for approval of the gasoline sulfur extension.
Under § 80.594(d), refiners and importers have untilJuly 1, 2006 to submit a
report stating that production or importation of 15 ppm sulfur motor vehicle
diesel fuel will be started by June 1, 2006. The demonstration required by §
80.594(d) must be reported in a stand-alone report submitted by the refiner or
importer.
13.3: D 40 CFR 80.540(e) requires "The total volume of motor vehicle diesel fuel produced for
use in the United States and designated as meeting the 15 ppm sulfur content standard
under paragraph (d) of this section must meet or exceed 85% of the baseline volume
established under paragraph (c) of this section, except that for the first compliance period
from June 1, 2006 through June 30, 2007, the total volume must meet or exceed 92
percent of the baseline volume." Is it correct to assume that "produced" means available
for sale at the refinery gate as an on-road fuel meeting 15 ppm diesel fuel standards?
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A: D "Produced" should be interpreted as a refiner manufactured the motor vehicle
diesel fuel from crude oil and the dieselfuel met all of the standards under §
80.520 and was designated as motor vehicle dieselfuel when it was delivered to
the next facility in the distribution system.
13.4: D What records must be kept to demonstrate that an adequate volume has been produced?
A: D Under §80.540(1), the record keeping requirements specified under §80.592
must be met for GPA gasoline. This includes records indicating the volumes of
each batch of diesel produced during the compliance period (§ 80.592'(b)).
13.5: D How would a refinery with a loading rack account for 15 ppm diesel fuel that is sold into
the offroad market? If production is interpreted in any other way, a refinery could be
penalized if, due to logistical and production constraints, customers elect to purchase 15
ppm diesel fuel as an offroad diesel fuel.
A: D Per the requirements of § 80.598, promulgated in the nonroad diesel rule in June
2004, a refiner is responsible for designating the fuel appropriately when
delivered to the next facility in the distribution system. UntilJune 2009, all 15
ppm dieselfuel must be designated as motor vehicle dieselfuel.
13.6: D Who are the small refiners in the ULSD program? Are they the same as the "small
refiners" in the Tier 2 gasoline program?
A: D We have received 18 applications for small refiner status, and many of these
refiners are currently approved small refiners for the gasoline sulfur and highway
diesel programs. However, they may not all be approved for NRLM small refiner
status. Specific information can be obtained upon request from Larry Haslett of
EPA.
13.7: D If a large refinery spins off a small refinery how long does the small refiner have to apply
for the small refiner status?
A: The dates to apply for small refiner status were specified in both rulemakings,
and the deadlines have passed for both highway and nonroad diesel.
13.8: D Is there an opportunity for a blender who is presently classified as a refiner to apply for
small "refiner" status?
A: D The deadline to apply for small refiner status for both the highway and nonroad
dieselfuel rules has passed. Furthermore, to be considered for small refiner
status, a refiner must process diesel fuel from crude (see § 80.550 (a) and (b)).
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13.9: D EPA indicated that the deadline for applying for small refiner status has already passed.
However, should the marketer decide to blend e-diesel or biodiesel, it may want the
option to be a "small refiner" under the diesel regulations.
A: D As stated in § 80.550 (a) and (b), the marketer would have to produce diesel fuel
from crude.
13.10: How do you establish a baseline for a small refiner, who has never produced on road
diesel but wants to delay low sulfur gasoline equipment and build low sulfur diesel
equipment first?
A: D It was discussed in the preamble to the final highway rule to allow case-by-case
looking at a variety of factors (see pages 5073 and 5077, foot note).
Unfortunately the provisions never made it into the regulations. We will be doing
minor rule changes on this to mirror the preamble language.
13.11: Is the decision to use Small Refiner Options 1, 2, or 3 irrevocable?
A: D Under §80.551(c) (3), we ask for "an indication " of which kind of relief small
refiners expect to use. The regulations do not prevent a refiner from using a
different option later. However, section 80.55'3(h) voids the gasoline extension if
small refiners fail to meet the 15 ppm volume requirements.
13.12: Is an independent auditor required in order to establish a diesel baseline?C(See §§
80.595(c)(2) and 80.92.)
A: D Yes an independent auditor is required to establish a diesel baseline.
13.13: A company owns 58.75% of our refinery. The refinery is rated at 260,000 Barrels/day of
which the company owns 152,750 B/D (260 * 0.5875). Would this qualify our refinery
for the small refiner hardship provisions?
A: D That ownership percentage makes the refinery a subsidiary under our definition
(see § 80.550) and all of a subsidiary's crude capacity must be used in
determining the total crude capacity. There is no prorating.
13.14: Can an approved highway diesel small refiner stay in business just by producing only 500
ppm diesel fuel and supply to the off road market.
A: D Yes. An approved highway diesel small refiner that currently produces highway
diesel can produce no highway diesel and use all of its diesel fuel production to
supply the nonroad market.
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13.15: Our company is a small business refiner under the Small Business Administration (SBA)
regulations. Our company would similarly meet the definition of a "small refiner" under
the highway ULSD regulations, if not for the regulations' requirement that, for the
purpose of determining qualification as a small refiner, a refiner must "include the
employees and crude capacity of any subsidiary companies, any parent company and
subsidiaries of the parent company in which the parent has 50 percent or greater
ownership, and any joint venture partners." The distinction is attributable to the fact that,
unlike the highway ULSD regulations, the SBA regulations do not affiliate our company
with its owner.
Under the SBA regulations, our company's size is determined by counting the total
capacity of all of our refineries, and the employees of all of our refineries and subsidiary
distribution businesses. However, Section 121.103(b)(2) of SBA's regulations exempts
subsidiaries of our parent from affiliation, so that our company is not considered
affiliated with the parent itself or other, unrelated subsidiaries of the parent. Our
company believes that this definition is consistent with the purpose of the U.S.
Environmental Protection Agency's affiliation rule, and is concerned that the provisions
on affiliation in the highway ULSD regulations would inadvertently exclude our
company.
A: D Under EPA 's gasoline and diesel sulfur regulations, we include all employees
and crude capacity of all parent companies and subsidiaries where the parent
company maintains 50 percent (or greater) ownership (§ 80.550(a) and (c)).
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14. D Transmix/Interface Fuel
14.1: D In the case where a terminal processes transmix with an on-site fractionator, is the
on-road production volume subject to the requirements of § 80.520?
A: D The regulations finalized with the nonroad rule modified the requirements for
transmix processors who do not also produce fuel from crude. These provisions,
contained in § 80.513, allow for 100 percent of a transmix processor's highway
production to remain at the 500 ppm sulfur level untilJune 1, 2010.
14.2: D Interfaces between jet fuel and other distillates are cut into the other distillate to protect
the jet fuel, thereby increasing the volume of the other distillate. Kerosene/15 ppm diesel
fuel and high sulfur diesel/15 ppm diesel fuel interfaces could be cut into separate
tankage to create 500 ppm on-road diesel (assuming no dye in the high sulfur diesel). Is
there any limit as to the amount of 500 ppm on-road diesel that could be created through
these interface cuts? Are there any special downstream requirements for the testing or
documentation of on-road diesel created from interface?
A: D Under § 80.527 (c), the maximum allowable amount of #2 15 ppm on-road diesel
that can be downgraded to 500 ppm on-road diesel is 20%, otherwise there are
no downgrade restrictions. However, on-road diesel created from interface must
meet the standards under § 80.520.
14.3: D How will EPA treat transmix, which does not fit into any category? It is not on-road and
it is not off-road gas or fuel. Transmix is not intended for final use by any consumer but
it can be re-refined or re-processed.
a) For EPA purposes, will it need to be tracked after its creation?
b) If it is sold to a refinery for re-refining, will EPA treat it differently than if it is
sold to a reprocessor?
c) Does it make a difference if it is sold to another refiner or the original refiner?
A:
a) Transmix would merely be designated as such and would not be tracked for EPA
purposes unless (and until) it is redesignatedfor fuel use.
b) D It would not be treated any differently. However, transmix processors who are
also refiners are held to different standards for the fuel that they produce from
transmix.
c) D No, there is no difference if it is sold to another, or the original, refiner.
14.4: D Can a terminal tank meet the 15 ppm diesel fuel sulfur standard on average, or must the
diesel fuel meet the 15 ppm sulfur standard on a per-gallon basis? For example, if a
pipeline or terminal accidentally cut some of an interface, consisting of 500 ppm diesel
fuel and 15 ppm diesel fuel, into the 15 ppm diesel fuel, causing a certain strata of a 15
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ppm diesel fuel storage tank to exceed the 15 ppm standard, the rest of the tank may still
contain product that continues to meet the 15 ppm standard. In the alternative, it may be
possible to remedy a violation by blending diesel fuel exceeding 15 ppm sulfur content
by blending sufficient quantity of very low sulfur product to make the tank or batch meet
the 15 ppm standard. Would EPA allow such remedial action?
A: D Diesel fuel subject to the 15 ppm sulfur standard must meet that standard on a
per-gallon basis and not on average. The pipeline or terminal must handle the
interface in a manner that ensures that product distributed as subject to the 15
ppm cap is in compliance with that cap. If any portion of a tank that is offered for
sale or supply as fuel subject to the 15 ppm sulfur cap is out of compliance with
the 15 ppm cap, then that volume of fuel would be in violation. However, if a
pipeline or terminal accidentally cuts part of an interface having a sulfur content
greater than 15 ppm into a tank containing fuel subject to the 15 ppm sulfur
standard, it may be possible to remedy the violation. We would not pur sue an
enforcement action where a terminal determines that product exceeding the 15
ppm standard has been added to a tank if the terminal: discovers the
commingling of higher sulfur product with 15 ppm product through its quality
assurance program and not by an EPA inspection; immediately locks down the
tank before any of the product is released; transfers product exceeding the 15
ppm standard to some appropriate high sulfur product distribution; retests the 15
ppm product tank to assure that the entire remaining volume of the tank meets the
15 ppm standard before releasing the product as 15 ppm product; and maintains
records demonstrating the occurrence, the actions taken to remedy the violation,
sampling and test results, and actions to prevent future violations.
Such situations may also be remedied by blending the contaminated product with
low sulfur product in order to bring the sulfur level of all the product in the tank
to the 15 ppm sulfur standard. Again, before releasing product the sulfur level
should be re tested, and records of the occurrence, remedial actions, sampling and
test results, and of actions to prevent future violations should be maintained.
Finally, such situations could be remedied by downgrading the entire volume of
product affected by the commingling with the higher sulfur interface. When 15
ppm product is downgraded, the party should document the circumstances that
gave rise to the downgrading. The diesel fuel in question should be segregated
from diesel fuel subject to the 15 ppm standard, the product transfer documents
must reflect the downgraded classification, and the diesel fuel must not be sold,
dispensed or transported in a manner that is inconsistent with the downgraded
classification.
14.5: D The facilities that my company owns include a pipeline, terminal, and refinery. We wish
to blend the transmix generated due to normal pipeline operations into a barge containing
crude oil at our terminal facility. This crude oil and transmix mixture would then be
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taken to our refinery for processing. Is there anything in the clean diesel regulations that
places restrictions on this practice?
A: D There is nothing in the highway or nonroad diesel fuel regulations to prevent this
practice from continuing. The losses to transmix would merely be reflected in the
pipeline/terminal aggregated facility's report.
14.6: D Could the < 500 ppm sulfur diesel fuel that a transmix processor manufactures from
reprocessing transmix obtained from a refinery be sold into the highway diesel market
until 2010? Could a transmix processor sell <500 ppm sulfur diesel fuel it manufactures
from tank bottoms into the 500 ppm highway diesel market?
A: D 40 CFR 80.513, the provisions that apply to transmix processing facilities states
that the term transmix applies to a mixture of finished fuels that no longer meets
the specifications for a fuel that can be used or sold without further processing.
For the mixture to be considered transmix under section § 80.513, the component
finished fuels that make up this mixture must have been previously certified as
compliant with the applicable compositional requirements and the mixing must
have been non-intentional. The volume of '< 500 ppm diesel that a transmix
processor manufactures from reprocessing this transmix could be sold into the
500 ppm highway diesel market until May 31, 2010. Any volume of< 500 ppm
sulfur diesel fuel that a transmix processor manufactures from feedstock (e.g. a
diesel blendstock such as light cycle oil) that does not meet the definition of
transmix contained in section § 80.513 would have to meet the 80/20
requirements. Tank bottoms are the remains of previously certified finished fuels
and as such would meet the definition of transmix under section § 80.513. Thus,
< 500 ppm diesel fuel manufactured using tank bottoms by a transmix processor
could be sold into the 500 ppm highway diesel market until May 31, 2010.
14.7: D My company operates a pipeline. We currently blend small quantities of transmix into
diesel fuel subject to a 500 ppm sulfur standard during shipment. The quantities blended
have a negligible impact on the sulfur content of the fuel. Is there anything in the new
highway and nonroad diesel sulfur programs that would prevent us from continuing to
blend transmix into diesel fuel subject to a 500 ppm standard in the manner we do today?
The blending of transmix into the 500 ppm diesel would result in an increase in the total
highway diesel volume. How would this be accounted for in determining compliance
with the highway diesel volume balance requirements?
A: D EPA has not previously considered the blending of transmix into diesel fuel
subject to a 500 ppm sulfur standard during shipment by pipeline. The diesel
sulfur regulations do not specifically address blending transmix into diesel fuel.
We believe that it would be appropriate to provide this flexibility, provided the
pipeline operator met the following conditions:
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The transmix blended into 500 ppm diesel fuel would need to result from
factors associated with normal pipeline operations.
The pipeline would need to conduct periodic tests of the 500 ppm diesel
fuel into which transmix was blended which show that the transmix
blending would not cause the 500 ppm sulfur cap to be exceeded, and that
the diesel fuel still met all the applicable ASTM standards for diesel fuel
such as flashpoint or distillation points.
The pipeline would need to retain documents that reflect the rate of
transmix blending and make these documents available to EPA upon
request.
The volume oftransmix blended into 500 ppm highway diesel fuel would need to
be accounted for in demonstrating compliance with the highway diesel volume
balance calculations. The pipeline would have to account for the volume of
transmix blended into highway diesel fuel by including the transmix volume as
500 ppm diesel production in the compliance calculations in sections § 80.599, §
80.600 (except for the refiner batch reports, new volumes should simply be
accounted for in the D&T calculations) and § 80.601 of the diesel sulfur
regulations.
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15. D General/Miscellaneous
15.1: D Why is heating oil exempt from the sulfur content regulations? If it's bad for cars, why
not for people's homes?
A: The Clean Air Act does not give EPA specific authority to regulate heating oil.
15.2: D Will there be any significant quantities of kerosene that get hydrotreated to 15 ppm (or
lower) sulfur for making ULSD?
A: D We did not require early reporting of this information in the pre-compliance
reports, and as such do not have specific data to address it. Nevertheless, we are
currently aware that at least two refiners plan on manufacturing 15 ppm #1 diesel
fuel for wintertime blending purposes.
15.3: D What does EPA intend to do with all of these reporting requirements and paperwork to
justify their cost to the consumer and taxpayer?
A: D The D& T and recordkeeping provisions were put in place as a means of reducing
the capital and operating costs otherwise necessary to segregate fuels. The costs
of these provisions were estimated in the draft Information Collection Request
(ICR) submitted to OMB, and are small in comparison to the overall costs and
benefits of the program.
15.4: D Cetane index does not work for alternative diesel formulations- diesel with 10% ethanol
must be tested by Cetane number. Do you plan to make a technical correction?
A: D Only the highway diesel rule contains a cetane index standard. We will make a
technical amendment to the regulations, if necessary, to address this issue.
15.5: D Does "other sources of volume" refer to diesel desulfurizers? What do you mean by
"produced from crude oil"?
A: D "Other diesel fuel" means any distillate products that meet the definition of diesel
fuel, such as kerosene, that is represented to have a sulfur content less than or
equal to 500ppm. "Producedfrom crude oil" means that the refiner
manufactured the diesel fuel from crude oil, typically through distillation and
hydroprocessing.
15.6: D If terminals opt to wash barges, tanks, equipment and trucks before running 15 ppm
diesel fuel through their systems, the flushing process will generate substantial volumes
of oily-water waste. Has the EPA given thought to assisting the industry in dealing with
this waste?
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A: D The highway diesel rulemaking did not specifically address this issue. The
rulemaking allowed terminals untilJuly 15, 2006 (approximately 6 weeks after
the June 1, 2006 compliance date for refiners and importers), before any 15 ppm
highway diesel fuel they distribute must meet the 15 ppm standard, and this
additional time should help to minimize waste.
15.7: D Public reaction to new fuels in the past has been mixed (i.e., RFG in Milwaukee, CARB
II Diesel in California). What steps does EPA intend to take to educate and inform
owners of diesel-powered motor vehicles of the changes to fuel specifications,
performance issues, and/or air quality benefits?
A: D EPA currently has all documents associated with the diesel fuel rules available on
its website (http://www.epa.gov/cleandiesel/) and will be periodically providing
additional updates to the website to provide summary descriptions for the public
of the benefits and impacts of the rules. Additional steps will be determined over
the course of the remaining months leading up to June 2006.
15.8: D In the past, EPA has, with the assistance of industry trade associations, produced fuels
brochures for use at retail outlets explaining new fuel programs and addressing
performance and air quality issues. Is EPA planning a similar effort with respect to the
diesel fuel programs?
A: D Actions such as these were discussed with industry during the rule development.
We have been, and will continue to, work with industry trade associations over
the next several years on such actions.
15.9: D How will the highway diesel rule affect mobile refuelers?
A: D Mobile refuelers will be subject to the prohibitions against misfueling like a
retailer. However, we do not require them to label their truck storage tanks since
the product may change. They would also be liable for contaminating any 15
ppm fuel such that it no longer met the standard. They are required to deliver an
accurate product transfer document to the customer.
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