United States
Environmental Protection
Agency
Office of Air and Radiation
Acid Rain Division
EPA 430-R-94-002
February 1994
&EPA
Do the Acid Rain SO2
Regulations Apply to
A Guide for Utilities and Other
Electricity Generators
ACID
'RAIN
PROGRAM
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Do the Acid Rain Regulations Apply to You?
s the
unit..
.listed?
...in Table 1, 2, or 3 of 40 CFR 73.
(See Appendix D)
...potentially
affected?
...an IPP or a QF?
a combustion device
burning fossil fuel
producing electricity
for sale in 1985 or
on or after 11/15/90?
Yes
Yes
...that (Das of 11/15/90,
had a qualifying power purchase
commitment to sell at least 15% of
net planned capacity and (2) has
net installed capacity < 130% of
net planned capacity?
Yes
No
A unit that is exempted or unaffected
must continue to meet certain
requirements in order to maintain
exempted or unaffected status. See
the appropriate section of this guide
for information on the continuing
requirements for your unit.
-------
...a cogenerator?
...an
incinerator?
...new?
...that (1) supplied an annual average of 5 1/3 ...that CO combusted<20% fossil fuel (on a ...a unit that commenced commercial
of potential electrical output capacity ... Btu basis) on average for the first three years of ... operation on or after 11/15/90?
or s; 219,000 MWe-hrs to the grid for sale for ^P operation or from I98S-1987, whichever is
any three year period after 11/15/90 and (2) was later and (2) combusted < 20% fossil fuel (on a ~
constructed for the purpose outlined in (1) if Btu basis) on average for any three year period
construction commenced on or before 11 /15/90? after 11/15/90?
Yes
Yes
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...using
clean fuel?
• ...a new unit combusting only fuel
with 005% sulfur content by weight
and serving generator(s) with total
nameplate capacity 25 MWe?
i\f
..serving small
generator(s)?
serving only generator(s) with
N nameplate capacity 25 MWe on and
after 11115/90?
No
.retired?
.ceased operation. (before it waS issued
N an Acid Rain Permit or before the permit
istobe renewed)?
Yes
...a simple turbine?
No
.a simple combustion turbine?
Noó
AffectSd
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ACKNOWLEDGEMENTS
This guide was developed by the Acid Rain Division of the Office of Air and Radiation, U.S. Envi-
ronmental Protection Agency. This guide was developed and written under the direction of Ms.
Kathy Baryiski of the Acid Rain Division. Special thanks to Janice Wagner, Renee Rico, Brian
McLean, Tom Eagles, Michael Stenburg, Beth Burns, Donna Attanasio, Bill Bumpers, Gordon
Beals, Barbara Cook, Stephen Fotis, Gene Higa, William Marx, Gilbert Sperling, and Margaret
Welsh, who reviewed drafts and provided comments. Contractor support was provided by ICF
Incorporated.
The U.S. Environmental Protection Agency has reviewed and approved this document for publication.
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Table of Contents
Preface . 1
Overvleiw ............. ................ Iss . . .u•.u•u•us•uI• . .uI .• . .• ill
What This Guide Will Tell You v
What This Guide Won’t Tell You vii
Section 1: DeterminIng Applicability .... . . . I
Applying for an Applicability Determination by EPA 2
Affected Units 3
Exempted Units 6
Small New Units Burning Clean Fuels 6
Retired Units 8
Unaffected Units 9
Enslirig Simple Combustion Turbines 10
Existing Units Serving Generators Less Than or Equal To 25 MWe 11
Cogeneration Units 12
Independent Power Pivduction Facilities and Qualifying Facilities 16
Solid Waste Incinerators 20
Section 2: Requirements for Affected and
Exempted Units 21
Continuous Emission Monitoring 22
Holding Allowances 22
Designated Representatives 23
Permitting 23
Applying for an Exemption 24
Compliance Timelines 25
Glossary
Appendix A: Selected Acid Rain Regulations and Documents
Appendix B: EPA Regional and State Office Addresses
Appendix C: Applicability Determination Examples
Example 1: Listed Unit
Example 2: Cogenerator Not Selling Electricity
Example 3: Qualifying Facility
Example 4: Cogenerator Selling Electricity
Example 5: Solid Waste Incinerator
Example 6: New, Small, Clean Unit
Example 7: Retired Unit
Example 8: Existing Simple Combustion Turbine
Example 9: Existing Unit Serving A Small Generator
Appendix D: Selected List of Units Affected by the
Acid Rain Reguiations
Appendix E: Certificate of Representation
index
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Preface
T his guidance is designed to assist electricity producers in deter-
mining whether or not the Acid Rain Program’s sulfur dioxide
(SO 2 ) regulations apply to their units. The information provided in this
guidance document may be updated as EPA makes additional deci-
sions and determinations regarding implementation of the Acid Rain
Program. EPA will seek to reconcile implementation of the Acid Rain
Program with new legislation, such as the Energy Policy Act of 1992.
If desired, the owner or operator of a unit may request that EPA
determine if a unit is affected by the regulations under the procedures
described in 40 CFR 72.6(c). Publication of this document is not an
applicability determination under 40 CFR 72.6(c). If you have further
questions on applicability, please call the Acid Rain Hotline at (202)
233-9620, or submit questions in writing to:
U.S. EPA
Acid Rain Division (6204J)
A’fl’N: Applicability
401 M Street, SW
Washington, D.C. 20460
Legal Statement
This document is intended solely as guidance. It does not represent
final Agency action. This document is not intended, nor can it be
relied upon, to create any rights enforceable by any party in
litigation with the United States. Only a formal applicability
determination under the procedures described in 40 CFR 72.6(c)
will be enforceable. EPA officials may decide to follow the
guidance provided in this document or to vary from it, depending
on the specific circumstances encountered. The Agency may
change this guidance at any time without public notice.
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Do the Acid Rain SO 2 Regulations Apply to You?
II
-------
Overview
Q (the approximately 23 million tons of sulfur dioxide (SO 2 ) and
19 million tons of nitrogen oxides (NOr) emitted from all
sources in the United States in 1985, about 16 million tons of SO 2 and
seven million tons of NO were emitted by electric utility companies.
Emissions of SO 2 and NO are the primary causes of acid rain.
In order to reduce acid rain in the U.S. and Canada, Title IV of
the Clean Air Act Amendments of 1990 requires the Environmental
Protection Agency (EPA) to establish a program to reduce emissions,
called the Acid Rain Program. The overall goal of the Acid Rain
Program is to achieve significant environmental benefits through
reductions in SO 2 and NO emissions. To achieve this goal at the
lowest cost to society, the Program employs both traditional and
innovative market-based approaches for controlling air pollution. In
addition, the Program encourages energy efficiency and promotes
pollution prevention.
Title IV sets as its primary goal the reduction of annual SO 2
emissions by 10 million tons below 1980 levels. Approximately 85
percent of the reduction in emissions is to be achieved by electric
utilities. To achieve these SO 2 reductions, the law requires a two-phase
tightening of the restrictions placed on fossil fuel-fired power plants.
Phase I, which begins in 1995, requires 110 higher-emitting utility
plants in 21 eastern and midwestern states to meet an intermediate SO 2
emissions limitation. Phase II, which begins in the year 2000, tightens
the annual emissions limitation and expands coverage to most utility
units.
Under the Program, units are allocated “allowances” by EPA. An
allowance is a limited authorization to emit up to one ton of SO 2
during or after a specified calendar year. Once allowances are allo-
cated, owners or operators may use their allowances to cover emis-
sions, or they may trade their allowances to other units under a market-
able allowance program. EPA will keep track of the allowances held
by each unit by using the Allowance Tracking System (ATS).
I I I
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Do the Acid Rain SO 2 Regulations Apply to You?
Utility units that began operation prior to the passage of the Clean
Air Act Amendments (November 15, 1990) are allocated emission
allowances based on their historic fuel usage and emission rates
specified in Title IV and its implementing regulations. Most units
commencing operation from November 15, 1990, through December
31, 1995, will also be allocated allowances under Phase IL* The
National Allowance Data Base (NADB), developed by EPA, lists
utility units — existing and planned — as well as the information neces-
sary to allocate allowances to these units.
Units that are affected by the acid rain regulations are required to
limit SO 2 emissions to the number of allowances they hold. Some
utilities may benefit by selling their allowances while reducing their
emissions. Since allowances are fully transferable, these utilities may
choose to emit less than their allocated allowances and sell the differ-
ence to utilities that would benefit from buying allowances and emit-
ting more than their initial allocation. This trading achieves economic
efficiency while capping total SO 2 emissions nationwide.
* Certain other facilities may be allocated allowances, but they are not subject to
emissions limitations under Title IV. These allowances are allocated to provide
financial incentives for indirect reductions of SO 2 emissions. Small diesel refining
facilities are eligible for allocations based on fuel desulfurization, which will reduce
SO 2 emissions from diesel-burning vehicles (see 40 CFR 73 Subpart G). Also,
utilities using renewable energy or employing energy conservation measures may be
eligible for certain allowances (see 40 CFR 73 Subpart F).
1980 levels
of SO 2
Phase I:
Emissions standard
for higher emitting
plants
20
C
0
C o
( 0
E
w
a)
. 15
XC
.2.2
.— C
E
—
a
t
a)
w
5—
Phase II:
Emission standards
for most utility
plants begin
Permanent
cap on utility
SO 2 emissions
1980
1995
2000
2010
iv
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Overview
In order to maintain a permanent cap on utility SO 2 emissions of
8.95 million tons per year, utility units that begin operation after 1995
generally are not allocated allowances. Affected units not allocated
allowances may not emit SO 2 unless they purchase allowances.
In any year that a source fails to hold sufficient allowances to
cover its emissions, excess emissions penalties will apply. Also, the
source must submit a plan to EPA that specifies how the excess SO 2
emissions will be offset, or it will have allowances deducted immedi-
ately from its unit account.
The Act also calls for a two million ton reduction in NO emis-
sions by the year 2000. A significant portion of this reduction will be
achieved by requiring coal-fired utility boilers to meet new NO
emissions requirements. A marketable allowance program is not part
of the NO reduction program.
What This Guide Will Tell You
This guide is designed to help utilities and other electricity gen-
erators determine whether they are affected by the SO 2 and monitoring
regulations of the Acid Rain Program. The flow chart on the inside
cover provides a quick-reference guide showing categories of units
that are affected by, eligible for exemption from, or unaffected by the
regulations. The document presents descriptions of these categories,
requirements for affected units, and requirements for obtaining exemp-
tions. Specific sections of the document are described below.
Section 1: Determining Applicability
This section outlines how to determine if a unit is affected by the
SO 2 and monitoring provisions of the Acid Rain Program. It describes
various types of units as defined by the Acid Rain Program and states
whether those types are affected by, may be eligible for an exemption
from, or are unaffected by the Acid Rain Program. This section also
outlines the information that needs to be included in a request for an
applicability determination from EPA.
V
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Do the Acid Rain SO, Regulations Apply to You
Section 2: Requirements for Affected and
Exempted Units
A unit that becomes affected by the Program must meet several
initial and continuing requirements. This section outlines these re-
quirements and provides references for further information. This
section also provides compliance timelines for meeting Phase I, Phase
I I, and continuous emission monitoring (CEM) requirements, and it
lists permit deadlines and dates when units must hold allowances.
Appendix A: Selected Acid Rain
Regulations and Documents
Appendix A lists several acid rain regulations and informational
documents, including publication dates and dockets.
Appendix B: EPA Regional and State
Office Addresses
Appendix B presents a Ilist of EPA Regional offices and State
environmental offices relevant to the Acid Rain Program.
Appendix C: Applicability Determination
Examples
Appendix C presents several case studies demonstrating how to
determine whether the regulations affect certain utility units.
Appendix D: Selected List of Units Affected by
the Acid Rain Regulations
Appendix D provides lists of units affected by the acid rain regu-
lations. These lists were published in the Clean Air Act or in regula-
tions.
Appendix E: Certificate of Representation
Appendix E contains the Certificate of Representation form and
its instructions.
vi
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What This Guide Won’t Tell You
This document does not address Title IV NO control require-
ments, which establish new NO emissions limits for existing coal-
fired electric utility units.
This document also does not address requirements applicable to
unaffected units that voluntarily participate in the Acid Rain Program.
Sources of SO 2 that are not required to meet Title IV emissions limita-
tions may choose to “opt-in” to the Acid Rain Program. The Opt-In
Program encourages these sources to reduce emissions of SO 2 in
circumstances under which it will be less costly for them to do so than
it would be for an affected unit.
Note that many units are required to meet SO 2 emissions limita-
tions or control requirements under other programs, whether or not
they are affected by acid rain regulations. These other limitations may
be more stringent than the limitations under Title IV. Non-Title IV
requirements are not covered in this guidance.
For questions about the Acid Rain Program, or for more informa-
tion on the NO requirements or the Opt-In Program, please contact
the Acid Rain Hotline at (202) 233-9620. For questions or informa-
tion on other Federal or State clean air programs, please contact your
State air quality office (see Appendix B).
VII
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Section 1
Determining Applicability
I n generaL the acid rain regulations for sulfur dioxide (SO 2 ) are appli-
cable to existing utility units serving a generator with nameplate capac-
ity of 25 megawatts of electricity (MWe) or greater and almost all new
utility units located in the 48 contiguous States and the District of Colum-
bia. For the purposes of the Acid Rain Program, the term “utility units”
includes units serving generators that supply electricity for sale, whether
wholesale or retail.
There are, however, applicability exceptions for certain types of units
and units meeting specific criteria. These units may be eligible for an
exemption or may be unaffected by the acid rain regulations. This section
provides the necessary information for determining whether a unit is
affected. Note that once a unit becomes affected, it remains affected for
the duration of the Program.
Section 1 is presented in three parts. The first part describes the
characteristics of affected units. The second part describes the characteris-
tics of units that may be exempted from certain acid rain regulations. The
third part describes six types of units that are unaffected by the regula-
tions. Following the descriptions of each of these unit types are checklists
of information to include in a request for an applicability determination. If
you do not know which type of unit you have, or if you have a unit that
may qualify as more than one type, be sure to submit the necessary mate-
rial for all potentially relevant categories.
I
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Do the Acid Rain SO Regulations Apply to You?
Q
____1 ____
The following are general
requirements for filing an
applicability
determination requës :
/ The letter requesting ar-i ap-
plicabi!it determination must b’e
signed by a certifying official.’.
‘/ The letter must pecify the
? unit. Information should include ’.
the plant that contains the unit,.
the location, of the unit (i.e.,.
State and county), the ORISPL
r(a plant.cdde used by the;
‘Departnientof Energy) if ppro-
priate, and a name or number.
for the unit. ,: -
/ The letter must include the.
ifollowing statement: 1 certify
unddr peQalty pf law that I have
personally ‘examijied, and arñ ’
; amiiiar ’with, the statements
; nd,. information submitted in,
this. .document and all its: ,aV
‘tachrneç its Based on my i 1quiry
‘of those individuals with primary,
;responSibility Lfor obtaining the,
information, I cerUf i that th&
statements and information ark,
to. the dest of my, knowledge:
and belief true, accurate, and
corn lete. 5j am ‘aware that there
are significant’penalties for sub-
. ,mitting false, statements and
:inforrnetion or omitting required
statemeritC and inforrniation, in-,
cluding the possibility of fin or
imprisonment.” S
‘ The letter’ must be sent’ to
the following addr ’ess: U.S. En-.
vironmental Protection Agency;i
Director, Acid Rain Division
(6204J); ATIN: Applicability;,
401 M Street, SW: Washington,
DC ‘20460. 5
/ The certifying official mi )st
send copies ‘of the request to
‘each ”owner or operator of the 4
facility. , ‘ - : ‘
Applying for an Applicability
Determination by EPA
EPA has adopted a procedure by which owners and operators of
any potentially affected unit may choose to ask EPA to determine
whether or not Title IV SO 2 requirements apply to their source. See 40
CFR 72.6(c). This procedure is optional ; EPA does not require any
owner or operator to request a determination of applicability. Those
sources that clearly fit into an unaffected or exempted category should
not feel compelled to request an applicability determination.
This procedure requires submittal of a written request, including
certain information about the unit. In response to that request, EPA
will determine if a unit is affected, based on information included in
the submittal. EPA will then write a letter stating that the unit is either
affected or unaffected. This response letter will constitute final agency
action in the absence of an administrative appeal and will be binding
upon the permitting authority administering the Acid Rain Program for
the unit (i.e., the State or EPA Region). EPA’s determination may be
appealed through the Acid Rain Appeals process. If the information
originally submitted by the unit was inadequate to make an applicabil-
ity determination, EPA may request additional data or write a letter
stating that EPA cannot make a determination based on the informa-
tion submitted.
2
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Determining Applicability
Affected Units
EPA has compiled a list of the sources of SO 2 emissions known
to be affected by the acid rain regulations. All of these “listed units,” Affected
which are discussed below, are Phase I or Phase II affected sources. A
list of these units is included in Appendix D. If a unit or source is listed
in the appendix, it is affected. Some of these units may be eligible for
exemptions from certain Acid Rain Program requirements, as dis-
cussed below. See 40 CUR 72.6(a).
Listed Units
Phase I requirements initially affect only the 263 units at the 110
power plants specifically listed in the Clean Air Act and provided in
Table 1 of 40 CFR 73.10 (see Exhibit I of Appendix D). Phase II
requirements affect a broader group of utility units. Tables 2 and 3 of
40 CUR 73.10 (see Exhibits 2 and 3 of Appendix D) list approximately
2,300 utility units affected by Phase I I requirements.
Additional units may become affected under Phase I if they are
either “substitution units” or “compensating units.” Utilities have
already notified EPA as to which units will be brought into Phase I in
this manner. Substitution units are existing units affected under Phase
LI that are designated under approved substitution plans and that accept
the emission reduction obligation of a unit required to comply with
Phase I. Compensating units are Phase II units that are designated
under approved reduced utilization plans and that generate electricity
to replace electricity historically generated by Phase I units.
Unlisted Units
The Appendix D listings do not include all units that are or may
become affected. Other potentially affected units include:
U Units not in the NADB,
U Units that are planned, and
U Units owned by industrial or commercial entities that sell
electricity.
3
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Do the Acid Rain SO: Regulations Apply to You?
If a unit is not listed in Appendix D, it may be affected by the acid
rain regulations only if it meets all three of the following conditions:*
I i The unit is a combustion device.
U The unit is fossil fuel-fifed.
U The unit supplies electricity for sale or serves an electricity..
generating device that supplies electricity for sale.
Definitions
Unit vs. Generator
A unit is a fossil fuel-fired combustion device, such as a boiler. A
generator is a device that produces electricity. A unit may be
subject to the acid rain regulations if it provides steam or is
capable of providing steam or hot air to a generator that produces
electricity. A generator itself is not affected by the acid rain
regulations. For the purposes of the Acid Rain Program, a com-
bined cycle turbine — a turbine with a heat recovery steam genera-
tor — will be treated as a single unit.
Combustion Devices
A combustion device is a device that initiates the chemical reac-
tion of fuel and oxygen with the addition of heat. In the case of a
combustion device that uses fossil fuels to produce electricity, the
combustion of fossil fuels causes the reaction of carbon and
hydrogen in the fuel with oxygen in the air to form carbon dioxide
and water vapor. Other substances, such as sulfur in the fuel and
nitrogen in the air, may also react with the oxygen and thereby
produce air pollutants.
Fossil Fuel-Fired
A source is “fossil fuel-fired” if it combusts any amount of fossil
fuel, no matter how small. The definition of fossil fuel includes
natural gas, petroleum, coal, and any form of solid, liquid, or
gaseous fuel derived from these materials, such as petroleum coke.
The definition of natural gas does not include landfill gas, digester
gas, or biomass.** Waste fuels, including anthracite cu lm and
bituminous coal waste, are also considered fossil fuels for the
purposes of the Acid Rain Program. A unit, by definition, is fossil
fuel-fired. Thus, a boiler fueled exclusively by fuels other than
fossil fuels is not a “unit” or “utility unit” under the regulations,
and therefore is not subject to the acid rain regulations.
* See 40 CFR 72.2 for the definition of “utility unit.”
* * See preamble to the final acid rain “core” rules, 58 FR 3596, January 11,
1993.
Examples of Combustion and
Non-Combustion Devices
combustion Devices
Combustion Turbine. A comb us-
tuon turbine uses air heated from
the combustion of fuel to spin the
turbine in a magnetic field, thus
creating electricity. Since it is a
device that uses combustion to
produce electricity directly, it is a
combustion device.
Boiler. A boiler is an enclosed de-
vice that combusts fuel to produce
and transfer heat to recirculating
water, steam, or any other me-
dium. Since it combusts fuel, it is
a combustion device.
Non-Combustion Devices
The! Coil. A fuel cell relies on a
electrochemical reaction of fue’
(usually pure hydrogen) with pure
oxygen to yield energy and water.
Since this reaction is not produced
by the addition of heat, it is not a
combustion device.
4
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Determining Applicability
• Supplies Electricity for Sale
Any unit that served a generator producing electricity for sale in
1985 or on or after November 15, 1990, is potentially affected by
the acid rain regulations. The sale may be wholesale or retail. The
“sale of electricity” is the sale of electrical output or capacity or
the sale of steam to a steam-electric generator that produces
electrical energy for sale.
Units that do not produce electricity or steam for sale are not
affected. Also, a unit that produces steam or heat rather than
electricity for sale is not affected so long as the purchaser of the
steam or heat does not produce electricity for sale. A unit that
produces limited amounts of electricity for sale may not be af-
fected if the unit’s combustion device is used primarily to produce
steam or heat. (See Co generation Unit, below.)
Even if a unit meets all three of the conditions discussed above, it
may be eligible for an exemption or qualify as one of six types of
unaffected units. Exemptions may be granted to new utility units
generating less than 25 MWe and using fuel with a sulfur, content less
than or equal to 0.05 percent, as well as to units that retire. The six
categories of unaffected units are existing simple combustion turbines,
existing small units, cogenerators, independent power production
facilities, qualifying facilities, and solid waste incinerators. The cat-
egories are described below in the sections Exempted Units and Unaf-
fected Units.
5
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Do the Acid Rain SO, Regulations Apply to You?
Exempted Units
Two categories of affected utility units may be eligible for ex-
emptions from many — but not all — of the acid rain regulations: small
new units burning clean fuels and retired units. These exempted units
must continue to meet certain continuing requirements of the Acid
Rain Program to remain exempted. Please refer to Section 2: Require-
ments for Affected and Exempted Units for a list of these requiremen 5
In order for a unit to be considered for an exemption. it must
submit an application to EPA . The Agency does not require eligible
units to apply for an exemption in cases where the owner of a unit does
not want the unit exempted. Units that do not obtain an exemption,
however, must fully comply with the Acid Rain Program require-
ments. If a unit decides to seek and is granted an exemption, it is not
eligible to join the Program on a voluntary basis as a substitution unit,
a compensating unit, or an opt-in unit.
Small New Units Burning Clean Fuels
A utility unit may be granted an exemption from acid rain regula-
tions if it meets all three of the following requirements:*
U The unit is a new unit (i.e., commenced commercial opera-
tion on or after November 15, 1990).
U The unit is a small unit (i.e., serves generator(s) with total
nameplate capacity of 25 MWe or less).
U The unit bums clean fuels (i.e., only fuels with sulfur content
of 0.05 percent or less by weight).
Although the statutory exemption for existing units that serve
generators with nameplate capacities of 25 MWe or less does not sum
the nameplate capacities of all the generators served by the unit, the
exemption for new units requires that the total nameplate capacity
served by the unit be 25 MWe or less. For example, boilers headered
to more than one generator (multi-header units) will be treated as
serving all generators to which they are headered, regardless of the
steam capacity of the boiler.
* See 40 CFR 72.7.
6
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Determining Applicability
A small, ne w unit that is granted an exemption will have to forfeit
any allowances it received or was to receive as an initial allocation for
all years for which the exemption is granted. Also, if the unit gains an
exemption, it must comply with the acid rain regulations for all years
prior to January 1 of the year after it is issued the exemption. For
information on applying for a new unit exemption see Section 2:
Requirements for Affected and Exempted Units.
Definitions
Commence Commercial Operation
A unit “commences commercial operation” when it begins to
generate electricity for sale, including the sale of test generation.
The National Allowance Data Base (NADB Version 2.11) in-
cludes the boiler on-line date and generator on-line date (month
and year). For units in the NADB that commenced commercial
operation by December 1992, the boiler on-line date in the NADB
will be used as the date the unit commenced commercial opera-
tion. If a unit is not listed in the NADB or if a unit commenced
commercial operation after December 1992, the first commercial
on-hne date will be determined in accordance with standards used
by the Energy Information Administration (E IA). In general,
generator first-electricity dates are reported to the U.S. Department
of Energy (DOE), Energy Information Administration on Form
EIA 86O,* and boiler first-fuel consumption is reported on Form
E1A 767.*
Each unit should have only one date of commencement of com-
mercial operation, even if the unit is relocated or restarted after
retirement. However, a unit that was substantially modified before
November 15, 1990, may be treated as a unique unit with a new
commencement of commercial operation date.
Nameplate Capacity
“Nameplate capacity” is a measure of the capacity of a generator.
For a unit listed in the NADB, the nameplate capacity of a genera-
tor is defined as the capacity listed for the generator in the NADB.
If a unit is not listed in the NADB, the nameplate capacity will be
determined in accordance with the DOE standards using Form
EIA-860. Generator nameplate capacity as defined on Form E IA-
860 is the full-load continuous rating of a generator, prime mover,
or other electric power production equipment under specific
conditions as designated by the manufacturer. Installed generator
nameplate rating is usually indicated on the nameplate physically
attached to the generator. If more than one capacity appears on the
nameplate, the highest capacity is reported on Form EIA-860.
* A description of Forms EIA-860 and EJA-767 is provided in the Glosswy.
Example of New Commercial
Commencement
The Tidd plant in Ohio was retired
pnor to 1985. The plant was sub-
stantially modified and repowered
through a clean coal Technology
project and began operation again
in October, 1990. Therefore, EPA
assigned this plant a commenced
commercial operation date of
October 1990.
7
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Do the Acid Rain SO 2 Regulations Apply to You ?
Burns Clean Fuel
Clean fuels are fuels with sulfur content of 0.05 percent or less by
weight. All natural gas, including most “sour” gases, meets this
standard. On-road diesel fuel meeting the new requirements of the
Clean Air Act (Section 211(i)) will also meet this standard. A unit
obtaining an exemption under this provision must test petroleum
or petroleum products and gaseous fuels, other than natural gas,
according to the appropriate ASTM methods to assure compliance
starting on the first day the exemption takes effect .
Retired Units
A utility unit may be granted an exemption from the acid rain
regulations if it retires before the issuance (or renewal) of its Phase H
acid rain permit (see 40 CFR 72.8). These “retired” units must docu-
ment the actual or expected date of retirement as well as any actions
that have been taken to retire the unit and to prevent any further emis-
sions of SO 2 and NOR. If the unit gains an exemption, it must comply
with the acid rain regulations until January 1 of the year after it is
issued the exemption. Therefore, to avoid installation and testing of
continuous emission monitoring (CEM) systems required by the Acid
Rain Program, a unit must apply for this exemption prior to January 1,
1995.
If a retired unit is to resume operation, its Designated Representa-
tive must submit an acid rain permit application not less than 24
months prior to January 1, 2000 or the date the unit is to resume
operation, whichever is later.
For information on applying for a retired unit exemption see
Section 2: Requirements for Affected and Exempted Units.
8
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Determining Applicability
Unaffected Units
Some sources of SO 2 emissions that generate electricity for sale
or provide steam or heat for electricity generation are not subject to
emissions limitations under Title IV. The following six types of elec-.
tricity generat1ng units are not affected by the regulations under
certain conditions:
tJ Existing Simple Combustion Turbines, under 40 CFR
72.6(b)( 1).
( Existing Small Units, under 40 CFR 72.6(b)(2).
D Cogenerators, under 40 CFR 72.6(b)(4).
Li Independent Power Production Facilities, under 40 CFR
72.6(b)(6).
U Qualifying Facilities, under 40 CFR 72.6(b)(5).
Li Solid Waste Incinerators, under 40 CFR 72.6(b)(7).
Units in each category must meet requirements specific to that
category to be unaffected. These requirements are discussed below. A
unit need only qualify as unaffected under one of these categories in
order to be unaffected. In order to remain unaffected, these units must
meet a set of “continuing requirements,” also discussed below.
If a facility is unaffected under more than one provision, it will
remain unaffected until it loses its unaffected status for all appropriate
provisions. For example, if a unit is unaffected as both an IPP and a
QF, then it will remain unaffected if it loses its status as unaffected IPP
but retains its status as an unaffected QF.
The Acid Rain Program does not require an unaffected unit to
submit proof of its status. However, units may be required to provide
documentation supporting their claim of unaffected status, if requested
by EPA or the State or Regional permitting authority. Unaffected units
may become affected under certain operating or construction condi-
tions. It is the duty of the unit’s owner and operator to meet the re-
quirements of the Acid Rain Program if the unit becomes affected.
Also, unaffected units may be eligible to opt-in to the Program, as
discussed above in What This Guide Won’t Tell You.
9
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Do the Acki Rain SO 2 Regulations Apply to You?
Submit the following to.
have EPA deterthine
wh ther your
‘combustion tuthine Is
affected:
/ Information on the, unit’s’ op-
erational characteristics (i.e.,
whether’ the system captures
hot aIr exiting the turbine ;
through a heat recovery steam:
ge erator or a waste heat boiler
or lacks such capability), such
as a, ystem di gram.
/ lnfo ’rmation demonstrating
that the unit did not use auxil-’
iary firing from 1985 to 1987k.
,nor after, Novembe r 15, 1990. i
/ The date the unit ’donimenced
com ’merciál. operation,. as ‘re ,
ported to EIA. ‘ ‘ , • ‘ ,
(1) Existing Simple Combustion Turbines
A utility unit is not affected by the acid rain regulations if it meets
both of the following conditions:
U The unit is a simple combustion turbine.
U The unit is an existing unit (i.e., commenced commercial
operation before November 15, 1990).
Definitions
Simple Combustion Turbine
For the purposes of the acid rain regulations, a “simple combustion
turbine” is defined to include a combined cycle unit that did not
use auxiliary firing in 1985 through 1987 and will not use auxil-
iary firing at any time after November 15, 1990. A combined cycle
unit that uses auxiliary firing during these periods does not qualify
as a simple combustion turbine.
Combined Cycle Unit
In a combustion turbine, air heated from the combustion of fuel
causes a turbine to spin in a magnetic field, which, in turn, creates
electricity. If the hot air exiting the turbine is captured through a
heat recovery steam generator or waste heat boiler, the turbine is a
combined cycle unit.
Auxiliary Firing
In some combined cycle units, additional fuel is burned in a duct
or in a heat recovery steam generator in order to enhance the
production of steam. This is called auxiliary, or supplemental,
firing.
Continuing Requirements
If a simple combustion turbine installs and uses auxiliary firing, it
will become an affected unit. To remain unaffected, a simple combus-
tion turbine may not add or begin using auxiliary firing.
Examples of Combustion
Turbines
Example 1: Two simple turbines
feed a common header to a single
heat recovery steam generator (i.e.,
together they constitute a com-
bined cycle unit) that has auxiliary
firing. Neither turbine qualifies as
a simple ‘combustion turbine.
Example 2: A combustion turbine
serves a heat recovery generator
that installed a duct burner in 1983.
Due to poor efficiency in the duct
burner, the duct burner is not uti-
lized after 1984, although not re-
moved. The turbine is a “simple
combustion turbine” as defined.
10
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Determining Applicability
(2) Ex 5th g iu vL g
Than or Eqi n T©
A utility unit is not affected if it meets both of the following
requiremefl
U The unit serves a small generator (i.e., the largest generator
served by the unit, on or after November 15, 1990, has a
nameplate capacity less than or equal to 25 MWe).
U The unit is an existing unit (i.e., commenced commercial
operation before November 15, 1990).
The term “serve” means either providing steam or being capable
of providing steam to a generator. A unit on cold standby is considered
capable of providing steam. The only units EPA can confirm through
DOEIEIA data as not serving a generator are those units that are
reported as. retired.
Generators listed in the NADB are defined to have the nameplate
capacity listed in the NADB. The regulations are not designed to
penalize units that improve efficiency without increasing emissions.
Thus, if a generator listed in the NADB is modified to produce over 25
MWe capacity because of significant improvements in turbine effi-
ciency only, the units serving this generator do not become affected.
For example, a boiler that in 1988 served a generator of 22 MWe
nameplate capacity, as listed in the NADB, may retain its unaffected
status if that generator is renovated to increase its output capacity from
the same steam input. Unaffected units are required to submit informa-
tion on improved turbine efficiency only if specifically requested by
EPA or the State or Regional permitting authority.
However, if a boiler served a generator of 22 MWe nameplate•
capacity before November 15, 1990, that is replaced with a new
generator of greater than 25 MWe nameplate capacity after November
15, 1990, then that boiler will be affected. Also, if a new generator is
hnked to that boiler and if that generator has a nameplate capacity of
greater than 25 MWe, the boiler will be affected. On the other hand, if
a boiler that serves a generator of 22 MWe nameplate capacity is
hnked to a new generator of 5 MWe nameplate capacity, the boiler
will not be affected because it is not serving any individual generator
of greater than 25 MWe nameplate capacity.
SubmIt the fol owIrig
have EPA dete rm ne
whether your sma l unit
is a ected:
V The nameplate capacity of all
generators served by the unit
on or after November 15, 1990.
/ The date the unit commenced
commercial operation.
Conthuj g R qemetnt
If after November 15, 1990, the existing utility unit serves a
generator with a nameplate capacity of greater than 25 MWe, it will
become an affected unit.
Examples o ExistIng limits
Example 1: Unaffected Unit. In
1985, a boiler served a 5 MWe
generator and a 45 MWe generator
that were used to produce electric-
ity for sale. In 1988, the 45 MWe
generator was retired. The boiler is
not affected because, as of No-
vember 15, 1990, it did not serve
a generator with nameplate capac-
ity greater than 25 MWe.
Example 2: Affected Unit. Three
boilers, two consuming coal and
one burning natural gas, com-
menced commercial operation in
1967. The boilers feed a common
header that serves two generators,
one of 11 MWe nameplate capacity
and one of 26 MWe nameplate
capacity, that are used to produce
electricity for sale. All three boilers
are affected because one of the
generators has a nameplate ca-
pacity greater than 25 MWe. Even
if no one boiler could produce
enough steam to feed the 26 MWe
generator, all boilers are affected.
11
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Do the Acid Rain SO, Regulations Apply to You 7
(3) Cogeneration Units
A cogeneration unit (or cogenerator) is a unit that produces steam
or heat both for direct use and to run an electricity generator.
Definition
Cogeneratlon Unit
A cogeneration unit is a unit that produces electric energy and
various forms of useful thermal energy (such as heat or steam) for
heating or cooling purposes by using the waste heat of one process
as the energy input into a subsequent process. For example, a unit
that produces electricity and then uses the waste heat of that
process as energy to run a process that cools another unit is a
cogenerator.
The statute provides that some cogenerators may not be affected
by the Title IV regulations. Although many cogenerators were con-
structed primarily to serve a specific industrial need, they often sell
excess electricity to local utilities for distribution to the utilities’
customers. Because only “utility units” (i.e., units that are used to
produce electricity for sale) are affected by Title IV regulations, EPA
makes a distinction between cogenerators operating to sell electricity
and those operating primarily for self-generation (e.g., boilers for in-
house use that do not sell electricity).* The key factors are the portion
of “potential electrical output capacity” (a capacity-equivalent of the
boiler) sold and the actual MWe-hrs of electrical output sold.
Which Cogenerators are Unaffected?
For cogeneration units that commenced construction on or before
November 15, 1990, a unit is unaffected if it was constructed for the
purpose of supplying less than or equal to one third of its potential
electrical output capacity or less than or equal to 219,000 MWe-hrs of
annual electrical output.** Documents that can be used for determin-
ing the purpose of construction include permitting applications, con-
struction contracts, and original plant diagrams. In the absence of
information regarding the purpose of construction (often the case with
very old plants), EPA will assume that actual operations from 1985
through 1987 represent that purpose. If the unit began operations after
1985, EPA will use the operational data for the first three calendar
years of operation to make the determination of purpose.
* A cogenerator also may be unaffected by the regulations because it is a qualify-
ing facility or an independent power production facility. These types of facilities are
discussed below.
* 1 219,000 MWe-hours is equal to 25 MWe multiplied by 8,760 hours, the number
of hours in a year.
12
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Determining Applicability
Potential electrical output capacity is the MWe capacity rating for
the unit, which is equal to 33 percent of the maximum design heat
input capacity of the steam generating unit for boilers and simple
combustion turbines. The potential electrical output Capacity for these
units is calculated using the following equation:*
(Maximum Design Heat Input (mniBtu/hr)) X (1,000,000 Btu/l mmBtu)
x (33%) x (1 kw-hr/3,413 Btu) x (1 MWe/l,000 kw) = MWe
For multi-headered boilers, the potential electrical output capacity
for the entire source is equal to the sum of the potential electrical
output capacities for each boiler. To compare an individual boiler’s
potential electrical output capacity to the generator capacity (in MWe),
determine the total generator nameplate capacity (if there are multiple
generators) and divide by the boiler’s proportional share of steam
based on the unit’s potential electrical output capacity (see example).
EPA will work with the unit to determine the appropriate sharing of
output capacity.
For combined cycle combustion turbines, the Agency will con-
sider information as to actual efficiency of a specific system. EPA
understands that many combined cycle combustion turbines operate at
approximately 50 percent efficiency. Thus, to calculate the actual
electrical output, the maximum fuel flow (in mmBtu/hr as an aggre-
gate value for the turbine and any supplemental or auxiliary burners)
multiplied by 50 percent, should be substituted for the first term in the
equation presented above:
(Maximum Fuel Flow (mmBtu/hr)) x (1,000,000 Btull mmBtu)
x (50%) x (lkw-hr/3,4l3 Btu) x (I MWe/l,000 kw) = MWe
For complex multi-headered combined cycle units, the owner/
operator may request to use a formula that more accurately estimates
the potential electrical output capacity for the unit(s).
To determine whether the unit is affected, compare the potential
electrical output capacity to the nameplate capacity of the generator. If
the nameplate capacity of the generator is more than one third of the
potential electrical output capacity, then the annual sales must be
evaluated. If the annual electrical sales exceed 219,000 MWe-hrs, the
unit will be affected.
The calculation of actual electrical output should incorporate
mdirect steam supplied to a steam-electric generator that will produce
electrical energy for sale. Convert the Btus of steam sold to MWe-hrs
based on the equation for potential electrical output capacity above
assunung 33 percent efficiency. Add the MWe-hrs of steam to the
direct MWe-hrs supplied for a total.
Example of Potential
Electrical Output Capacity
A boiler has a maximum design
heat input capacityof 340 mmBtu/
hr. Using the conversion equation,
(340,000,000 Btu/hr) x (1/3) x
(1 kw-hr/3,413 Btu) x (1 MWe/
1,000 kw),
this boiler has a potential electri-
cal output capacity of 33.2 MWe.
Example of Actual Electrical
Output from a Cogenerator
Providing Steam to a
Generator That Provides
Electricity
A cogeneration unit provides
175,000 MWe-hrs of electricity to
the grid and 100 mmBtufhr of
steam to a second generator that
sells electricity.
(100,000,000 Btu/hr) x (1/3) x
(1 kw-hrf 3,413 Btu) x (1 MWe/
1,000kw)x8,76Ohrs/yr=
85,555 MWe-hrs
Thus, the total electricity sold is
175,000 + 85,555 = 260,555
MWe-hrs.
* Appendix D of 40 CFR 72.
13
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Do the Acid Rain S0 Regulations Apply to You?
Example of Cogenerator DetermInations
Situation I:
Boiler 1 (1,024 mmBtu/hr) serves Generator A (50 MWe nameplate)
Boiler 2 (4,100 mmBtu/hr) serves Generator B (50 MWe nameplate)
To calculate Potential Electrical Output Capacity:
Boiler I = (1,024,000,000 Btu/hr) x (33%) x (1 kw-hr/3,413 Btu) x (1 MWe/1,000 kw)
= 100 MWe
Boiler 2 = (4,100,000,000 Btu/hr) x (33%) x (1 kw-hr/3,413 Btu) x (1 MWe/1,000 kw)
= 400 MWe
First, compare nameplate capacity of generator served to potential electrical output capacity of boiler:
Boiler 1 serves 50 MWe/100 MWe = 50% of potential capacity
Boiler 2 serves 50 MWe/400 MWe = 12.2% (Boiler 2 is unaffected because 12.2% is less than 33%.)
Because Boiler 1 serves over 50% of potential electrical output capacity, calculate the actual electrical output at 1/3
potential electrical output capacity for Boiler I only:
Boiler 1 = 1/3 x 100 MWe x 8,760 hr/year = 292,000 MWe-hrs
If Generator A sells less than this every year, Boiler 1 is unaffected as well.
Situation II:
If Boilers I and 2 are multi-headered to Generators A and B, we compare the proportion of electrical output to total
nameplate capacity.
Boiler 1 serves 100 MWe/500 MWe (total unit capacity) x 100 MWe (total generator nameplate) = 20 MWe
= 20% of its Potential Electrical Output Capacity
Boiler 2 serves 400 MWe/500MWe x 100 MWe = 80 MWe
= 20% of its Potential Electrical Output Capacity
(Result - both boilers are unaffected because both produce less than 33% of potential capacity.)
14
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Detei’niining Applicability
iñuhig I equüveanents ____
Unaffected cogeneratOrs must continue to supply one-third or less ,subm , the fo l oowmg to
1 df potentia l electrical output capacity or 219,000 MWe-hrs or less of have EPA detemime
actual electflca l output to any utility power distribution system for sale whether your
annually calculated as an average over any three calendar year penod cogeneration 1 unit ls l
atter iNovember 15, 1990 If a cogenerator does not meet this require- affected
ment, t will become affected / The date the ui it commenced
construction
/ A system diagram of the
steam/electric facil 1 ty ‘
/ If the unit commenced con
s ruction before Nqvember p15,
1990, information as to the ‘pur
pose of the unit and/or steam
and electn6ity sales and 1 usel
____________________________________________________ data from 1985 through 1987
Example of Continuing Requirements and Applying the / The na?rieplate capacity of
Three-Year Rolling Average 4 each generator served by the
Year S sold 210 000 MWe-hrs electricity unit
9 ” The tmaxirnum 4 desidnfl,
Year 2 sold 215 000 MWe-hrs electricity b
input: (in :mm6tu/hr)ief th. , . unit
Year 3 sold 200 000 MWe hrs electricity and of all other units headered
4 so(d 248 000 MWe-hrs electricity to the generators it serves
jhe three calendar year rolling average for Years 2 through 4 is / If the facility is in operation
221 000 MWe-hrs Thus if the average electrical outputexceeds thç annual ,electrioal sales (in
1/3 of the potential electrical output capacity in Years 2 through MWe hrs)
4 the unit would become affected beginning in Year 4 / The annual steam sales
______________ (mmBtu) that are used to pro-
duce eleatricity
15
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Do the Acid Rain SO 2 ReguIatior Apply to You?
(4) Independent Power Production Facilities
and (5) Qualifying Facilities
Certain independent power production facilities and qualifying
facilities are not affected by the Acid Rain Program regulations.
Definition
Independent Power Production Facility (1PP)
An “independent power production facility” (IPP) is a source
developed, usually by private investors, to serve as a wholesaler of
power to a public utility. The Public Utility Regulatory Policies
Act of 1978 (PURPA) provided a loose framework for the IPP
industry. IPPs may offer utilities energy at lower cost and lesser
risk than building electric plants or purchasing power from other
utilities. LPPs and utilities negotiate preliminary power commit-
ments, which often include 20- or 30-year terms. After obtaining
the commitment, the project developers negotiate fuel supply,
transportation contracts, construction contracts, site lease, and
other project specifications. For these projects, lenders have
recourse only to the assets and cash flows associated with a
specific project and not to a parent company or partner companies
that provide equity or other assurances. This type of financing is
called “nonrecourse project financing.”
In order for an IPP project to be unaffected by the Title IV regula-
tons, it must meet the following requirements:
U The project must be nonrecourse project financed.
U The project must sell at least 80 percent of the power gener-
ated at wholesale.
o The project must have no more than 50 percent direct public
utility ownership. This does not preclude indirect ownership
of an IPP by a public utility through its unregulated subsid-
iaries or affiliates.
16
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Determining Applicability
Definition
Qualifying Facility (QF)
A “qualifying facility” (QF) is a qualifying cogeneration facility or
qualifying small power production facility as defined under
PURPA. Small power production facilities are facilities generating
not more than 80 MWe that employ renewable resources — such as
water power, solar energy, wind energy, geothermal energy,
biomass, or waste — as a primary fuel.
In order for a cogeneration facility to be a qualifying facility, it
must meet the following requirements:
0 No electric utility or public utility holding company or any
organization* owned by either may own more than 50
percent of equity interest in the facility.
0 The unit must meet operating and efficiency standards
specified in 18 CFR 292.205.
Many cogenerators meet these requirements.
In order for a small power production facility to be a qualifying
facility, it must meet all three of the following requirements:
0 The unit must use fuel that is composed of more than 75
percent biomass, waste, renewable resources, geothermal
resources, or some combination of the above.
U Fossil fuels must compose less than 25 percent of the fuel
used by the facility.
U No electric utility or public utility holding company or any
organization* owned by either may own more than 50
percent of equity interest in the facility.
As few small power production facilities meet QF fuel require-
ments, most QFs are qualifying cogeneration facilities.**
In some instances, a qualifying small power production facility
may be unaffected under the provisions applicable to solid waste
incinerators. Qualifying cogeneration facilities may also be unaffected
under the cogenerator provisions, but qualifying cogeneration facilities
need only satisfy the provisions for any one of the six types of electric-
ity-generating units described (see 40 CFR 72.6(b)) in order to be
unaffected.
* Organization as defined as “person” in the Federal Power Act, Section 3. This
definition includes municipalities as well as other individuals and organizations.
** See 18 CFR 292.204.
17
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Do the Acid Rain SO, Regulations Apply to You 2
Example of Whether a Unit Is
Affected based on Total
Planned Net Output Capacity
Example .1: An IPP had qualifying
power purchase commitments
demonstrating that 100 MWe of
capacity was planned and that 17%
of its total planned net output ca-
pacity would be sold. The facility
commences commercial operation
with 110 MWe capacity. As such,
all units at the facility are unaf-
fected (assuming all other require-
ments are met) If an additional
boiler-generator pair, with the same
emission rates as the rest of the
facility, is added for more than 20
MWe additional capacity (bringing
the total capacity of the facility to
over 130 MWe), this new boiler
Nould be affected.
Example 2: An IPP has a power
purchase commitment in 1989 for
SO MWe, but the power purchase
:ommitment did not list planned
capacity. In 1989, the IPP signed a
construction contract for two coal-
ired boilers and generators, with
?ach generator rated at 50 MWe
capacity. In 1992, the IPP signed
3nother power purchase commit-
nent for 70 MWe and contracted
construction of another 50 MWe
lenerator to be served by a gas-
red boiler. The entire facility com-
nences commercial operation in
1996. From these facts, the total
lanned net output capacity of the
acilityon November15, 1990 was
100 MWe. However, part of the
acuity is affected by the Acid Rain
‘rogram because, as constructed,
the facility’s total installed net out-
‘ut capacity is greater than 130%
ifthat planned. Because the ernus-
don rates of SO 2 and NO of the
coal-fired and gas-fired boilers are
lifferent, EPA may choose which
ioiler is affected. Only one boiler,
however, will be affected.
While EPA’s rules provide the limit on ownership interest for
unaffected independent power production facilities, Federal Energy
Regulatory Commission (FERC) rules established under PURPA limit
ownership interests for QFs. FERC rules generally do not allow a
partially or wholly owned subsidiary of an electric utility or electric
utility holding company to have more than 50 percent ownership in a
qualifying facility. *
IPPs and QFs may be regulated under both Title IV and Tide I II.
For example, a unit burning waste fuels for more than 20 percent of its
fuel may be regulated as both a solid waste incinerator under Title III
and as an affected unit under Tide IV. This would occur if “waste
fuel,” which is considered a “fossil fuel” under the Acid Rain Pro-
gram, is considered also to be a “refuse-derived fuel” under the solid
waste incinerator provisions of Title Ill**
Which IPPs and QFS are Unaffected?
In order for an IPP or a QF to be unaffected, it must meet all
three of the following requirements:
0 The facility must meet the definition of an IPP or a QF as
described above.
U The facility must have, as of November 15, 1990, a “qualify-
ing power purchase commitment” to sell at least 15 percent
of its total planned net output capacity.
U The total installed net output capacity of the facility must not
exceed 130 percent of the total planned net output capacity.
The total planned net output capacity of a facility is established
by reference to the power purchase commitment in place as of Novem-
ber 15, 1990 or by reference to other contemporaneous documents,
such as submissions to a State environmental authority or construction
contracts.
For example, a facility with a planned net output capacity of 100
MWe must have, as of November 15, 1990, a qualifying power pur-
chase commitment of at least 15 MWe. If the facility has more than
one qualifying power purchase commitment, the sum of the committed
capacities is compared to the planned capacity (e.g., a facility planned
for 200 MWe could have two qualifying power purchase commitments
for 15 MWe each and be unaffected).
* See 18 CFR 292.206.
* * See Title I I I implementing regulations for detai]s. Some Tale I I I regulations,
specifically those for non-municipal waste, have not been written at this time.
-------
Determining Applicability
Definition __________
Qualifying Power Purchase Commitment
A qualifying power purchase commitment is a formal agreement
or requirement with a utility for the purchase of power Utilities
may include cooperative utilities, municipal electric authonties,
and other sellers of electricity. The most common type of power
comm itment was entered i ip a i
purchase commitment is the power sales agreement (PSA). Other
types of power purchase commitments include a letter of intent to
purchase power at a given pnce, a State regulatory authority order
4It t %tbe \tpower purchase comr
to purchase power, and the selection of the facility as the winning
bidder in a utility competitive bid solicitation
imenttwas entereth tt% Sai i
• . /kThe totai pIanned net toutpub
To be a qualifying power purchase commitment, the power
• .
purchase commitment must meet all three of the following
+ • ror contem oraheoa kdocument l
requiremenLs.
$t ,
The commitment must have been entered into on or before
November 15, 1990.
omm itmentnt t e
U At least one of the following two elements must remain
unchanged (from November 15, 1990 to the present):
the l ident itytof 4he *eIectnca 3o n
• t t * i
— The identity of the electricity purchaser.
a ifl 4 \
— The identity of the steam purchaser and the planned
location of the facility a ç
M*if the facttttyJhas”commenced l
• •
O The commitment must not shift or allow the shift of the cost
of compliance with the acid rain regulations to the purchaser.
If an I PP 4 ,nformat ,on%show -
• r e * c
Contünuiing Requü eirnents
• • •• show4
For IPPs and QFs to remain unaffected, they must continue to
meet the definition of an IPP and QF, respectively, and continue to
meet the requirements stated above. For example, if an IPP continues
cent pA ¼ 4ta 6
to have less than 50 percent direct ownership by a public utility, it will
/ If an IPP, informat ion that
still meet the definition of an IPP and, if it continues to meet the other
requirements, will remain unaffected If an IPP or QF adds capacity
such that the total installed net output capacity is greater than 130
percent of total planned net output capacity, then either some portion
irtg fac iI ity statu s undeNthe
or all of the facility — depending on the facility configuration — will
become affected.
10
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Do the Acid Rain SO ReguTations Apply to You?
merQiaI operaJon after January ’.
1, 1985 hform tiono, o$era
• ‘is 4 , c- ‘ ‘X \ ’ •
\
‘ ,
‘• ,
rnformat o pn operatpons; in -.
k
zt985i986; ar d i98Z as well
••1• .
a fo ’the yearsL1991 on
t ‘
lnformat:on proyided on Form
767 of*4he Department of En-
.
Ad in t ttd (ElA)flickidirig:
M 4
Da
Jsed by the uçnt inciuding:
Btits ,of aste fuel and Btus
l of i u’mê ’d
(6) Waste e ito rs
If a unit is a “solid waste incinerator” that produces electricity for
sale or provides steam or heat for electricity generation, it may be
affected by the acid rain regu1ations . A solid waste incinerator is a unit
that burns nonhazardous solid wastes from commercial or industrial
establishments or the general public (e.g., residences). For example, a
QF that bums municipal solid waste is a solid waste incinerator and
may be unaffected under this provision if it meets the requirements
discussed belOw.
The definition of a solid waste incinerator does not include the
following categories of facilities:
c i Incinerators of hazardous wastes;
Materials recovery facilities;”
ci Qualifying facilities that burn homogeneous wastes (except
for. refuse-derived fuel), including tires and used oil; and
ci Air curtain incinerators burning wood wastes, yard wastes,
and clean lumber.
Which So d Waste linchierators a è Unaffected?
Solid waste incinerators burning less than 20 percent fossil fuels
(on a Btu, or heat input, basis) are not affected by the acid rain regula-
tions. The unit must meet this requirement on average for the three
years from 1985 to 1987 or for the first three calendar years of opera-
tion if the unit began operation after 1985. Solid waste incinerators
may also be subject to other control, technology-based requirements
under the Clean Air Act.
— :ample of Three-Calendar-
Year Rolling Basis
it I - burns 16% fossil fuel,
raged over the year
it 2- burns 16% fossil fuel
r3- burns 19% fossil fuel
it 4- burns 31% fossil fuel
three calendar year rolling av-
eforyears lthrough 3 is 17%.
iever, the three calendar year
ng average for years 2 through
22%, making the unit affected
inning in Year4. (Note that the
must have allowances for Year
January 30 of Year 5.)
Conthn fing eq re ents
An unaffected solid waste incinerator must continue to combust
less than 20 percent fossil fuels (on a Btu basis) on three-calendar-year
rolling average for any period after November 15, 1990, in order to
stay unaffected. Fuel consumption for most units is reported to the
Department of Energy, Energy Information Administration, in’Btus,
on Form EIA-767. •
20
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DJT © 0
: o o1
, unit must comply with acid rain regulations, including
t . holçling allowances sufficient to cover its annual SO 2 emissions,
acid rain permit (which is part of the unit’s general air
p rrnit), having a Designated Representative (DR), and installing and
koperating ystems that continuously monitor emissions of SO 2 , NOR,
and other related pollutants These requirements are discussed below
Th onl jway an affected unit may avoid the full requirements of
the Acid Rain Program is by qualifying for an “exemption,” as de-
scribed in S ctzon 1 Even if a unit is awarded an exemption, it is
subject to certain minimum requirements
Inlorthation presented in this section is provided as summary
,guidance for the Acid Rain Program requirements This section also
pr wides corhphance timehnes for Phase I and Phase II of the Program
as well as fcir continuous emission monitoring (CEM) For more
detailed infc mation on the regulations, please refer to 40 CFR 72-78,
OtnCali ctheAèjd Rain ]H [ otline at (202) 233-9620.
21
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Do the Acid Rain SO, Regulations Apply to You
Continuous Emission Monitoring
Each affected unit must continuously measure and record its
emissions of SO 2 , NOR. and carbon dioxide, as well as volumetric
flow, opacity, and diluent gas, unless otherwise specified in regula-
tions at 40 CFR 75. Most units must be equipped with a continuous
emission monitoring (CEM) system. CEM systems are critical to the
Acid Rain Program for several reasons:
C) They ensure compliance with the emissions limitations.
C) They instill confidence in allowance transactions by certify-
ing the existence and quantity of the commodity being
traded.
U They track the progress of the Program.
The CEM rule (40 CFR 75) also contains provisions for initial
equipment certification procedures, periodic quality assurance and
quality control procedures, recordkeeping and reporting, and proce-
dures for filling in missing data periods. Affected units are required to
report emissions data to EPA ’s Emission Tracking System on a quar-
terly basis. Please refer to the compliance timeline table at the end of
this section for dates by which installation and certification testing of
CEM systems must be complete.
Holding Allowances
Each affected unit must hold an allowance for every ton of sulfur
dioxide emitted during a calendar year. To support this requirement,
EPA has developed an electronic recordkeeping and notification
system, called the Allowance Tracking System (ATS), to keep track of
allowance transactions and the status of allowance accounts. ATS will
provide the official tally of allowances by which EPA will determine
compliance with the emissions limitations.
An ATS account has been established for each unit listed in
Exhibits 1, 2, and 3 of Appendix D. EPA will open an account for
affected units not listed in Exhibits 1, 2, or 3 of Appendix D upon
submittal of Certificate of Representation for the source identifying a
Designated Representative. Once EPA receives a Certificate of Repre-
sentation, it will establish an account for each unit at the source. This
certificate must be submitted to EPA with or-prior to the permit appli-
cation for the unit. Any other party interested in participating in the
trading system may open an ATS account by submitting a general
account application to EPA.
What Are the Monitoring
Renuirements?
The owner or operator of an
affected unit must install CEM
system on the unit and pro-
vide emission reports to EPA
unless otherwise specified in
the regulations. CEM systems
include the following:
O An SO 2 pollutant concen-
tration monitor
O A NO pollutant concentra-
tion monitor
O A volumetric flow monitor
O An opacity monitor
o A diluent gas (oxygen or
C0 2 ) monitor that monitors
CO 2
O A data acquisition and han-
dling system (computer-
based) for recording and
performing calculations
with the data.
Refer to 40 CFR 75 for excep-
tions and other additional re-
quirements.
22
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Requirements for Affected and Exempted Units
The ATS also provides the allowance market with a record of
who is holding allowances, the date of allowance transfers, and the
allowances transferred. The ATS does not, however, record the price
or other terms associated with allowance trades; such information is
better collected and reported by the private sector through established
exchanges or other trade information brokers.
Each affected unit must hold sufficient allowances in its account
by January 30 (or, if January 30 is not a business day, the first business
day thereafter) to cover its emissions for the previous year. For ex-
ample, a new affected unit that commences commercial operation
during 2002 must hold sufficient allowances in its account to cover its
emissions of SO 2 during the year 2002 by January 30, 2003.
If a unit emits more tons of SO 2 than allowances it holds in its
account, the additional tons of SO 2 emitted and not covered by allow-
ances are called “excess emissions.” Under the Acid Rain Program, if a
unit has excess emissions, it must pay $2,000 (adjusted by the Con-
sumer Price Index) per ton of excess emissions and submit an offset
plan. The offset plan tells how many allowances are to be deducted
from the unit’s allowance account for future years to offset the previ-
ous year’s excess emissions. Thus, a unit must make up for all excess
emissions.
Designated Representatives
Each source must appoint one individual, the Designated Repre-
sentative, to represent the owners and operators of the source in all
matters relating to the holding and disposal of allowances for its
affected or exempted units. The Designated Representative is also
responsible for all submissions pertaining to permits, compliance
plans, emission monitoring reports, offset plans, compliance certifica-
tion, and other required information. To specify a Designated Repre-
sentative, complete the Certificate of Representation. The Certificate
of Representa1 ion form and instruction are provided in Appendix E.
Permitting
The Designated Representative for each affected source is re-
quired to file a permit application for the source and a compliance plan
for each affected or exempted unit at the source with the permitting
authority. The permitting authority is either the approved State permit-
ting authority or EPA. Contact the EPA Regional office to determine
the appropriate permitting authority for your unit(s). See Appendix B.
For exempted units, the exemption itself serves as a permit for the
unit. Both permits (for affected units) and exemptions (for exempted
units) must be renewed every five years.
What information Is
Contained in ATS
Accounts?
ATS accounts include the
name and address of the au-
thorized account representa-
tive (the official contact per-
son for the account); the
allowances in current and fu-
ture subaccounts; and a record
of allowance transfers to and
from the account. Information
in the ATS accounts is avail-
able to the public.
What information Must
Be included In Permit
Applications?
The source must complete
standard forms when applying
for an acid rain permit. The
forms request information
about the Designated Repre-
sentative, general plant infor-
mation, specific unit informa-
tion, and a compliance plan
for each affected unit. Forms
can be obtained from a per-
mitting authority. Please refer
to Appendix B.
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Do the Acid Rain SO, Regulations Apply to You?
The Acid Rain Program operating permit details the specific
program requirements and compliance options chosen by each source.
The permits and compliance plans aim to provide flexibility, which is
a goal of the Acid Rain Program as a whole; permits and compliance
plans are designed to complement the marketable allowance program
and foster trading. The permits and compliance plans also let sources
fashion a compliance strategy tailored to their individual needs.
The permit stipulates the initial annual allowance allocation for
each affected unit at a source. The permit application must certify that
each unit’s account will hold a sufficient number of allowances to
cover the unit’s SO 2 emissions for the year and that the unit will
comply with the applicable NO limit. In addition, the compliance
plans may specify alternative measures that will be taken to ensure
compliance. Permits are subject to public comment before approval.
Applying for an Exemption
Small, new units burning clean fuel and retired units that meet the
requirements stated in Section 1: Exempted Units can apply for an
exemption with the permitting authority. The Designated Representa-
tive for a small, new unit can apply for an exemption. Any allowances
allocated to a small, new unit must be surrendered for any year for
which the unit is exempted.
For retired units, the Designated Representative must submit a
petition for written exemption to the permitting authority on or before
(1) the deadline for submitting an acid rain permit application for
Phase H, or (2) if the unit has a Phase II acid rain permit, the deadline
for reapplying for that permit. The petition for written exemption must
contain:
I ] Identification of the unit,
U The applicable deadline for submission,
U The actual or expected date of retirement of the unit,
U A description of any actions that have been or will be taken
with regard to the retirement of the unit, and
U The following statement: “I certify that this unit [ ‘is’ or ‘will
be’ as applicable] permanently retired on the date specified
in this petition and will not emit any sulfur dioxide or nitro-
gen oxides after such date.”
This information must be supplied to the permitting authority on forms
as stipulated by the permitting authority.
24
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Requirements for Affected and Exempted Units
A retired unit obtaining an exemption must comply with the monitor-
ing requirements, as previously discussed, unless an exemption from these
requirements is obtained from the permitting authority. Units that will be
permanently retired prior to January 1, 1995 can be exempted from install-
ing and certifying a continuous emission monitoring system if the Desig-
nated Representative completes a written exemption petition prior to the
deadline for completion of certification tests for the continuous emission
or opacity monitoring systems. Retired units will retain any allowances
they are allocated in 40 CFR 73. An exempted unit shall not resume
operation unless the Designated Representative submits an acid rain
permit application for the unit not less than 24 months prior to the later of
January 1, 2000 or the date the unit is to resume operation. A unit must
comply with all of the acid rain regulations as of the earlier of the date an
exemption expires or the date a permit application is submitted (or re-
quired to be submitted).
The exemption of a small, new unit or a retired unit will take effect
beginning January 1 of the year following the issuance of the written
exemption.
Compliance Timelines
The following table indicates when a specific type of unit becomes
affected by the acid rain regulations, the deadline for that unit to apply for
an acid rain permit, the deadline for completing continuous emission and
opacity monitoring compliance testing, and the first date on which a unit is
required to hold allowances.
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Do the Acid Rain SO 9 Regulations Apply to You?
Compliance T meIines
t it i ;s im it i First Date to Hold
Sii .i iiisT i p t A llowa:c: for Previous
February 15, 1993 Ndvember15 it i993*fl \ *, January 30, 1996
assai l
Pbls% P th 1aterbf anuiy ’ The later of Feb r ua r y 15 the atakf1Nov&nbe (15 f The later of Jan 30 1996
1993, or 90 days before the or Jan. 30 of the year after
plan is activated the plan is activated
wn ka t asa a
Phase ll JanuatyW ’ 2 %k January I, 1996 fle later of Jantfaqfl, January 30, 2001
aasa ’a i $M
\ k tat ? commence rcommem ia k
a a a i e i
;fl \ aJ np Ist a t k
wn i &ana & ia sa tu
N iatsqtsnk n
PhaseMI ’ffhe later bffIM fl j rhelater o J iu jij j The later of January 30
J I 200O )To 0 daft i199 ?t 7 rfte? W 2001 or January 30 of
commencement ofreb year after unit commences
‘commercial operationmbutkk ommerciaL operation*nob commercial operation
fh iate ofêJanuary3lW$ The later of January 30,
Januar 2bOó ot90ThW 5frdà9 it 2001 or January 30 of
‘wi- ‘tt fltt ,t ‘flQ & ’ w
after $hewnit beginnoPn . serves generator , th t $ year after unit is affected
sewe a¼genentor M ith ”fl4 nameplate capacity > 25 a
la m k 253 ?
S i l l S
The later of January I, TheMater ’oNJanuary4* >n % The later of January 30,
r ’ waa ’ wt.’e ’ “ i S ” ‘ ‘ ,t ’ud ‘ w r * a i a ’ i 5S
January t, 2O00 or 90 days 1998, or 24 months before i1995’pr days ,after’ ‘ ‘a 2001 or January 30 of
auxiliary finng commences au iiary finng ponimences year after unit is affected
S f
‘ u S
The later of January 30,
, ‘_w, ‘,, ,5 ‘j , , ‘ “ k , ‘ wy ’ w S a
Januasy 1 200O ’or k9G liayst d995kor 90days after ktbeS i 200 1 or January 30 of
‘ a ’k “a
er a ”3 calendamyext factlity ifai ls;to meetdhen5a year after unit is affected
“ t ” w
RhaseJibThq later oftpRaM The later oQJanuar.1?IttSkl The later of January 30,
2001 or January 30 of
tiñt ?f il ’ kP o itM year after unit is affected
‘ p ’*: ’ ‘k iaaass
flneet4he$efinition$fjam “ Kdefinition ofk qualifying: jg
111111
Th ek? 4 bf ami tYI1W The later of January 30,
2001 or January 30 of
q kk ‘ k ’ M + ‘kO ,i \
M 9 facdit fa i ls toa i t )rqee t di$a year after unit is affected
qmeeuutekdefimtion oftann definitien oNndependent i
e n , ’ “ek nrt* ”tk n + ’
independent$Ower \ , Power J ?roducuoi aFaeihtyM
111111 te l
The later of January 30,
kJanuarY4L \ ’2O0O or :9Oq p i 2001 or January 30 of
k Z+ + t ” + ” ' fl€ ’ ‘Vk “tSkAkk ’w++ %
days after S 9 ca1endan kyear c$endar year iperiodtdurmgr year after unit is affected
es e s S jje ‘\;fl
Category
Unit Listed in Table I of
40 CFR 73.10
Substitution or
Compensating Unit
Unit Listed in Tables 2
or 3 of 40 CFR 73.10
(other than a substitution
or compensating unit)
A New Affected Unit
The later of January 1,
1998, or 24 months before
the date the unit
commences operation
A Previously Affected
Existing Small Unit that
fails to meet continuing
requirements
The later of January 1,
1998, or 24 months before
the unit begins to serve a
generator with nameplate
capacity > 25 MWe
A Previously Affected
Existing Simple
Combustion Turbine
that fails to meet
continuing requirements
A Previously Unaffected
Cogenerator that fails to
meet continuing
requirements
The later of January 1,
1998, or March 1 of the
year following 3 calendar
years during which
continuing requirements
are not met
A Previously Unaffected
Qualifying Facility that
fails to meet the definition
of a qualifying facility
The later of January 1,
1998, or March 1 of the
year following the year
during which the facility
fails to meet the definition
of a qualifying facility
A Previously Unaffected
Independent Pàwer
Production Facility that
fails to meet the definition
of an independent power
production facility
The later of January 1,
1998, or March 1 of the
year following the year
during which the facility
fails to meet the definition
of an independent power
production facility
A Previously Unaffected
Solid Waste Incinerator
that fails to meet
continuing requirements
The later of January 1,
1998, or March 1 of the
year following 3 calendar
years during which
continuing requirements
are not met
2A
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Requirements for Affected and Exempted Units
Examples of Compliance Schedules
Case 1: A previously unaffected cogeneration unit exceeds the 1/3 potential
electrical output capacity and 219,000 MWe hours criteria, when averaged, for
1993, 94, and 95.
The unit must:
No later than March 30, 1996, complete CEMS tests.
No later than January 1, 1998, submit a permit application.
No later than January 30, 2001, hold allowances to cover 2000 emissions.
Case 2: A previously unaffected solid waste incinerator combusts greater than 20%
fossil fuel, when averaged, for 2003, 04, and 05.
The incinerator must:
No later than March 1, 2006, submit a permit application.
No later than March 30, 2006, complete CEMS tests.
No later than January 30, 2007, hold allowances to cover 2006 emissions.
Case 3: A boiler that commenced operation in 1965 serving a 21 MWe generator
has that generator replaced on June 1, 1996 with a 27 MWe generator.
The boiler must:
No later than August 29, 1996, complete CEMS tests.
No later than January 1, 1998, submit a permit application.
No later than January 30, 2001, hold allowances to cover 2000 emissions.
Case 4: An unaffected IPP with 100 MWe total planned net output capacity in 1996
installs that capacity with three natural gas fired turbines. On November 11, 2002,
the facility commences commercial operation of another natural gas turbine of 40
MWe (it has the same emission rate as the other turbines).
The original three turbines remain unaffected.
The new turbine must:
No later than November 11, 2000, submit a permit application.
No later than January 29, 2003, complete CEMS tests.
No later than January 30, 2004, hold allowances to cover 2003 emissions.
a Notes on the timelines:
For Phase I units, if the unit was shut down and not yet operating by November 15,
1993, then all monitonng certification tests must be completed no later than 90
days after the unit recommences commercial operation (not to exceed the date
the unit is turned over to the dispatcher).
For Phase II units, if the unit was shut down and not yet operating by January 1,
1995, then all monitonng certification tests must be completed no later than 90
days after the units recommences commercial operation (not to exceed the date
the unit is turned over to the dispatcher).
The allowance holding date (allowance transfer deadline), if January 30 is not a
business day, is the first business day thereafter.
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Glossary
Many of these definitions have been paraphrased from the definitions included in the Code of
Federal Regulations (40 CFR 72.2). References have been provided where applicable. The Code of
Federal Regulations also contains additional definitions relating to the Acid Rain Program that are
not included here.
Acid Rain Permit: The acid rain portion of a source’s operating permit. It is the legally binding
document specifying acid rain requirements applicable to an affected source. See 40 CFR 72.2.
Affected Unit: A unit that is subject to any acid rain emissions reduction requirement or acid rain
emissions limitation. See 40 CFR 72.2.
Allowance: Under the Acid Rain Program, an authorization to emit up to one ton of sulfur dioxide
during or after a specified calendar year.
Auxiliary Firing: The use of fuel in addition to the primary fuel supply to enhance the production
of steam. For example, a cogeneration facility in which the energy input to the facility is first
used to produce power, and the waste heat is used to provide useful steam where additional
natural gas firing is used to boost the steam/thermal process. This addition of natural gas is
called auxiliary firing. See 18 CFR 292.202.
Boiler: An enclosed fossil or other fuel-fired combustion device used to produce and transfer heat
to recirculating water, steam, or any other medium. See 40 CFR 72.2.
Certifying Official: The person required to sign a request for an applicability determination by
EPA. For a corporation, this should be the president, secretary, treasurer, or vice-president in
charge of a principal business function, or other person who performs similar policy or deci-
sion-making functions. For a partnership or sole proprietorship, this should be a general partner
or the proprietor.
Clean Fuels: Fuels with sulfur content of 0.05 percent or less by weight.
Cogeneration: The combined production of power and useful heat that uses the reject heat of one
process as the energy input into a subsequent process. These processes may be for industrial,
commercial, heating, or cooling purposes. See 18 CFR 292.202.
Cogeneration Unit: A unit that has equipment used to produce electric energy and fonns of useful
thermal energy (such as heat or steam) for industrial, commercial, heating, or cooling purposes,
using the reject heat of one process as the energy input into a subsequent process; a unit that
uses cogeneration. These units are also known as “cogenerators.” See 40 CFR 72.2, Federal
Power Act Section 3(l8)(A), and 18 CFR 292.202.
Combined Cycle Unit: A unit that uses a heat recovery steam generator or waste heat boiler to
capture hot air exiting a steam turbine.
Combustion Device: A device that initiates the chemical reaction of fuel and oxygen with the
addition of heat.
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Do the Ac,d Rain Regulations Apply to You?
Commence Commercial Operation: To begin to generate electricity for sale, including the sale of
test generation. See 40 CFR 72.2.
Commence Construction: To undertake a continuous program of construction or enter into a
contractual obligation to undertake and complete, within a reasonable amount of time, a con-
tinuous program of construction. See 40 CFR 72.2.
Compensating Unit: A unit not otherwise subject to acid rain regulations during Phase I that is
designated as a Phase I unit in a reduced utilization plan. See 40 CFR 72.2.
Construction: The fabrication, erection, or installation of a unit or any portion of a unit. See 40
CFR 72.2.
Designated Representative: The person authorized by the owners and operators of an affected
source to represent the source in matters pertaining to the Acid Rain Program.
See 40 CFR 72.2.
Direct Public Utility Ownership: Direct ownership of equipment and facilities by one or more
corporations, the principal business or which is the sale of electricity to the public at retail. See
40 CFR72.2.
Emissions: Air pollutants exhausted from a unit or source into the atmosphere. See 40 CFR 72.2.
Exemption: An authorization by the EPA Administrator, under 40 CFR 72.7 or 72.8, that exempts
a utility unit from certain acid rain regulations.
Existing Unit: A unit that commenced commercial operation before November 15, 1990, that
served, on or after that date, a generator with nameplate capacity greater than 25 MWe, and that
is not a simple combustion turbine. See 40 CFR 72.2.
Facility: Any institutional, commercial, or industrial structure, installation, plant, source, or build-
ing. For the purposes of the Acid Rain Program, this usually refers to an independent power
production facility or a qualifying facility. See 40 CFR 72.2.
Form EIA-767: Steam-Electric Plant and Design Report submitted to the Department of Energy
containing boiler and fuel consumption information. To obtain this form, write to: US Depart-
ment of Energy, Energy Information Administration (ETA), EI-521, Mail Stop: BG-094 (Form
EIA-767), Washington, DC, 20585.
Form EIA-860: A Department of Energy form completed by each electric utility that operates a
power plant in the United States or plans to operate the plant within 10 years of the filing of the
form. The form includes site information, generator information, operations, energy sources,
and capacity. For the purposes of Form 860, an electric utility is a corporation, person, agency,
authority, or other legal entity or instrumentality that owns or operat s facilities within the
United States for the generation, transmission, distribution, or sale of electric energy primarily
for use by the public. To obtain this form, write to: US Department of Energy, Energy Infor-
mation Administration (ETA), EI-52l, Mail Stop: BG-094 (Form EIA-860), Washington, DC,
20585.
Fossil Fuel: Natural gas, petroleum, coal, or any fuel derived from such material. See 40 CFR 72.2.
G lossarv -2
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G!ossar,’
Fossil Fuel-Fired: Combustion of fossil fuel or any derivative of fossil fuel, alone or in combina-
tion with any other fuel, independent of the percentage of fossil fuel consumed in any calendar
year. See 40 CFR 72.2.
Generator: A device that produces electricity and was or would have been required to be reported
as a generating unit pursuant to the United States Department of Energy Form 860(1990
edition). See 40 CFR 72.2.
Independent Power Production Facility (IPP): An electricity-generating facility that is generally
not regulated by State public utility commissions and that sells power at wholesale, usually to
public utilities. See 40 CFR 72.2.
Listed Units: Units that are listed in Tables 1, 2, or 3 of 40 CFR 73.10 (Exhibits 1, 2, and 3 of
Appendix D). These units are affected (unless exempted) by either Phase I or Phase II of the
acid rain regulations.
Multi-header Generator: A generator served by ductwork from more than one unit. See 40 CFR
72.2.
Multi-header Unit: A unit with ductwork serving more than one generator. See 40 CFR 72.2.
Nameplate Capacity: The maximum electrical generating output that a generator can sustain over
a specified period of time when not restricted by deratings. This figure is listed in the NADB
and on Form EIA-860 for most utility units. See 40 CFR 72.2.
National Allowance Data Base (NADB): A data base established by EPA in order to calculate
Acid Rain Program SO 2 emissions allowances. Version 2.11 includes detailed information on
3,800 boiler-generator pairs and lists the boiler on-line date and generator on-line date. Most of
the boilers and turbines listed in the data base are affected units. See 40 CFR 72.2.
New Unit: A unit that commences commercial operation on or after November 15, 1990, including
any such unit that serves a generator with a nameplate capacity of 25 MWe or less or that is a
simple combustion turbine. See 40 CFR 72.2.
Nonrecourse Project Financing: Financing in which lenders have recourse only to assets and cash
flows associated with a specific project and not to a parent company or partner companies that
provide equity or other assurances. See independent power production facilities and 10 CFR
715.3.
Opt-In: To participate in the Acid Rain Program voluntarily. Units that opt-in to the Program are
given emissions allowances that can be sold to other units, with some restrictions. Exempted
units (i.e., retired units and new units that are granted an exemption) and units otherwise af-
fected are not allowed to opt-in to the Program. Note that the Opt-In Program has not been
finalized as of January 1, 1994.
Phase I Unit: Any affected unit that is subject to an acid rain emissions reduction requirement or
acid rain emissions limitation beginning in the period from January 1, 1995, to December 31,
1999. All Phase I units continue to be affected in Phase 11. See 40 CFR 72.2.
Phase II Unit: Any affected unit that is subject to an acid rain emissions reduction requirement or
acid rain emissions limitation only after January 1, 2000. See 40 CFR 72.2.
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Do the Acid Rain Regulations Apply to You?
Potential Electrical Output Capacity: The MWe capacity rating for a unit. For simple combus-
lion turbines and boilers, this rating is equal to 33 percent of the maximum design input capac-
ity (in mmBtu/hr) of the steam generating unit converted to MWe. See 40 CFR 72.2.
Power Purchase Commitment: A commitment or obligation of a utility to purchase electric
power from a facility pursuant to a power sales agreement, a State regulatory authority order, a
letter of intent to purchase power from the source at a previously offered or lower price, or a
utility competitive bid solicitation that has resulted in a winning bidder. See 40 CFR 72.2.
Power Sales Agreement (PSA): A legally binding agreement between a qualifying facility, an
independent power production facility, an new independent power production facility, or a firm
associated with such facility and a regulated electric utility that establishes the terms and
conditions for the sale of power from the facility to the utility. See 40 CFR 72.2.
Qualifying Facility: A qualifying small power production facility or a qualifying cogeneration
facility as administered under the Federal Energy Regulatory Commission (FERC). See 18
CFR 292 and Federal Power Act, Sections 3(17)(C) and 3(18)(B).
Qualifying Power Purchase Commitment: A power purchase commitment in effect as of
November 15, 1990, that meets the following requirements:
U The identity of the electrical purchaser does not change, or
U The identity of the steam purchaser and the planned location of the facility do not change,
and
U The cost of compliance with the acid rain regulations are not allowed to shift to the pur-
chaser.
See 40 CFR 72.2.
Retired Unit: A unit that has ceased operation and certified that it will not recommence operation.
See 40 CFR 72.8.
Simple Combustion Turbine: A unit that is a rotary engine driven by a gas under pressure that is
created by the combustion of any fuel. This includes combined cycle units without auxiliary
firing and combined cycle units with auxiliary firing that did not use auxiliary firing in 1985
through 1987 and will not use auxiliary firing at any time after November 15, 1990. See 40
CFR 72.2.
Solid Waste Incineration Unit: A distinct operating unit of any facility that combusts any solid
waste material from commercial or industrial establishments or the general public. This does
not include most materials recovery facilities, qualifying small power production facilities, or
air curtain incinerators. See Clean Air Act, Section 129(g)(1).
Source: Any governmental, institutional, commercial, or industrial structure, installation, plant,
building, or facility that emits or has the potential to emit any regulated air pollutant under the
Clean Air Act. See 40 CFR 72.2.
Substitution Units: An affected unit that is designated as a Phase I unit in a substitution plan under
40 CFR 72.41. See 40 CFR 72.2.
Total Nameplate Capacity: The sum of the nameplate capacities to which a unit is headered.
G IossArv4
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Glossary
Unaffected Unit: A unit that is not subject to any acid rain emissions reduction requirement or acid
rain emissions limitation.
Unit: A fossil fuel-fired combustion device. See 40 CFR 72.2.
Utility: Any facility, company, or person that sells electricity. See 40 CFR 72.2.
Utility Unit: A unit owned or operated by a utility that serves a generator that produces electricity
for sale. This includes, in some instances, electrical generating equipment owned or operated
by entities that are not public utilities, such as manufacturers and independent power producers.
This does not include units that did not serve a generator in 1985 or on or after November 15,
1990. This also does not include most cogeneration units. See 40 CFR 72.2.
e
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Appendix A
Selected Acid Rain
Regulations and Documents
The Acid Rain Program regulations and documents have been produced as a series and include
those listed below:
Auctions, Direct Sales, and Independent Power Producers Written Guarantee
40 CFR 72
Final December 17, 1991, 56 FR 65592
Additional materials located in EPA Air Docket A-91-32.
Acid Rain Program: General Provisions and Permits, Allowance System, Continuous Emis-
sion Monitoring, Excess Emissions, and Administrative Appeals
40 CFR 72, 73, 75, 77, and 78
Final January 11, 1993, 58 FR 3590
Additional materials located in EPA Air Dockets A-90-38 (for permits-related materials), A-91-43
(for allowance systems), A-90-5 1 (for continuous emission monitoring), A-91 -68 (for excess emis-
sions), and A-91-69 (for the general docket).
Acid Rain Allowance Allocations and Reserves
40 CFR 72, 73, and 75
Final March 23, 1993, 58 FR 15634
Additional materials located in EPA Air Docket A-92-06.
Acid Rain Provisions: Notice of Availability of the
National Allowance Data Base
Revised Final Data Base, version 2.11, March 23, 1993, 58 FR 15720
Additional materials located in EPA Air Docket A-92-07.
Acid Rain Program: Nitrogen OxIdes Emission
Reduction Program
40 CFR 76
Proposed November 25, 1992, 57 FR 55632
Additional materials located in EPA Air Docket A-92-15.
Acid Rain Program: Permits and Allowance System (Opt-In)
40 CFR 74
Proposed September 24, 1993, 58 FR 50087
Additional materials located in EPA Air Docket A-93-15.
-------
Do the Acid Rain SOp. Regulations Apply to You?
Acid Rain Program: Permits and Allowance System (SubstItution & Compensating Units)
40 CFR 72 and 73
Proposed November 18, 1993, 58 FR 50949
Additional materials located in EPA Air Docket A-93-40.
To obtain a copy of any of these documents, call the Acid Rain Hotline at (202) 233-9620.
A-2
-------
Appendix B:
EPA Regional and State
Office Addresses
Contacts
Region I
JFK Building
One Congress Street
Boston, MA 02203
(617) 565-3800
FAX#: (617)565-4939
Region 2
Jacob K. Javitz Federal Building
26 Federal Plaza
New York, NY 10278
(212) 264-2301
FAX#: (212) 264-7613
Region 3
841 Chestnut Building
Philadelphia, PA 19107
(215) 597-9390
FAX#: (215) 597-3156
345 Courtland Street, NE.
Atlanta, GA 30365
(404) 347-3043
FAX#: (404) 347-3059
Region 5
77 West Jackson Boulevard (A-i 8J)
Chicago, IL 60604
(312) 353-2212
FAX#: (312)353-1661
Region 6
First Interstate Bank Tower
1445 Ross Avenue (MC6T-AN)
Dallas, TX 75202-2733
(214) 655-7200
FAX#: (214) 655-2164
Region 7
726 Minnesota Avenue
(ARTX/ARBRJPERM)
Kansas City, KS 66101
(913) 551-7404
FAX#: (913) 551-7065
Region 8
999 18th Street, Suite 500 (8ART)
Denver, CO 80202-2466
(303) 293-0946
FAX#: (303) 294-7559
Region 9
75 Hawthorne Street (A-3-1)
San Francisco, CA 94105
(415) 744-1219
FAX#: (415)744-1076
Region 10
1200 Sixth Avenue (AT-082)
Seattle, WA 98101
(206) 553-4152
FAX#: (206)553-0110
Region 4
EPA Regional
D l
-------
Do the Acid Rain Regulations Apply to You?
State Contacts
Alabama
Environmental Management Department
1751 Congressman W.L. Dickinson Drive
Montgomery, AL 36130
(205) 271-7706
FAX#: (205) 271-7950
Arizona
Environmental Quality Department
3033 N. Central Avenue
Phoenix, AZ 85012
(602) 207-2300
FAX#: (602) 207-2218
Arkansas
Department of Pollution Control and Ecology
P.O. Box 9583
Little Rock, AR 72219
(501) 570-2130
FAX#: (501) 562-4632
Calitorn la
California Air Resources Board
P.O. Box 2815
Sacramento, CA 95812
(916) 445-4383
FAX#: (916) 322-6003
California Environmental Protection Agency
555 Capitol Mall, Suite 235
Sacramento, CA 95814
(916) 445-3846
FAX#: (916) 445-6401
Colorado
Office of Environment
Colorado Department of Health
4300 Cherry Creek Drive South, OE-B2
Denver, CO 80222-1530
(303) 692-3099
FAX#: (303) 782-4969
Connecticut
Department of Environmental Protection
79 Elm Street
Hartford, CT 06106
(203) 566-2110
FAX#: (203) 566-7932
Delaware
Natural Resources and Environmental Control
P.O. Box 1401
89 Kings Highway
Dover, DE 19903
(302) 739-4403
FAX#: (302) 739-6242
District of Columbia
Department of Consumer arid Regulatory Affairs
Environmental Regulation Administration
2100 Martin L. King, Jr. Avenue, SE
Washington, D.C. 20020
(202) 404-1136
FAX#: (202) 404-1141
Florida
Department of Environmental Regulation
2600 Blair Stone Road
Tallahassee, FL 32399-2400
(904) 921-9717
FAX#: (904) 487-4938
Georgia
Department of Natural Resources
205 Butler Street, S.W., Suite 1252
Atlanta, GA 30334
(404) 656-4713
FAX#: (404) 656-0770
Idaho
Division of Environmental Quality
1410 N. Hilton Street
Boise, ID 83720
(208) 334-0502
FAX#: (208) 334-0417
Illinois
Illinois Environmental Protection Agency
2200 Churchill Road
P.O. Box 19276
Springfield, IL 62794
(217) 782-339’7
FAX#: (217) 782-9039
Indiana
Indiana Department of Environmental Management
100 N. Senate, Room 1301
Indianapolis, IN 46204
(317) 232-8162
FAX#: (317)232-8564
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Appendix B
Iowa
Environmental Protection Division
Iowa Department of Natural Resources
Wallace State Office Building
Des Moines, IA 50319
(515) 281-6284
FAX# (515) 281-8895
Kansas
Department of Health and Environment
900 S.W. Jackson, Suite 901
Topeka, KS 666 12-1290
(913) 296-0461
FAX#: (913) 296-6231
Kentucky
Natural Resources and Environmental Protection Cabinet
5th Floor, Capital Plaza Tower
Frankfort, KY 40601
(502) 564-3350
FAX#. (502) 564-4245
Louisiana
Department of Environmental Quality
P.O. Box 44066
Baton Rouge, LA 70804
(504) 765-0639
FAX#: (504) 765-0746
Maine
Department of Environmental Protection
State House Station 17
Augusta, ME 04333
(207) 287-2812
FAX#: (207) 287-7826
Maryland
Department of Environment
2500 Broening Highway
Baltimore, MD 21224
(410) 631-3084
FAX#: (410) 631-3888
Massachusetts
Department of Environmental Protection
One Winter Street
Boston, MA 02108
(617) 292-5856
FAX#: (617) 556-1049
Environmental Affairs Executive Office
One Winter Street
Boston, MA 02108
(617) 727-9800
FAX#: (617) 727-2754
Michigan
Department of Natural Resources
Box 30028, Steven 1. Mason Building
Lansing, M l 48909
(517) 373-2329
FAX4#: (517) 335-4242
Minnesota
Minnesota Pollution Control Agency
520 Lafayette Road, 6th floor
St. Paul, MN 55 155-3898
(612) 296-7303
FAX#: (612) 296-7923
Mississippi
Department of Natural Resources
Box 10305
Jackson, MS 39289-1305
(601)961-5000
FAX#: (601) 354-6965
Missouri
Department of Natural Resources
205 Jefferson Street, P.O. Box 176
Jefferson City, MO 65102
(314)751-4422
FAX#: (314) 751-7627
Montana
Environmental Sciences Division
Department of Health and Environmental Science
Cogswell Building
Helena, MT 59620
(406) 444-3948
FAX#: (406) 444-1374
Nebraska
Environmental Control
P.O. Box 98922
Lincoln, NE 68509
(402) 471-2186
FAX#: (402) 471-2909
Nevada
Environmental Protection Division
Nevada Department of Conservation and
Natural Resources
333 West Nye Lane
Carson City, NV 89710
(702) 687-4670
FAX#: (702) 687-5856
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Do the Acid Rain Regulations Apply to You?
New Hampshire
New Hampshire Department of Environmental Services
Hazen Drive, P.O. Box 95
Concord, NH 03301
(603) 271-3503
FAX#: (603) 271-2867
New Jersey
Department of Environmental Protection and Energy
401 East State Street - CN 402
Trenton, NJ 08625
(609) 292-5617
FAX#: (609) 984-3962
New Mexico
Department of Environment
P.O. Box 26110
Santa Fe, NM 87503-0968
(505) 827-2850
FAX#: (505) 827-2836
New York
Environmental Conservation Department
50 Wolf Road
Albany, NY 12233
(518) 457-3446
FAX#: (518) 457-6996
North Carolina
Environmental Protection
North Carolina Department of Environment, Health and
Natural Resources
P.O. Box 27687
Raleigh, NC 27611-7687
(919) 715-4140
FAX#: (919)715-3060
North Dakota
Environmental Health Section
1200 Missouri Avenue, Box 5520
Bismarck, ND 58502-55 20
(701) 221-5150
FAX#: (701) 221-5200
Ohio
Ohio Environmental Protection Agency
P.O. Box 1049
1800 Watermark Drive
Columbus, OH 43266-0149
(614) 644-2782
FAX#: (614) 644-3184
Oklahoma
Oklahoma Department of Environmental Quality
1000 N.E. 10th Street
Oldahonia City, OK 73117-1299
(405) 271-8056
FAX#: (405) 271-7339
Oregon
Department of Environmental Quality
811 S.W. Sixth Avenue
Portland, OR 97204-1334
(503) 229-5395
FAX#: (503) 229-6124
Pennsylvania
Department of Environmental Resources
400 Market Street
Hamsburg, PA 17105-2063
(717) 787-5028
FAX#. (717) 783-8926
Rhode Island
Department of Environmental Management
9 Hayes Street
Providence, RI 02908
(401) 277-2771
FAX#: (401) 277-6802
South Carolina
Environmental Quality Control
Department of Health and Environmental Control
2600 Bull Street
Columbia, SC 29201
(803) 734-5360
FAX*: (803) 734-5199
South Dakota
Department of Environment and Natural Resources
523 E. Capitol Avenue
Pierre, SD 57501
(605) 773-5559
FAX#: (605) 773-6035
Tennessee
Department of Environment and Conservation
21st Floor, L & C Tower
401 Church Street
Nashville, TN 37243-0435
(615) 532-0109
FAX#: (615) 532-0120
B-4
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Appendix B
Texas Wyoming
Texas Natural Resource Conservation Commission Department of Environmental Quality
1700 North Congress, Room 123 Herschler Building, 4th Floor West
Austin, TX 78701 Cheyenne, WY 82002
(512) 463-7901 (307) 777-7938
FAX#: (512) 475-2332 FAX#: (307) 777-7682
Utah
Department of Environmental Quality
168 North 1950 West
P.O. Box 144810
Salt Lake City, UT 84116-4810
(801) 536-4400
FAX#: (801) 538-4401
Vermont
Vermont Agency of Natural Resources
103 S. Main Street, Building 1-South
Waterbury, VT 05676
(802) 241-3600
FAX# (802)244-1102
Virginia
Department of Environmental Quality
9th Street Office Building
Richmond, VA 23219
(804) 786-0044
FAX# (804) 371-8333
wasnungcon
Department of Ecology
P .O. Box 47600
Olympia, WA 98504-8711
(206) 407-7001
FAX#: (206) 493-9495
West Virginia
Natural Resources Department
800 Washington Street
Charleston, WV 25305
(304) 558-2754
FAX#: (304) 348-2768
Wisconsin
Wisconsin Department of Natural Resources
P.O. Box 7921
Madison, WI 53707
(608) 266-2121
FAX#: (608) 266-6983
-------
Appendix C
Applicability Determination
Examples
This appendix provides examples illustrating how to work through the flow chart to determine
applicability of the Acid Rain Program to a specific unit. Each example includes facts about a
hypothetical unit, the applicability decision for that unit, and an annotated flow chart.
r’ I
-------
Do the Acid Rain Regulations Apply to You?
Example 1: Listed Unit
Facts: This unit is listed in Table 2 of 40 CFR 73.10 (Exhibit 2 of Appendix D). A prospective
owner wants to buy the unit and convert it to bum only non-fossil fuels. The unit will
continue to supply steam to a 50 MWe capacity generator that sells electricity.
1.
The unit is listed in Table 2,
so continue to the next
decision point.
Is the
unit...
‘MU
..Jlstsd?
— .1
...,nlabkl.2 .or3of4OCFR7
5ee Appendix D
lItt:te4
ii f
cog twrati)r
Yes
-------
Appendix C
Decision: The unit is affected even if it is converted to consume non-fossil fuels. Note that the unit
will retain its allowance allocation even though it uses non-fossil fuels.
Mfl
ifl(;IIlerdtOf?
newi
..a s n1pk ne t
Th
srvin iu,aH
gun iatut L ;)
Tr
...
I
2.
Afthough the unit will
use clean fuel, it serves
a 50 MWe generator,
so it is affected.
-------
Do the Acid Rain Regulations Apply to You?
Example 2: Cogenerator Not Selling Electricity
Facts: This unit is not listed in Tables 1, 2, or 3 of 40 CFR 73.10 (Exhibits 1, 2, or 3 of Appen-
dix D). The cogenerator commenced commercial operation in 1988 and burns primarily
coal, but also some wood waste and natural gas. The cogenerator was constructed to
supply steam to an industrial facility. Neither the cogenerator nor the industrial facility
has sold any electricity since the commencement of operations.
Is the
unit...
1.
The unit is not listed
in Tables 1, 2, or 3,
so proceed to the
next decision point.
2.
The unit is a combustion device
burning fossil fuel, but its output
does not go to the production of
electricity for sale, so it is
...Usted?
..inTabI ! ,2 ,or3of4OCF
lSee App ndhc D)
LI
rn PI’
U I?
QF!
a gt n.iatm ?
4
-------
Appendix C
Decision: The unit is unaffected, because its output does not go to the production of electricity for
sale. If the industrial facility buying the steam was using it to produce electricity that was
then sold to the public utility grid, then one would have to continue through the flow
chart to determine whether the unit is affected.
a
ltnb n ?
Ii
II
• •usmg
dean fuel
C-5
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Do the Acid Rain Regulations Apply to You?
Example 3: Qualifying Facility
Facts: There are two oil- and gas-fired boilers headered to one generator at this facility. In 1986,
during the planning of the facility, the facility owners filed for self-certification of quali-
fying cogeneration facility status with the Federal Energy Regulatory Commission
(FERC). The facility is the subject of a power sales agreement, executed in 1987, for 40
MWe with a utility. The facility’s construction contract specifies a generator of 50,000
kVA at a power rating of 85% (equivalent to 42.5 MWe). The facility also has a steam
sales agreement with a local prison. The facility was completed and commenced opera-
tion in 1992 with a 43 MWe nameplate capacity generator. The power sales agreement
has not been changed or amended. The unit is not listed in Tables 1, 2, or 3 of 40 CFR 73.10
(Exhibits 1, 2, or 3 of Appendix D).
Is the
unit...
1.
The unit is not listed
in Tables 1, 2, or 3,
so proceed to the
next decision point.
2.
The unit is a combustion
device burning fossil fuel
producing electricity for
sale, so proceed through
the next decision points.
...Ilsted?
3.
The facility meets the
requirements for an
unaffected qualifying
facility, so it is
unaffected
...potentiafly
affected?
...thatfl)asot1t 0.
Yes had a quaHlylng pr)wnr purchase
_ agreement to tell at least 15% of
net planned capacity and 123 has
Lj
net installed capac,tt, c 130% of
net planned capacuyt
J , , es
I
a
-------
Appendix C
Decision: Neither boiler at this facility is affected. The facility meets the requirements for an
unaffected qualifying facility:
LI It meets the definition of a qualifying facility;
LI It had a qualifying power purchase commitment as of November 15, 1990; and
LI It has installed capacity less than or equal to 130% of its planned net capacity.
II
‘K
‘a
Ins Invi attn I
II
a t pLn ts,rm* ?
r
! t svin sanafl
—
th&i*i I 5U II
I I
4 •.
a a
C-7
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Do the Acid Rain Regulations Apply to You?
Example 4: Cogenerator Selling Electricity
Facts: An industrial company built a cogeneration facility to serve the company’s adjacent
manufacturing plant. The facility commenced commercial operation with a single boiler-
generator pair in 1991. The boiler has a maximum design heat input of 1,024 mmBtu/hr
(which calculates to potential electrical output capacity of 100 MWe), and the generator
has a nameplate capacity of 75 MWe. When the needs of the manufacturing plant are
low, the industrial company sells the excess power to a public utility. The amount of
electricity sold to the public utility (gross sales) in any one year has not exceeded, and is
not expected to exceed, 200,000 MWe-hrs. The unit is not listed in Tables 1, 2, or 3 of 40
CFR 73.10 (Exhibits 1,2, or 3 of AppendixD).
2.
fres
a
1.
The unit is not listed
in Tables i, 2, or 3,
so proceed to the
next decision point.
The unit is a combustion
device burning fossil fuel
producing electricity or
sale, so proceed through
the next decision
3.
Is the
unit .Hstd?
The unit is a cogenerator
selling less than 219,000
MWe-hrs of electrical
output to the grid and
construction commenced
after 11/15/90, so it is
• unaffected.
an IPP or a QF?
aofl buchondev e
n cogensrator?
pp
,uppllid I averageo( 1 13
iI I.c t a p 4capacs1y
)• 21LQOOMivito Ib.gc Idk r ,.I.(or
prrlod afier 11/15 190 ai,d 12) w
the
a
C-8
-------
Appendix C
Decision: The unit (boiler) is unaffected because it meets the requirements for an unaffected
cogenerator. The gross annual electricity sales are less than or equal to one-third of the
potential electrical output capacity or less than or equal to 219,000 MWe-hrs.
First, calculate the potential electrical output capacity (100 MWe), then compare this to
the generator nameplate capacity. In this example, 75% of the boiler’s capacity can be
used to generate electricity. Because this level (75%) is greater than one-third, calculate
the maximum number of MWe-hrs that could be sold at one-third potential electrical
output capacity. This figure is 292,000 MWe-brs (see Example of Cogenerator Determina-
tions on page 14 of Section 1). Since 200,000 MWe-hrs (the amount of the unit’s gross
electricity sales) is below both the 292,000 MWe-hrs and 219,000 MWe-hrs criteria, the
boiler is unaffected;
U4;U 49
d cw
a__
a pJt hH n ?
rn aU
II
• n ung
;. k 4bfl mel?
+
c-9
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Do the Acid Rain Regulations Apply to You?
2.
Example 5: Solid Waste Incinerator
Facts: A solid waste incinerator commenced operation in the 1970s and generally consumes 25
to 30% of its fuel in the form of number 2 diesel fuel. By 1995, the facility expects to
consume less than 20% fossil fuels by burning more consumer waste. It is not listed in
Tables 1,2, or 3 of 40 CFR 73.10 (Exhibits 1, 2, or 3 of Appendix D).
flt uatawTa ed v3
had a qualltyln pow , purchase pcio o l e ectri .I apcity
anienttc&f atreasUS%of No No
netplannedcapacityand(2)hac .
net lns&afl ed c pac fl 3O% of co ucted fr* l w surpool outl Ined in Ii ) f
net planned capac y crerucilon commenced on or betliwe Il/i
...anIPPoraQF? .
...a cogenerator?
1.
The unit is not listed
in Tables 1, 2, or 3,
so proceed to the
next decision point.
The unit is a combustion
device burning fossil fuel
producing electricity for
sale, so proceed through
the next decision points.
Is the
unit...
listed?
p .
...potentially
affected?
I.
c-b
-------
Appendix C
Decision: The facility is affected because it consumed greater than 20% fossil fuels during the
baseline period, 1985-1987. The current and future consumption rates are irrelevant in
this case.
3.
The unit is an incinerator, but it combusted >20%
fossil fuels during the baseline period 1985 to 1987.
Because the unit does not qualify as exempt or
unaffected under any subsequent provision in the
flow chart, it is affected.
No
a simple turbine?
ii
‘11
att cap dty
1fl5/90?
‘II
c-Il
-------
Do the Acid Rain Regulations Apply to You?
Example 6: New, Small, Clean Unit
acts: A unit is planned to commence commercial operation in March 1998. It is not listed in
Tables 1, 2, or 3 of 40 CFR 73.10 (Exhibits 1, 2, or 3 of Appendix D), nor is it listed in
the National Allowance Data Base (NADB). It is planned to consume at least 90% natu-
ral gas, so its fuels average sulfur content will be below 0.05% by weight. The boiler will
serve one generator with nameplate capacity of 15 MWe.
‘11
a
2.
1.
The unit is not ilsted
in Tables 1,2, or 3,
so proceed to the
next decision point.
The unit is a combustion
device burning fossil fuel
producing electricity for
sale, so proceed through
the next decision points.
p.
Is the
unit Ist.d?
...a ccg.nsrator?
Yes
I-
a
C-i.2
-------
Appendix C
Decision: The unit is eligible for the exemption as a small, new unit burning clean fuels. It re-
ceived no allowance allocation initially, so it does not need to forfeit allowances. The unit
may be able to avoid the requirements to install and test CEMS by receiving its exemp-
tion before January 1, 1998. Without this exemption, the unit would be required to install
and certify CEMS within 90 days of the unit’s commencement of commercial operation
(see Compliance Timelines) in June 1998. if the unit files for and receives its exemption
in 1997, the exemption goes into effect January 1, 1998, in time to avoid the requirements
to install and certify CEMS (see 40 CFR 72.7(c) and 75.4(b)(1)).
4
3.
The unit commenced
commercial operation after
11/15/90, so it qualifies as
a new unit.
incln.rator?
a
t U1 P ‘
1
N,
U ,’
...usI
combus*ig or 4y
4.
The unit meets the
definition of using clean
fuel, so it qualifies for an
exemption.
C-13
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Do the Acid Rain Regulations Apply to You?
Example 7: Retired Unit
Facts: A unit is listed in Table 1 of 40 CFR 73.10 (Exhibit 1 of Appendix D). The unit is pres-
ently on “cold standby” status; that is, it is not immediately operable but could be brought
on-line within 6 months. The owners have decided to formally retire the unit in 1995.
*
1.
The unit is listed in Table 1,
so continue to the next
decision point.
Is the
unit... ..Jst.d?
Ii
•,tI fIt .4lIY
i u ( t( d’
(See Ap *ndi D)
I
•. )H IPP (U Q1
I
i ( flt f itffl ?
‘a
C-14
-------
Appendix C
Decision: The unit Is eligible for the retired units exemption of 40 CFR 72.8. Because it is a
Phase I affected unit, it must meet all applicable Acid Rain Program requirements until
January 1 of the year after the unit is granted its exemption. Applicable acid rain require-
ments include holding sufficient allowances to cover its annual SO 2 emissions (for emis-
sions in 1995 and thereafter), obtaining an acid rain permit, having a Designated Repre-
sentative, and installing and operating systems to monitor emissions, as required by 40
CFR75.
I.’
in iiiei atur’
4 J
•.a irnpk turbm* ?
-
‘a
* ,P1vmg Mu 1tJ
gent’aat(Pr( •P
a
U
—
2.
The unit is not combust-
ing any fuel. It has
ceased operation and
will be formally retired
in 1995, so it is eligible
for an exemption.
C-15
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Do the Acid Rain Regulations Apply to You?
Example 8: Existing Simple Combustion Turbine
Facts: A unit is a simple combustion turbine that is not listed in Tables 1, 2, or 3 of 40 CFR
73.10 (Exhibits 1, 2, or 3 of Appendix D). It commenced commercial operation in 1983
and does not have auxiliary firing. The owner plans to sell it to another utility. That utility
plans to move the turbine, refurbish it, and rename it. The turbine is listed in the National
Allowance Data Base (NADB) with the 1983 on-line date.
1.
Is the
unit...
The unit is not listed
in Tables 1, 2, or 3,
so proceed to the
next decision point.
The unit is a combustion
device burning fossil fuel
producing electricity for
sale, so proceed through
the next decision points.
...IIst.d?
p
U
...anIPPoraQF?
...a ccg.n.rator?
. .. . ... ... . ...
C-16
-------
Appendix C
Decision: The turbine is unaffected as an existing simple combustion turbine. The new dvnër
should not change the name of the turbine and should ensure that future subm aisto he
Energy Information Administration (EIA) do not change the on-line date to’ avcj id’bec m-
ing affected as a new unit.
J4.
I The unit is an existing
combustion turbine,
4 ;Ie 4fl •fuel ‘
4
‘1
.t4E I1ftrz1Iol
iufl ;
, , t t( e t?
a
3..
The unit commenced
commercial operation
before 11/15/90, so it is
an existing unit.
an
Incinerator?
H
a simpi. turbine?
C-17
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Do the Acid Rain Regulations Apply to You?
Example 9: Existing Unit Serving A Small
Generator
Facts: A boiler presently serves a generator with nameplate capacity of 18 MWe and, in 1985,
served only this generator. The boiler commenced operation in 1963 and sells electricity
and steam for industrial process use. Because of increased electrical demand at the
industrial site, the owner of the boiler pians to add a generator with nameplate capacity of
8 MWe in 1997.
1.
The unit is not listed
in Tables 1, 2, or 3,
so proceed to the
next decision point.
2.
The unit is a combustion
device burning fossil fuel
producing electricity for
sale, so proceed through
the next decision points.
Is the
unit IIst.d?
p
•• r tsntially
an IPP or a QF?
a cog.n.rator?
a
. .... .,,.. ... ..
C-18
-------
Appendix C
Decision: The unit is currently unaffected and would remain unaffected if it adds the 8 MWe
generator. The boiler is an existing unit, and all current and planned generators served
by it have nameplate capacities of less than 25 MWe (i.e., the statutory cutoff; see Sec-
tion 402(8) of the Clean Air Act). However, if the boiler owner replaces the 18 MWe
(nameplate) generator with a generator of greater than 25 MWe nameplate capacity, the
boiler would become affected, according to 40 CFR 72.6(a)(3)(ii), which affects existing
units that serve, on or after November 15, 1990, generators with nameplate capacities
greater than 25 MWe.
No
4.
3.
The unit commenced
commercial operation
before 11/15/90, so it is
an existing unit.
The unit is an existing unit serving
only generator(s) with nameplate
capacity 25MWe, so it is unaffected.
It will not become affected in 1997
because the additional generator also
has nameplate c j, 25MWe.
U
incinerator?
.new?
I
1. Yes J’
...a simple turbine?
...servlng small
generator(s)?
leaii fuel?
h
4
C-19
-------
•1 .
Appendix
Selected List of Units Affected by
the Acid Rain Regulations
Exhibit 1: Units listed in Table I StateName PlantName Boilers
MINNESOTA
of §73.10 (40 CFR 73) HighBridge 6
lack Watson 4, 5
State Name Plant Name Boilers MISSOURI
ALABAMA Asbury I
Colbert 1,2,3,4,5 James River 5
E C Gaston 1,2, 3, 4,5 Labadie 1,2, 3,4
FLORIDA Montrose 1,2,3
New Madrid 1,2
Big Bend BBOI, BBO2, BBO3 Sibley 3
Crist 6,7
Sioux 1,2
GEORGIA Thomas Hill MBI. MB2
Bowen IBLR, 2BLR, 3BLR, 4BLR NEW HAMPSHIRE
Hammond 1,2,3,4 Merrimack 1,2
Jack McDonough MBI, MB2
Wansley 1,2 NEW JERSEY
Yates YIBR, Y2BR, Y3BR. Y4BR, B L England 1,2
Y5BR, Y6BR, Y7BR EW YORK
ILLINOIS Dunkirck 3,4
Baldwin 1,2, 3 Greenndge 6
Coffeen NO 1,02 Milliken 1,2
Grand Tower 09 Northport 1,2,3
Hennepin 2 Port Jefferson 3,4
Joppa Steam 1, 2, 3,4, 5, 6 OHIO
Kincaid 1,2 Ashtabula 7
Meredosia 05 Avon Lake 11, 12
Vermilion 2 Cardinal 1.2
INDIANA Conesville 1,2, 3,4
Badly 7, 5 Eastlake 1,2, 3,4, 5
Breen I Edgewarer 13
Cayuga 1,2 Gen J M Gavin 1,2
Clifty Creek 1,2,3,4,5,6 Kyger Creek 1,2,3,4,5
Elmer W Stout 50,60,70 Miami Fort 5-1, 5-2, 6.7
F B Culley 2,3 Muskingum River 1.2, 3,4, 5
FrankERatts 1SG I,2SG1 Niles 1,2
Gibson 1,2, 3,4 Picway 9
H T Pritchard 6 RE Burger 5,6,7, 8
Michigan City 12 W H Sammis 5,6.7
Petersburg 1,2 Walter C Beckiord 5,6
R Gallagher 1,2,3,4 PENNSYLVANIA
Tanners Creek U4 Armstrong 1,2
Wabash River 1,2, 3. 5, 6 Brunner Island 1,2, 3
Warrick Cheswick I
IOWA Conemaugh 1,2
Burlington I Hatfield’s Ferry 1,2, 3
DesMoines 11 MartinsCreek 1,2
George Neal 1 Portland 1,2
Milton L Kapp 2 Shawville 1,2, 3,4
Prarne Creek 4 Sunbury 3,4
Riverside 9 TENNESSEE
KANSAS Allen 1,2, 3
Quindaro 2 Cumberland 1,2
Gallalin 1,2,3,4
KENTUCKY
Johnsonvilie 1,2,3,4, 5,6, 7, 8. 9, 10
Coleman CI, C2, C3
Cooper 1,2 WEST VIRGINIA
E W Brown I, 2, 3 Albright 3
ElmerSmith 1,2 Fort Martin 1,2
Ghent I Harrison 1,2, 3
Green River 5 Kammer I, 2, 3
H L Spurlock I Mitchell 1,2
HMP&LStation2 Hl,H2 MtStorm 1,2,3
Paradise 3 WISCONSIN
Shawnee 10 Edgewater 4
MARYLAND Genoa 1
C P Crane 1 • 2 Nelson Dewey 1,2
Chalk Point 1,2 North Oak Creek 1,2,3,4
Morgantown 1, 2 Pulham 8
SouthOakCreek 5,6,7,8
MICHIGAN
JHCampbell 1.2
D-i.
-------
Do the Acid Rain Regulations Apply to You?
Exhibit 2: Units listed in Table 2
of §73.10(40 CFR 73)
ALABAMA
ARIZONA
ARKANSAS
CALIFORNIA
Plant Name
Barry
Charles R Lowrnan
Cflickasaw
Coibert
E C Gaston
Future Fossil
Gadsden
Gorgas
Greene County
James H Mifler Jr
Mcintosh-Caes
Mcw i llia ms
Widows Creek
Agua Fria
Apache Station
Choila
Coronado
D C Moss Petrie
Oils Bend
Irvingion
Kyrene
Navajo
Ocoti llo
Saguam
Springerville
West Phoenix
Yuma Axis
Carl Bailey
Cecil Lynch
Flint Creek
Hamilton Moses
Harvey Couch
tndependettce
Lake Cathenne
Mcclellan
Na 2— 7246
Robert ERircIne
Thomas Fiizhugh
White Bluff
Aiamitos
Avon
Broadway
Contra Costa
Cool Water
El Centro
El Segundo
Enema
Etiwanda
Gienarm
Grayaon
Harbor Gen Station
Haynta C nn Station
Highgrove
Humboldt Bay
flusters Point
Huntington Beach
Kern
Magnolia
Mandalay
Martinez
Morro Bay
Moss Landing
Oleuin
Olive
Ormorid Beach
Pittsburg
Potrero
Redondo Beach
San Bernardino.
Scattergood Oen Sta
Silver Gate
South Bay
Valley Gen Station
Plant Name
Bo i lers
COLORADO
Arapahoe
1,2,3,4
Cameo
2
Cherokee
12,3,4
Comanche
1,2
Craig
C1,C2,C3
Hayden
I -II,H2
Martin Drake
5,6,7
Nucla
Pawnee
1, 1*2
Rawhide
101
Ray f lNixon
Valn iont
1, 1 4 NA I
5,11,12 . 13,14,21,22,23,24
Zuni
1,2,3
CONNECTJCIYF
Bridgeport Harbor
Devon
BI-IBI, 81-182, BHB3
3,6,7,8, 4A, 48, SA, 58
English
SouthMeadow
EB I3, 8814
1 1,12,13
Middletown
1, 2,3, 4
Montville
5,6
New Haven Harbor
NH$ I
Norwalk Harbor
I, 2
DELAWARE
EdgeMoor
Hay Road
Indian River
3,4, 3
* 43
1,2,3,4
Mckee Run
3
Vamisant
* 111
DISTRICT OF COLUMBIA
Benning
IS. 16
FLOR IDA
Anclote
1,2
ArvahBHopksns
1,2
Avon Park
2
&g Bead
8801,8802, 3803,3804
CD Mcintosh Jr
1,2,3
Cape Canaveral
PCCI, PCC2
Cnst
1,2,3,4,5,6,7
Crystal River
Ct
1,2,4,5
**l,*fl,**3,**4
Cutler
PCIJS, PCU6
Debary
1*7, 1* 5, 1*9, * 110
Deerhaven
DI, 82, ‘NAI, 1 NA2
F J Cannon
0801.0802,0803,0804,
0805.0806
Fort Myers
PFM1. PPM2
GE turner
2,3 ,4
HenryOK ing
7,8
Higgins
Hookers Point
1,2,3
8301, H302, 1-1803, 11804.
11805,11806,
Ind ian River
1,2,3, **(
J D Kennedy
8, 9, 10
JR Kelly
Smith
iRKS
1,2
Larsen Memorial
7, 445, 449
Lauderdale
PFL4, PEtS
Manatee
PMT 1, PMT2
Max im
PMRI, FMR2
Nal—7238
Nonhside
1,2, 3
PLBartow
1,2,3
Port Everglades
Putna m
PPE1. PPE2, PPE3, PPE4
HRSGI 1, }IRSOI2, 1-1RSO2I,
1 1R 5022
Riviera
PRV2, PRV3, PRV4
SOPu r dom
7
Sanford
PSN3, PSN4, PSN S
Scliolz
1,2
Seminole
1,2
Soutliside
1,2,3,4,5
Si IohnsRiverPower
1,2
Stanton Energy
Stock island
1,2
I
Stock island D I
“NAI NA2
Suwannee River
I, 2, 3
Tom 0 Smith
S-3, S-4
Turkey Point
PTPI,PTP2
Veto Beach Municipal
3,4,4*3
1,2,3,4,5
1,2,3
110
1, 2, 3, 4, 5
1, 2, 3, 4, 5
I
1,2
5,6,7,8,9,10
1,2
1,2,3,4
4*J 1*2
Cr2 C’I’3
1,2,3,4,5,6,7,8
1,2,3
1,2,3
1,2, 3,4,4*5
(JIB, U2B
4
15 0T1 G1’2
1*013 *bOT4
1,2,3,4
K-I, K-2
1,2,3
1,2
1,2
1.2
4,6
01
1,2,3
1,2
1,2
1,2
1 ,2.3.4
01
4*1
1.2
1,2
1 ,2 ,3,4 ,5 .6
1,2, 3
81, 82, B3
1,2,3,4,5,6,7.8.9.10
1,2
2.3,4
I, 2,3,4
1,2.3.4.5
1,2,3,4
16, 17
4.5
1,2,3,4,5
1.2.3,4,5.6
1,2.3.4
1.2
3.4,5,6,7
1.2.3.4
1,2,3,4
1 *14
1.2
1.2. 3
1.2,3,4
I,2,3,4.5,6.7,8.6-i,7-I
1.2 ,3.4,5 ,6
0 1 .02
1.2
1.2,3,4.5.6,7
3—I
5,6,7,8, IL 12.13,14.15,
16, 17
1,2
1,2,3
1, 2, 3, 4, 5, 6
1.2,3,4
1 .2,3 .4
Arkwright
Atkinson
Bowen
Hammond
1,2,3,4
A2 . A), A4, A lA, AIR,
IBLR. 2BLR, 3BLR, 4BLR
1 .2 .3.4
D-2
-------
Appendix D
$lak Plant Name
INDIANA
Harilee Branch
Jack Mcdonough
Mcintosh
Mcmanus
Mitchell
Port Wentworth
Riverside
Scherer
Wansley
Yates
Baldwin
Coffeen
Collins
Crawford
Dallman
Duck Creek
E D Edwards
Fisk
Grand Tower
Havana
Hennepin
Hutsonville
Joliet 29
Joliet 9
Joppa Steam
Kincaid
Lakeside
Marion
Meredosia
Newton
Powerton
R S Wallace
Venice
Vermilion
Waukegan
Will County
Wood River
A B Brown
Badly
Breed
Cayuga
Clifty Creek
Dean H Mitchell
Edwardsport
Elmer W Stout
F B Culley
Frank E Ratis
Gibson
MT Pritchard
Merom
Michigan City
Na 1—7221
Na I -7228
Noblesville
Petersburg
R Gallagher
R M Schahfer
Rockport
State Line
Tanners Creek
Wabash River
Warrick
Whitewater Valley
Ames
Burlington
Council Bluffs
Des Moines
Dubuque
Earl F Wisdom
Fair Station
George Neal
Graettinger
Gnnnell
Lansing
Lime Creek
Louisa
Maynard Station
Milton L Kapp
Muscatine
Na I —7230
Boilers
1,2,3,4
MBI. MB2
1,2
3
1,2,3,4
12
1,2,3.4
1,2
YIBR, Y2BR. Y3BR. Y4BR,
Y5BR. Y6BR, Y7BR,
1.2,3
01,02
1,2,3.4,5
7,8
31. 32, 33
1,2,3
19
07,08,09
1,2,3,4,5,6,7,8,9
1,2
05.06
71, 72,81, 82
5
1,2,3,4,5,6
1,2
7,8, GT2
1,2,3,4
01,02,03,04,05,06
1,2
51, 52, 61, 62
9, 10
1.2,3.4.5,6.7,8
1,2
7,8, 17
1,2,3.4
1,2,3,4,5
1,2, “4
7,8
1,2
1,2,3,4,5.6
4,5,6,11
6-1,7-1,7-2, 8-I
1,2,3,4,5,6,7.8,9, 10,50,
60, 70
1,2, 3
ISGI, 2SGI
1,2,3,4,5
1,2,3,4,5.6
ISGI, 2SGI
4.5,6.12
“I 1*2,1*3
*14 1*5
I, 2,3
1,2,3,4
1,2.3.4
14, 15, 17, 18
MBI. MB2
3.4
Ui, U2, L13. 1.14
1, 2, 3, 4, 5, 6
4
1,2
7,8
1,2.3
*15, 10, II
2
1,2,3,4
* 15
*12
3.4
Ill 1*2
101
2
8,9
1*2
KENTUCKY
LOUISIANA
Plant Name
Ottumwa
Pella
Praine Creek
Riverside
Sixth Street
Streeter Station
Sutherland
Arthur Mullergren
Cimarron River
Coffeyville
East 12Th St
Garden City
Gordon Evans
Holcomb
Hutchinson
Jeffrey Energy Centr
Judson Large
Kaw
Kingman
La Cygne
Lawrence
Mcpherson 2
Mulvane
Murray Gill
Nearman Creek
Neosho
Quindaro
Ripley
Riverton
Russell
Tecumseh
Big Sandy
Cane Run
Coleman
Cooper
DBWilson
Dale
EWBrown
East Bend
Elmer Smith
Ghent
Green River
H L Spurlock
Henderson I
Hmp&L Station 2
I KSmith
Mill Creek
Na I —7220
Paradise
Pineville
RD Green
Robert Reid
Shawnee
Trimble County
Tyrone
A B Paterson
A B Paterson
Arsenal Hill
Big Cajun I
Coughlin
D G Hunter
Doc Bonin
Dolet Hills
Houma
Lieberman
Little Gypsy
Louisiana I
Louisiana 2
Michoud
Monroe
Morgan City
Natchitoches
Ninemile Point
Opelousas
R S Nelson
Rodemacher
Ruston
Sterlington
Teche
Waterford I & 2
Willow Glen
6,7,8
3.4
9
1,2.3.4,5
7
1,2,3
4
4
S-2
1.2
SGU I
1,2.3.4
1.2. 3
4
1,2, 3
1*9
1.2
2,3,4,5
1*7, *18
1.2,3,4
NI
7
1,2
1*2 3
39,40
1 I, 1* 12
9.10
BSIJI, BSU2
3, 4, 5, 6, II 12, *113
CI, C2, C3
1,2
WI
3,4
1.2. 3
2
1,2
1.2,3,4
1,2,3,4,5
1,2
6
HI, H2
1,2,3,4
*13, *14, *15
1,2,3
3
01,02
RI
1,2,3.4,5,6,7,8,9.10
1,2.3,4,5
3
4
5A
IBI, 1B2,2Bl,2B2, 2B3
6.7
3,4
1,2, 3
IS, 16
3.4
1,2, 3
IA, 2A, 3A
10,11,12
1,2, 3
Il, 12
4
10
1,2.3,4,5
10
1,2,3,4,6
1,2
2, 3
10, 7AB
2, 3
1,2
1,2,3,4,5
Boilers
ILLINOIS
KANSAS
IOWA
D-3
-------
Do the Acid Rain Regulations Apply to You?
MAINE
MARYLAND
MASSACHUSEflS
MIC HIGAN
MINNESOTA
MISSISSIPPI
Plant Name
Hol lers
St 1
Plant Name
Rollers
MISSOURI
Graham Station
Mason Steam
William F Wyman
5
3,4,5
1, 2,3,4
Asbury
Blue Valley
Chamois
I
3
2
Columbia
6, 7,8
Brandon Shores
CPCrane
Chalk Point
Coal Gas Ccl
Coal Gas Cc 2
Dickerson
Easton 2
Gould Street
HerbertAWagner
Morgantown
Nanticoke
Perryman
RPSmith
Riverside
Vienna
Westport
1,2
1,2
1.2. 3,4, ‘GT3, 1 1 0T4,
fl(fl
**al* . 1
** 3, I*C4
1,2, 3
1*26, 1*27
3
1,2,3,4
, 2
• 1 STl
1*52, 1*61, * 162
9, I I
1,2,3 ,4,5
8
34
Combustion Turbine I
Combustion Thrbine 3
Empire Energy Center
Grand Avenue
H’thom
latan
James River
Jim Hill
Lake Road
Meramec
Montrose
Na 1—7223
Na 1—7226
New Madrid
Rg 1 &2
Rush [ sland
“NA4, 11 NAS,
‘ 1 NA6, 1 1 NA7
1’3
*14, 11 1’.Ifl, 11 Nfr3
* 17,1*9
5
I, * 12
3. 4. s. G’r2
1* 1
,2,3 ,4
6
1,2, 3,4
1 2.3
1*1, 1 *2, 1 13
**J
1 2
I’ ll, *fl
1,2
Brayton Point
Canal
Cannon Street
1,2,3,4
1 2
3
Sibley
Sikeston
Sioux
Southwest
1,2 ,3
I
1,2
1
Cleary Flood
Kendall Square
Mount Tom
Mystic
NewBoston
SalemHarbor
Somerset
8.9
I. 2. 3
I
4. 5, 6, 7
1 ,2
1.2.3,4
1,2,3.4,5,6.7,8
MONTANA
Thomas Hill
Co lstrip
FrankBird
JECorette
Lewis & Clark
M B I, M32, MB3
1,2, 3,4
I
2
BI
Waters River
1*2
NEBRASKA
West Spnngfield
1, 2, 3
Bluffs
C W Burdick
4
B-3
BCCObb
Belle River
ConnersCreek
DanEKarn
De lray
Eckert Station
Endicoct Generating
Erickson
Greenwood
Harbor Beach
1,2,3,4,5
1. 2
15,16,17,18
1,2,3.4
7 ,8,9,10, 1 1, 12
1,2,3,4,5,6
I
I
I
I
Canaday
Gerald Gentleman Ste
Haroldkramer
HssnngsEnergyCtr
Len Wnght
Na I — l Jl9
Nebraska City
North Omaha
Platte
Sheldon
I
1,2
1,2 ,3,4
1
a
• 1 NA2
1, 2, 3,4,5
I
1, 2
JR Sims
3
NEVADA
JCWesdock
J H Campbell
J R Whiting
James De Young
Marysvtl le
Mistetsky
Monroe
Presque Isle
7.8
1,2,3
1.2,3
5
9. 10, 1 1 ,12
5 6, 7
1,2,3,4
2, 3, 4, 5,6,7,8,9
Clark
Fort Churchill
Harry Allen
Mohave
North Valmy
Reid Gardner
Sunnse
1,2,3
1 2
*9, 1*2 4*3, * 14 ,
1 1 G’fl 1 1 GT4
1 ,2
1,2
1.2,3,4
I
RiverRou ge
Shim
StClair
Trenton Channel
Wyandotte
491 E. 48Th Street
1,2,3
3
1,2,3,4,5,6,7
16, 17, 18, 19,9A
5,
• 7, °8
NEW HAMPSHIRE
Tracy
Merrimack
Newinston
Sc uller
1 ,2,3
1 ,2
I
4, 5, 6
NEW JERSEY
Allen S King
BlackDog
Clay Boswell
Fox Lake
Future Base
High Bndge
Hoot Lake
MLHibbard
Minnesota Valley
Nal—7237
Northeast Station
Riverside
Sherburne County
SilverLake
Syl Laskin
I
1 .2.3.4
I, 2. 3,4
3
I ll
3,4,5.6
2 ,3
3,4
3
1*2
NBPP
6.7,8
I, 2, 3
4
1, 2
B L England
Bergen
Burlin gion
Butler
Deepwater
Gilbert
Hudson
Kearny
Linden
Mercer
Na 3—7 141
Na4—7 142
Na 5—7217
Na6—72l8
Sayreville
Sewaren
Werner
1.2,3
1.2
7
* 14
1,3,4,5 6,8 9
Dl, 02,03,04,05,06,07
1 2
7 ,8
2,4,11,12,13
1 2
**j 0*2
Ill
*4 1 *42
* 11 1*2
02.03.05, 06,07,08
1, 2, 3, 4,5
04
Baxter Wilson
Delia
Gerald Andrus
JackWatson
Moselle
Natehea
RD Morrow
Rex Brown
Sweatt
VictorJDaiiieljr
Wright
1.2
t,2
1
1 ,2,3,4,5
. 3 *16 *47
I
1,2
3,4, IA, LB
1, 2
1,2
W4
NEW MEXICO
Cunningham
Escalante
Four Corners
Maddox
North Lovington
Person
Reeves
Rio Grande
San iuan
121 B. 1 22B
1, 1*2
1,2, 3,4, 5
1 1 3,05lB
S2
3,4
I 2,3
6:7.8
1,2,3,4
rs A
-------
Appendix D
Plant Name
Albany
Arthur Kill
Astona
Bowline Point
CR Huntley
Charles Poletti
Danskammer
Dunkirk
B F Barrett
East River
Far Rockaway
Glenwood
Goudey
Greenidge
Hickling
Jennison
Loveti
Milliken
Northport
Oswego
Port Jefferson
Ravenswood
Rochester 3
Rochester 7
Roseton
S A Carlson
Somerset
Waterside
59Th Street
74Th Street
NORTH CAROLINA
Asheville
Belews Creek
Buck
Cape Fear
Chffside
Dan River
GGAIIen
LV Sutton
Lee
Marshall
Mayo
Riverbend
Roxboro
W H Weatherspoon
NORTH DAKOTA
OHIO
Antelope Valley
Coal Creek
Coyote
Dakotas
Leland Olds
Milton R Young
R M }leskett
Stanton
Acme
Ashtabula
Avon Lake
Bay Shore
Cardinal
Conesville
Dover
Eastlake
Edgewater
Gen J M Gavin
Gorge
Hamilton
JMStuart
Killen Station
Kyger Creek
Lake Road
Lake Shore
Miami Fort
Muskingum River
Niles
0 H Hutchings
Ptcway
Poston
R E Burger
Refuse & Coal
Richard Gorsuch
Ttdd
Toronto
W H Sammis
W H Zimmer
Walter C Beckjord
Woodsdale
Boilers
1,2,3,4
20,30
10,20,30,40,50
1,2
63, 64,65,66,67, 68
001
1,2,3,4
1,2,3,4
10,20
50,60,70
40
40,50
11, 12,13
4,5,6
1,2,3,4
1,2,3,4
3.4,5
1,2
1,2,3,4
1, 2, 3, 4, 5, 6
1,2,3,4
10. 20, 30
1.2,3,4,7,8,12
1,2,3.4
1,2
9, 10,11,12
41,42,51,52,61,62,80,90
110
120, 121. 122
1,2
1,2
5, 6, 7, 8. 9
3,4,5,6
1, 2, 3, 4, 5
1,2.3
1,2,3,4,5
1.2,3
1,2,3
1,2,3,4
IA, lB
7,8,9, 10
1,2, 3A, 3B, 4A, 4B
1,2,3
BI, 82
1,2
SI
I
1,2
B 1,82
B2
I, ID
9.11,13,14,15, 16.91, 92
7,8.9,10,11
9.10.11.12
1,2.3,4
I, 2,3
1.2,3.4,5.6
* 16
1,2.3,4,5
II, 12,13
1,2
25. 26
9
1,2,3.4
2
1,2,3,4,5
6
18, 91, 92. 93, 94
6,7,8,5-1.5-2
1,2,3,4,5
1.2
H-I. H-2, H-3, H-4, H-5, H-6
9
1,2,3
1,2,3,4,5,6,7,8
001,002,003,004,005,006
1,2,3,4
*9
9.10,11
1,2,3,4,5,6,7
1,2.3,4,5,6
**GTI ‘ GT2, ‘0T3
• 1 GT4, **GT5, ‘ 1 0T8,
** ‘j ’9, 1 GT 10, 1 GT 1 I,
**GTl2
OREGON
PENNSYLVANIA
RHODE ISLAND
SOUTH CAROINA
Plant Name
Anadarko
Arbuckle
Comanche
Conoco
Grda
Horseshoe Lake
Hugo
Inola
Mooreland
Muskogee
Mustang
Na 1 —5030
Northeastern
Ponca
Riverside
Seminole
Sooner
Southwestern
Tulsa
Boardman
Armstrong
Bruce Mansfield
Brunner Island
Cheswick
Conemaugh
Cromby
Delaware
Eddystone
Elrama
FR Phillips
Front Street
Hatfield’S Ferry
Hoitwood
Homer City
Hunlock Power
Keystone
Marcus Hook Refinery
Martins Creek
Mitchell
Montour
New Castle
Portland
Richmond
Schuylkill
Seward
Shawville
Southwark
Springdale
Sunbury
Titus
Warren
Williamsburg
Manchester Street
South Street
Canadys Steam
Cross
Dolphus M Grainger
H B Robinson
Hagood
Jeffenes
Mcmeekin
Na 4—7210
Urquhait
W S Lee
Wateree
Williams
Winyah
Big Stone
Huron
Mobile
Pathfinder
Allen
Bull Run
Cumberland
Gallatin
John Sevier
Johnsonville
Kingston
Watts Bar
Boilers
3
ARB
7251,7252
*9 $12
1.2
6.7.8
Ill
1.2, 3
3.4.5,6
1,2,3,4
‘ 2 *13
3301,3302. 3313. 3314
2
1501, 1502
I • 2, 3
1.2
8002, 8003, 80 1N, 8 OlS
1402, 1403, 1404
ISO
1.2
1.2, 3
1,2,3
1.2
1.2
71,81
1.2,3,4
1.2, 3.4
1.2.3,4,5.6
7,8.9,10
1,2,3
17
1.2, 3
6
1,2
1.2, 3,4
1.2,3,33
1,2
1,2, 3,4,5
1,2
63.64
12, 14, 15
1,2,3,4
II, 12, 21,22
77,88
3,4, IA, IB,2A,2B
1,2, 3
1,2,3,4
11
6,7,12
121, 122
CAN I, CAN2, CAN3
1.2
1,2
*14, HAGI, HAG2, HAG3
1,2, 3,4
MCMI, MCM2
1 1 ST 1
URQI, URQ2, URQ3
1,2, 3
WATI, WAT2
WILl
1.2,3,4
11 2A, *128
II, 12, 13
1,2, 3
1,2
1,2.3,4
1.2.3,4
1,2,3,4,5,6,7,8,9,10
1, 2, 3, 4, 5, 6, 7, 8, 9
A.B.C. D
NEW YORK
OKLAHOMA
SOUTH DAKOTA
TENNESSEE
0-5
-------
Do the Actd Rain Regulations Apply to You?
Plant Name Baikra Plant Name Bo i le n
TEXAS Trin idad 7,8,9
BarneyMDavis 1,2 Tw inCak 1 ,2
Rig8mwn 1 .2 VHfiraunig 1,2 ,3
Bryan 6 Valley 1,2,3
CE Newman W I tS Victona 5.6,7,8
Cedar Bayou CBY I, C8Y2. CBY3 WA Pansh WAN, WAP2, WAR), WAP4,
Coleto Creek I , WAPS, WAP6, WitP7, WAPE
Co hn I WBTuttle 1,2,3,4
Concho 2,4.5,6,7 Webster WERl, WEB2, W883
Dal las 3 ,9 Welsh 1, 2 ,3
Daosby Wi lkes 1,2 .3
DnckerCc’eek 1,2
UTA H
Decorr lo va 1 B OISSI IT A I - i
Deepwattr DWP L,DW 92,OWP3,DWP4, Carbon 1,2
DWP5, DWP6, DWP9
ESios lin i Gadaby 1 .2,3
EagleMountain 1,2,3 Hale
Forest Grove •9 Ilunter(Eniery) 1.2.3
Huntington 1 2
Fort Phantom I, 2 Intenasountarn I SGA, 2SGA
Qenenc Stat
Gibbons Creek I VERMONT
Graham 1.2 JCMcneii
GieensBeyou GHYI,08Y2,GBY3,08 14, •na cn
G8Y S BremoRh iff 3 ,4
Gi98 *9 , *2 Qiesapeake 1,2,3,4
0s99 ‘9. “2, “ Chesterfield 3.4,5,6, ‘8A, $*IS
Handley 2,3,4,5, IA, 18 CLinch River 1, 2,3
Harnngton Station 0613.0628, 0638 Clover 1,2
Hira inClar ice HOC1,HOC2,HOCS,HCJC4 Glen tyn 6,51 52
Holly Ave 1,2 Possum Point 1.2,3,4,5
Holly Street 1,2,3,4 Potomac River 1.2 .3,4,5
JESpruce **l,**2 Yorktown 1.2,3
JL Bmcs 1,2
I I Deely 1,2 WASHINGTON
Jones Siauois 15th. 1523 Ceniraha RW21, BW22
KnoxLee 2 ,3,4,5 KettleFa l ls
La Palms 7 Staif l leton 1, 2.3
Lake Creek 1,2 WF!ST VIRGIN iA
Lake hubbai’d 1 ,2 Aibright 1.2,3
Laredo 1,2,3 FonMartin 1 .2
Leon Creek 3,4 Mamaosi 1,2,3
LewisCreek 1.2
Limestone LZM LLIM2 JohnEAmos 1 .2,3
Kasniner 1 ,2 .3
LonCHi l l .2,3,4 Kanawba tiver 1 ,2
Lone Star 1 Mitche ll 1.2
Malakoff “t , ”l Mountasneer(130 1) I
MartinLake 1,2 ,3 MtStonn 1,2,3
Miss ion ltoad Phu l Spori II,2I.31,4 1,5 1
Montice llo 1,2,3 Pleasants 1,2
Morgan Creek 3.4, 5,6 Riveavifle i. E
Moirrikam Creek 2,6 ,1,8 , 3A. 38 2
NaI— .72l6
Nal— .72 19 “I . ’ 2 WISCONSIN
Na Z—4274 “NA I Alma 34 ,B5
Neches 1 1 , 13,15,18 BayFron i 1.2,3 ,4 .5
Newman 1.2.3, “4 Blourit Street 3, 5,6,7,8,9, it
Nichols Station 14 18, 1428, 1433 Columbia 1.2
NorthLake 1.2 ,3 Combustionturbine (*2
North Main 4 Cominetee 25
Norib Tenas 3 Edgewazer 3,4,5
NuecesBay 5 ,6,7 Genoa 1
OWSommers .2 JPMadgett St
OakCreek I Mamiowoc 6,7,8,9
Oklaunion I Na—7222 “1
PH Robinson P}IRI, PHR2, PHR3. P1184 Na I — 7203 “Cr3, “Cr4
Paint Creek 1.2.3,4 Nat —7205 “1, “2”3
Parkdale 1,2,3 Na i “ 1
Pen man Basin 5.6 Na4 “ 1
Pirkey I Nelson Dewey 1.2
Plan iX 1118, 1128,1138 , 1148 NorthOakCreek 1,2,3,4
Powerlaae Plant 2.3 Pleasant Prairie 1,2
R W Miller 1 ,2,3 Port Washington 1.2,3.4.5
Ray Olinger 8W2, 8W3, CEl Pultiamn 3,4,5,6, 7, 8
toPecos 3,6 RoekR,ver 1,2
RrverCrest I SouthOakCreek 5,6,7,8
Sabine 1 ,2 ,3 .4 ,5 Sconeman 81,82
Sam flenron SR8I. SRB2, SRB3, S1t84 Valley I , 2, 3,4
Sam Seymour 1.2. 3 West Mannette “33
SanAngelo 2 Weston 1,2 ,3
San Miguel “2 SM-I WYOMING
Saadow Dave Johnston 841, 8W42, 8W43, 9W44
Seaho lm J un Bridger SW ? 1, 8W72, 8W73, 8W74
SunG ideon 1,2,3 LaramueR iver 1,2,3
Spencer 4, 5
SuykerCreek 1,2 Naughion I 2.3
TCFerguaori Wyodak BW91
T I - I Wharton T1 IW I,THW2
Inp One Ui, U2, “3, “4
Tolk Station 1718, 1728
Tradinghouse 1, 2
-------
Appendix D
Exhibit 3: Units Listed in Table 3
of §73.10 (40 CFR 73)
SMk fit
ALABAMA
Mcwilliams 1*4
ARIZONA
Springerville 3
CALIFORNIA
Harbor Gen Station *90, 1 1 10A, 11 10B
FLORIDA
GWIvey 1*22
Indian River 1 D
Intercession City 1*7,1*8,1*9, **fl
Lauderdale 1 4GT1, 1 1 4GT2, ‘ 1 5GT1,
• 1 5G’fl
Martin 1 1 35T 1 1 4ST, 1 1 3GT1
**3Gfl, 11 4GT1, 1 1 40T2
ILLINOIS
Lakeside GTI
INDIANA
Na 1—7228 1*1, * 12, 1*3
IOWA
Nal—7230 * 11
KANSAS
Wamego 1 NA I
MARYLAND
Coal Gas Cc I 1 1 CT2
Easton 2 * 125
Perryman 1*51
MINNESOTA
Nal—7237 I ll
MISSISSIPPI
Moselle 1*4, 1*5
MISSOURI
Combustion Turbine 1 *11
Combustion Turbine 2 1*2
Empire Energy Center 1*3
Lake Road * 18
NEBRASKA
Nal—70 19 1 NA I
NEVADA
Clark * 19, 1*10
Harry Allen 1 1 GT1, 11 GT2
NEW JERSEY
Butler 1*1, 1*3
Nal—7 139 I ll
Na2—7 140 I ll
OHIO
Dover * 17
Woodsda le 11 GT6, 1 GT7
PENNSYLVANIA
Trenton Cogen Proj “I
SOUTH CAROLINA
NaI —7l06 1 1 GTI
Na2—7 107 1 GT2
Na3—7 108 **GT3
SOUTH DAKOTA
Ci * 15
TEXAS
R W Miller 1*4, 1*5
Twin Oak 2
UTAH
Bonanza 1*2
VIRGINIA
Clover 1,2
East Chandler 1*2
WISCONSIN
Combustion Turbine 1*1
Concord *11,1*2,1*3,1*4
Nal—7203 **Cl,**Cfl
Na2 I II
I I 1, 1*2, 1*3, 1*4
D-7
-------
Appendix E
Certificate of Representation
A Certificate of Representation with instructions is attached.
E-1
-------
Under the Acid Rain Program (at 40 CFR
Subpwt B), the owners and operators for
each affected source must designate a
representative, and may designate an
alternate, to act on their behalL The owners
and operators must choose the representative
through a process that ensures that all
owners and operators have notice regarding
the selection. All affected units at a source
must have the same designated
representative.
T ipe or complete this form using black ink It
you need more space, photocopy the pertinent
page. When you have completed the form,
Indicate the page order and total number of
pages( g, 1o14,2of4,etc.)intheboXesifl
the upper right hand corner of each page.
You must submit one Certificate of Representation
form with onoinal signatures and three
photocopies. Remember that under 40 CFR
72.21, the designated representative must notify
each owner and operator of all Acid Rain
Program submissions.
If you need assistance, call the Mid Rain Hotline
at (20Z 233-9620.
STEP 1 NADB is the National Allowance Data
Base for the Acid Rain Program. To
obtain the database on diskette or in
hard copy, call the Acid Rain Hotline.
This data file is in dBase format for use
on an IBM-compatib le PC. It requires 2
megabytes of hard drive memory.
STEP 2 The designated representative must be
a natural person and cannot be a
company. Please enter your firm name
and address as you would like it to
appear on all correspondence.
STEP 5 See 40 CFR 72.2 for the definitions of
“owner and “operator.” You may enter
a person’s or a company’s name.
identify each unit at this source that is
owned or operated by the named party
by providing the boiler identification
number listed for the unit In the NAD
For new units not listed in NADB, use
the boiler number you have assigned.
The state or local regulatory authority
means the Public Utility Commission or
other rate-making authority.
As designated representative, yo are
responsible for a!! submissions and allowance
transactions relating to the units at that source.
You and the alternate designated
represertattle are liable for acts or omissions
within The scope of your responsIbIlitIes under
the Acid Rain program.
EPA wW not Issue an Acid Rain permit or
record an allowance transaction until It has
received a complete Certificate of
Representation.
Submission instructions
Mail this form to:
U.S. Environmental Protection Agency
Acid Rain Program (8204J)
Attention: Designated Representative
401 M Street, SW.
Washington, D.C. 20460
For Ph... II sources, submit this form by
November 17,1994. If you wish to participate In
the annual auctions and sales of allowances prior
to that date, submit the form earlIer. EPA will not
issue proceeds from auctions or sales to a unit
until it receives a complete certificate of
representation.
Submit a revised Certificate of
when any Information changes.
notified of changes to owners
within 30 days.
Paperwork Burden Eethnats
The burden on the public for collecting arid repofling
information under this request Is estimated at 35 hours
per rasper,... $end cwiunente regardIng this collection
of Information, Including suggestions for reducing the
burden, to: Chief, Information Policy Branch (PM-223),
U.S. Errdrorvnentai Pretectiun Agency, 401 M Street.
SW. Washington, D.C. 20460 end to: Paperwork
Reduction Project (OMB#2060.0221), Offic. of
Information and Regulatory Affairs, Office of
Management and Budget, Washington. D.C. 20503. Do
not send your tense to these ad&ssus see th•
subnzlul.n Instructions above.
Acid Rain Program
Instructions for
Certificate of Representation (40 CFR 7224)
Representation
EPA must be
and operators
-------
United States
Environmental Protection Agency
Acid Rain Program
0MB No. 2060-0221
Expires 6-30-95
STEP 2
Enter requested
information for the
designated
representative
Name
Address
Fax Number
Phone Number
STEP 3
Enter requested
Information for the
alternate designated
representative
(optional)
Name
Address
Phone Number Fax Number
STEP 4
Complete Step 5. reed
the certifications and
sign and date
I certify that I was selected as the designated representative or alternate designated representative, as
applicable, by an agreement binding on the owners and operators of the affected source and each affected
unit at the source.
I certify that I have given notice of the agreement selecting me as the designated representative or alternate
desiQnated representative, as applicable for the alfected 8ource and each affected unit at the source
identified in this certificate of representation, daily for a period of one week in a newspaper of general
circulation in the area where the source is located or in a State publication designed to give general public
notice.
I certify that I have all necessary authority to carry out my duties and responsibilities under the Acid Rain
Program on behalf of the owners and operators of the affected source and of each affected unit at the source
and that each such owner and operator shall be fully bound by my actions, inactions, or submissions.
I certify that I shall abide by any fiduciary responsibilities imposed by the agreement by which I was selected
as designated representative or alternate designated representative, as applicable.
I certify that the owners and operators of the affected Source and of each affected unit at the source shall be
bound by any order issued to me by the Administrator, the permitting authority, or a court regarding the
source or unit.
Where there are multiple holders of a legal or equitable title to, or a leasehold interest in, an affected unit, or
where a utility or industrial customer purchases power from an affected unit under life-of-the-unit, firm power
contractual arrangements, I certify that:
I have given a written notice of my selection as the designated representative or alternate designated
representative, as applicable and of the agreement by which I was selected to each owner and operator
of the affected source and o each affected unit at the source; and
Allowances and the proceeds of transactions involving allowances will be deemed to be held or
distnbuted in proportion to each holder’s legal, equitable, leasehold, or contractual reservation or
entitlement or, if such multiple holders have expressly provided for a different distnbution of allowances by
contract, that allowances and the proceeds of transactions involving allowances will be deemed to be held
or distributed in accordance with the contract.
The agreement by which I was selected as the alternate designated representative includes a procedure for
the owners and operators of the source and affected units at the source to authonze the alternate designated
representative to act in lieu of the designated representative.
l—
STEP 1
Identify the source by
plant name. State. and
ORIS code from NADB
Certificate of Representation Page
For more information, see instructions and refer to 40 CFR 72.24
This submission is: New Revised
Plant Name
State ORIS Code
EPA Form 7610-1(11-92)
-------
Plant Name (from Step 1)
Certificate - Page 2
Peg. 0 of 0
Certification
I am authorized to make this submission on behalf of the owners and operators of the effected source or
affected units for which the submission is made. I certify under penalty of law that I have personally
examined. and am familiar with, the statements and information submitted in this document and all its
attachments. Based on my inquiry of those individuals with primary responsibility for obtaining the
information, I certify that the statements and Information are to the best of my knowledge and belief true,
accurate, and complete. I am aware that there are significant penalties for submitting false statements and
information or omitting required statements end infoimation, including the possibility of fins or imprisonment.
Signature
(designated representative)
Data
Signature
(alternate)
Date
STEP 5
Provide the name of
every owner and
operator of the source
and each affected unit
at the source. Identify
the units they own
and/or operate by
boiler lD# from NADB,
For owners only,
Identify each state or
local utility regulatory
authority with
jurisdiction over oath
owner
Name
101
IDS
ID,
D l
Regulatory Authorities
ID ,
0*
lot
l OS
lOt
I0 1
Owner Operator
ID ,
lOt
101
lDt
Name
Owner Operator
lOt
lO S
101
lOt
D I
D l
101
lOt
101
0*
D I
0 5
lOS
101
Regulatory Authorities
Mama
ID .
I C C
ID,
l Ot
lOt
lOt
0 Owner Operator
0 1
(01
Regulatory Authonties
ID ,
tot
10*
D C
ID ,
Name
lbS
lOt
lO S
(D C
101
I01
lot
Owner Operator
D C
Regulatory Authorities
01
(D C
IDI
tOt
lot
ID I lot
EPA Porrn76lO-1 (11-92)
-------
Index
A
Acid Rain Appeals process 2
Acid Rain Hotline i, vii, 21
actual electrical output 13, 14, 15
affected units v, 1, 3-5, 21-27
Allowance Tracking System iii, 22, 23
accounts 22, 23
allowances iii, iv, v, vi, ix, 7, 20-27
allowance accounts 22, 24
allowance allocation iv, v, 7, 24
allowance tranactions 22
allowance transfers 23
buying allowances iv
annual electrical sales 13, 15
annual steam sales 15
applicability determination i, v, ix, 1, 2, 10, 11, 15,
19, 20
Applying for an Exemption ix, 2, 6, 8, 24-25
ATS See Allowance Tracking System
auxiliary firing 10, 26
B
biomass 4, 17
boilers v, 6, 11, 12, 13, 14, 18
C
CEM See continuous emission monitoring
certifying official 2
Clean Air Act iii, iv, 3, 8, 20
clean fuels ix, 6, 8
coal v, vii, 4, 7, 11, 18
coal-fired v, vii, 18
cogeneration units ix, 5, 9, 12-15
cold standby 11
combined cycle 4, 10, 13
combined cycle combustion turbines 4, 13
combined cycle units 10, 13
combustion devices 4
commence commercial operation iv, 6, 7, 10
compensating units 3, 6
competitive bid solicitation 19
compliance certification 23
compliance plans 23, 24
compliance timelines ix, 21, 25-27
continuing requirements 6, 9, 10, 11, 15, 19, 20,
26
continuous emission monitoring ix, 8, 21, 22, 25
data acquisition and handling system 22
emission reports 22
monitoring reports 23
recordkeeping 22
reporting 22
rule 22
cooperative utilities 19
D
Designated Representatives ix, 8, 21, 22, 23
digester gas 4
diluent gas monitor 22
E
economic efficiency iv
electric utility companies iii, vii, 17, 18
electric utility holding companies 17, 18
electricity for sale 1, 4, 5, 7, 9, 11, 12, 20
electricity generators v, 12
emission rates iv, 18
emissions limitations iii, iv, vii, 9, 22
energy efficiency iii
Energy Information Administration 7, 10, 20
Energy Policy Act of 1992 i
equipment certification procedures 22
excess emissions v, 23
exempted units vi, ix, 5, 6-8, 21, 23, 24
existing simple combustion turbines ix, 5, 9, 10
existing small units 5, 9, 11
existing units ix, 1, 3, 6, 11
F
Federal Energy Regulatory Commission 18, 19
Federal Power Act 17
FERC See Federal Energy Regulatory Commission
Form EIA-767 5, 7, 20
Form EIA-860 5, 7
fossil fuel-fired iii, 4
fossil fuels 4, 17, 20
fuel cell 4, 5
G
general account application 22
generators ix, 1, 4, 6, 11, 13, 14, 15, 18
geothermal energy 17
Index-i.
-------
Do the Acid Rain Regulations Apply to You’
H
hazardous wastes 20
heat recovery steam generator 4, 10
historic fuel usage iv
homogeneous wastes 20
I
incinerators ix, 5, 9, 17, 20
independent power production facilities ix, 5, 9, 16-
19, 27
IPP See independent power production facilities
L
landfill gas 4
letter of intent 19
listed units 3
M
market-oriented allowance program 24
market-based approaches iii
marketable allowance program iii, v, 24
materials recovery facilities 20
maximum design heat input 13, 15
maximum fuel flow 13
minimum requirements 21
monitoring systems 8, 22, 25
multi-header units 6
multi-headered boilers 13
municipal electric authorities 19
municipal solid waste 20
N
NADB See National Allowance Data Base
nameplate capacity 1, 6, 7, 11, 13, 14, 15, 26
National Allowance Data Base iv, 3, 7, 11
natural gas 4, 8, 11, 27
nitrogen oxides iii, v, vii, 8, 18, 21, 22, 24
NOx pollutant concentration monitor 22
nonhazardous solid wastes 20
nonrecourse project financing 16
N0 See nitrogen oxides
0
offset plans 23
on-line date 7
opacity monitoring systems 22, 25
ORISPL 2
P
permit applications 8, 22, 23, 24, 25, 26, 27
permits 8, 23, 24, 25
permitting authority 2, 9, 11, 23, 24, 25
petroleum 4, 8
Phase I hi, 3, 21, 26, 27
Phase II ui, iv, 3, 8, 21, 24, 26, 27
planned net output capacity 18, 19, 27
potential electrical output capac-
ity 12, 13, 14, 15, 27
power sales agreement 19
preliminary power commitments 16
PSA See power sales agreement
public utilities 16, 17, 19
Public Utility Regulatory Policies Act of 1978 16,
17, 18
PURPA See Public Utility Regulatory Policies Act of
1978
Q
QF See qualifying facilities
qualifying cogeneration facilities 17
qualifying facilities ix, 5, 9, 16-19, 20
qualifying power purchase commitment 18, 19
quality assurance and quality control 22
R
refuse-derived fuel 1&, 20
renewable resources 17
retired units ix, 3, 6, 8, 24, 25
S
self-generation 12
simple combustion turbines ix, 5, 9, 10, 13
small generators 11
small new units burning clean fuels ix, 3, 6-8, 24
small power production facilities 17
small units 5, 6, 9
SO 2 pollutant concentration monitor 22
solar energy 17
solid waste ix, 5, 9, 17, 18, 20, 26, 27
solid waste incinerators ix, 5, 9, 17, 20
State environmental authority vii, 18, 19, 23
State or Regional permitting authority 9, Ii.
steam 4, 5, 6, 9, 10, 11, 12, 13, 15, 19, 20
steam sales 15
substantially modified 7
substitution units 3, 6
lndex-2
-------
Index
T
technOlOgy-based requirements 20
total installed net output capacity 18, 19
total nameplate capacity 6, 13
total planned net output capacity 18, 19, 27
turbines ix, 5, 9, 10, 13, 27
turbine efficiency 11
U
unaffected units vii, ix, 5, 9-20
.unit 4
unit account v
unlisted units 3-5
utility competitive bid solicitation 19
utility units iii, iv, v, vi, 1, 3, 4, 5, 6, 12
V
volumetric flow monitor 22
w
waste fuels 4, 18, 20
waste heat 10, 12
waste heat boiler 10
water power 17
wind energy 17
wood 20
Y
yard wastes 20
lndex-3
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