Acid Rain Program: 

Annual Progress Report, 2000

www.epa.gov/airmarkets

Compliance and Emissions Trends

United States Office of Air and Radiation August, 2001

Environmental Protection Clean Air Markets Division EPA-430-R-01-008

Agency 6204N
Table of Contents

Page

Background 1

• Multiple Benefits of Reducing Acid Rain 2

SO2 Program Compliance Results 5

• Deducting Allowances for Compliance 8

• Geographic Trends in Sulfur Dioxide Emissions 9

SO2 Allowance Market 11

NOX Program Compliance Results 13

• Geographic Trends in Nitrogen Oxide Emissions 17

SO2 and NOx Monitoring in 2000 19

Conclusion 21
List of Exhibits

Page

1. Affected Sources under the Acid Rain Program 1

2. Sensitive Resources: Nitrogen-Saturated Forests, 4

Class I Areas, Acidic Surface Waters in Surveyed Regions

3. National SO2 Emissions Trend for All Acid Rain Program Affected Units 5

4. The SO2 Allowance Bank: Emissions and Allocations (1995-2000) 6

5. Origin of 2000 Allowable Emissions Level 7

6. SO2 Allowance Reconciliation Summary 8

7. Sulfur Dioxide Emissions from Power Generation: 9

State-level Bar Graph (1990, 1995-1999 Phase I Average, 2000)

8. Geographic and Temporal Trends in Sulfur Dioxide Emissions 10

from Power Generation (1990, 1995-1999 Phase I Average, 2000)

9. SO2 Allowance Price Indices 12

10. SO2 Allowances Transferred Under the Acid Rain Program 12

11. Phase II NOX Units by Boiler Type 14

12. Compliance Options Chosen in 2000 15

13. NOX Mass Emissions for Phase II Units 16

14. State-level Electrical Production (Heat Input): 1990, 1999, 2000 17

15. State-level Nitrogen Oxide Emissions from Power Generation: Bar Graphs 18

(1990, 1996-1999 Phase I Average, 2000)

16. Geographic and Temporal Trends in Nitrogen Oxide Emissions 19

from Power Generation (1990, 1996-1999 Phase I Average, 2000)

17. 2000 Relative Accuracy Test Audit (RATA) Results 20

18. 2000 Continuous Emissions Monitoring Systems (CEMS) Availability 20
Acid Rain Program: Annual Progress Report, 2000 Page 1

BACKGROUND

The Acid Rain Program was established under Title IV of the 1990 Clean Air Act Amendments (“the

Act”). The program calls for major reductions of sulfur dioxide (SO2) and nitrogen oxides (NOX), the

pollutants that cause acid rain. Using a new, market-based approach to environmental protection, the

program sets a permanent cap on the total amount of SO2 that may be emitted by electric utilities

nationwide at about one half of the amount emitted in 1980, and allows flexibility for individual utility

combustion units to select their own methods of compliance. The program also sets NOX emission

limitations (in lb/mmBtu) for certain electric utility boilers, representing about a 27 percent reduction

from 1990 levels. The Acid Rain Program is being implemented in two phases: Phase I ran from 1995

through 1999 for SO2 and from1996 through 1999 for NOX; Phase II for both pollutants began in 2000

and involves over 2,000 units (Exhibit 1). In 2000, there were 2,262 units affected by the SO2

provisions of the Acid Rain Program, meaning they operated, submitted emissions data for SO2, and

were subject to annual reconciliation of allowable emissions with actual emissions. Additionally,

1,046 of these units were required to meet a NOX emissions limit under the Acid Rain Program

provisions.

Exhibit 1

Affected Sources under the Acid Rain Program
Acid Rain Program: Annual Progress Report, 2000 Page 2

The SO2 component of the Acid Rain Program represents a dramatic departure from traditional

command and control regulatory methods that establish source-specific emissions limitations. Instead,

the program introduces a trading system for SO2 that facilitates lowest-cost emissions reductions and

an overall emissions cap that ensures the achievement and maintenance of the environmental goal. The

program features tradeable SO2 emissions allowances, where one allowance is a limited authorization

to emit one ton of SO2. Allowances may be bought, sold, or banked by utilities, brokers, or anyone else

interested in holding them. Existing utility units were allocated allowances for each future compliance

year and all participants of the program are obliged to surrender to EPA the number of allowances that

correspond to their annual SO2 emissions.

The NOX component of the Acid Rain Program uses a more traditional management approach, and

establishes an emission rate limit for certain types of coal-fired boilers. Flexibility is introduced to this

command and control measure, however, through compliance options such as emissions averaging,

whereby a utility can meet the standard emission limitations by averaging the emissions rates of two or

more boilers. This allows utilities to over-control at units where it is technically easier to control

emissions, thereby achieving emissions reductions at a lower cost. Additionally, certain Phase II units 

elected to become subject to Phase I limits beginning in 1997. These early election units are not

subject to the more stringent Phase II limits until 2008.

At the end of each year, utilities must demonstrate compliance with the provisions of the Acid Rain

Program. For SO2 , utilities are granted a 60-day grace period during which additional SO2 allowances

may be purchased, if necessary, to cover each unit's emissions for the year. At the end of the grace

period (the Allowance Transfer Deadline), the allowances a unit holds in its Allowance Tracking

System (ATS) account must equal or exceed the unit's annual SO2 emissions. Any remaining SO2

allowances may be sold or banked for use in future years. For the NOX portion of the program, utilities

must achieve an annual emission rate at or below mandated levels. 

Multiple Benefits of Reducing Acid Rain

Acid deposition, or acid rain as it is commonly known, occurs when emissions of sulfur dioxide (SO2)

and oxides of nitrogen (NOx) react in the atmosphere (with water, oxygen, and oxidants) to form

various acidic compounds which then fall to earth in either wet form (rain, snow, and fog) or dry form

(gases and particles). Prevailing winds transport the compounds, sometimes hundreds of miles, across

state and national borders. SO2 and NOx gases and their particulate matter derivatives, sulfates and

nitrates, contribute to many negative environmental effects: air quality impairment and impacts to

public health, acidification of lakes and streams, damage to forest ecosystems, visibility degradation,

and acceleration of the decay of building materials, paints and cultural artifacts, including buildings,

statues, and sculptures.
Acid Rain Program: Annual Progress Report, 2000 Page 3

By reducing the pollutants that cause acid rain, significant environmental and health benefits are being

achieved.

Exhibit 2 illustrates the geographic extent of multiple sensitive resources in the United States: nitrogensaturated forests (forests where excess nitrogen deposition has resulted in long-term changes in soil

chemistry, leading to nitrogen saturation; saturated, the soil can no longer retain nutrients, leaving

forests more vulnerable to the effects of air pollutants and other stresses); Class 1 areas (national parks,

forests and wilderness areas with stringent protection from visibility impairment); and acidic surface

waters in surveyed regions (lakes and streams with a poor capacity to neutralize acid deposition, i.e.,

with acid neutralizing capacity less than zero).

As illustrated, many of these sensitive resources affected by air pollution and acid deposition are found

in the same parts of the country: Northeast (Adirondacks), Mid-Atlantic (Mid-Appalachians),

Southeast (Great Smokies), Upper Midwest, and West (Cascades, Rocky Mountains, Colorado Front

Range), including mountain ranges in California (Klamath, San Bernardino and San Gabriel

mountains). The significant emission reductions occurring as a result of the Acid Rain Program are

expected to benefit many of these sensitive resources.
Acid Rain Program: Annual Progress Report, 2000 Page 4

Exhibit 2

Sensitive Resources:

Nitrogen-Saturated Forests, Class I Areas,

Acidic Surface Waters in Surveyed Regions

The Acid Rain Program’s ultimate objective is to protect the environment and improve human health

by reducing both SO2 and NOx emissions. EPA believes these reductions will benefit the nation by:

• Improving air quality and protecting public health

• Restoring acidified lakes and streams so they can once again support fish and other aquatic life

• Improving visibility, especially at scenic vistas in national parks

• Reducing the damage to forests along the mountain ranges of the East coast

• Protecting our historic buildings and monuments from degradation.

The first step in protecting the environment and human health from acid rain is reducing emissions. 

The Acid Rain program is proving extremely effective in this regard. At the end of Phase I (1999), SO2

emissions from the 263 sources affected by Phase I were reduced 50 percent below 1990 levels; NOx

emissions were reduced about 32 percent below 1990 levels.
Acid Rain Program: Annual Progress Report, 2000 Page 5

Starting in Phase II (2000), additional units are affected with more stringent SO2 emissions limitations

nationwide. NOx rates (i.e., the amount of NOx emitted per unit of coal used) were also reduced (to

between 0.40 and 0.86 lbs/mmBtu, depending on the boiler type). In the first year of Phase II,

emissions continued to decline. In 2000, SO2 emissions from power generation were reduced by 1.25

million tons, and emissions of NOx were reduced by 380,000 tons, from the previous year.

SO2 PROGRAM COMPLIANCE RESULTS

All Title IV Units Reduce Overall Emissions by 29 Percent from 1990 Levels; 

10 Percent from 1999 Levels

In the first year of Phase II, all Title IV sources achieved a total reduction in SO2 emissions of almost

29 percent, when compared to 1990 levels. Compared to 1999 levels, these units reduced their SO2

emissions by 10 percent or 1.25 million tons, while increasing their utilization by 2.7 percent. Exhibit 3

illustrates the trend in SO2 emissions since 1980 for all affected units.

Exhibit 3

National SO2 Emissions Trend for All Acid Rain Program Affected Units
Acid Rain Program: Annual Progress Report, 2000 Page 6

There were 2,262 operating units that underwent annual reconciliation for SO2 in 2000. (These units

are listed on our website at www.epa.gov/airmarkets/cmprpt/arp00/index.html in Appendix A). 

The allowances (i.e., authorizations to emit SO2) allocated in a particular year to each source are

determined by several provisions of the Act. For the year 2000, a total of 9.97 million allowances were

granted. However, as a result of sources emitting less than their allowance allocations during 1995

through 1999, 11.62 million allowances were saved (or banked). Coupled with the 9.97 million

allowances granted in 2000 by the Act, a total of 21.58 million allowances were available for use in

2000. Nevertheless, sources emitted only 11.2 million tons in 2000. However, this was 1.2 million

tons more than the allowances granted in 2000, so the bank declined by 1.2 million allowances.

(Exhibit 4). The bank is expected to decrease as sources use up these banked allowances to comply

with the more stringent Phase II requirements.

Exhibit 4

The SO2 Allowance Bank: Emissions and Allocations (1995-2000*)
Acid Rain Program: Annual Progress Report, 2000 Page 7

Exhibit 5 explains in more detail the origin of the allowances available for use in the year 2000. 

Exhibit 5

Origin of 2000 Allowable Emissions Level

Type of Allowance Allocation Number of

Allowances

Explanation of Allowance Allocation Type

Initial Allocation 9,166,6141 Initial Allocation is the number of allowances granted to units

based on the product of their historic utilization and emissions

rates (performance standards) specified in the Clean Air Act

and other provisions of the Act.

Early Reduction Credits 416,989 Early Reduction Credit allowances were given to eligible Phase

II units for voluntary emissions reductions made between

January 1, 1995 and January 1, 2000.

Allowances for Substitution Units 10,636 A lawsuit settlement allowed for a small amount of allowances

to be allocated for Substitution Units in 2000 instead of an

earlier year during Phase I.

Allowance Auctions 250,000 Allowance Auctions provide allowances to the market that were

set aside in a Special Allowance Reserve when the initial

allowance allocation was made.

Opt-in Allowances 97,824 Opt-in Allowances are provided to units entering the program

voluntarily. There were 11 opt-in units in 2000.

Small Diesel Allowances 24,468 Small Diesel Allowances were allocated annually to small

diesel refineries that produced and desulfurized diesel fuel

during the previous year. These allowances were earned in

1999, which was the last year of the small diesel program.

TOTAL 2000 ALLOCATION 9,966,531

BANKED ALLOWANCES 11,607,955 Banked Allowances are those held over from 1995 through

1999 which can be used for compliance in 2000 or any future

year.

Conservation and Renewable

Energy Allowances

9,054 These allowances come from a special reserve set aside when

the initial allowance allocation was made. They are awarded to

utilities that undertake efficiency and renewable energy

measures. These are year 1999 allowances that were allocated

in year 2000.

TOTAL 2000 ALLOWABLE 21,583,540

1

 The total year 2000 initial allocation was 9,191,897. A total of 25,283 allowances were surrendered by units that

exceeded their 1999 Phase I Extension projected emissions limit, and were subject to Phase I substitution unit provisions.
Acid Rain Program: Annual Progress Report, 2000 Page 8

1 A source that does not hold enough allowances in its unit account to cover its annual SO2 emissions has “excess

emissions” and must pay a $2000 per ton automatic penalty. The $2000 penalty is adjusted annually for inflation, so the

year 2000 penalty was $2,682. Total year 2000 monetary penalty = 54 tons of excess emissions x $2,682 per ton =

$144,828.

Exhibit 6

 SO2 Allowance Reconciliation Summary

Total Allowances Held in Accounts as of 3/1/2001 (1995 through 2000 Vintages)1 21,583,540

 Unit Accounts 15,753,910

 General Accounts2 5,829,630

 Allowances Deducted for Emissions (1995 through 2000) 11,201,999

2001 Penalty Allowances Deducted 54

Banked Allowances 10,381,541

 Unit Accounts 4,551,911

 General Accounts2 5,829,630

Deducting Allowances for Compliance

The total number of allowances deducted in 2000 was 11,202,053. Because a few sources did not hold

enough allowances in their allowance tracking system unit accounts to cover their emissions for the

2000 compliance year, 54 year 2001 allowances were taken as “offsets”and included in the total. In

addition to the offsets, the operators of these six units were assessed automatic monetary penalties

totaling $144,828.1 Exhibit 6 displays these allowance deductions, as well as the remaining bank of

1995 through 2000 allowances. 

1

 The number of allowances held in the Allowance Tracking System (ATS) accounts equals the number of 2000 allowances

allocated (see Exhibit 5) plus the number of banked allowances. March 1, 2001 represents the Allowance Transfer

Deadline, the point in time at which unit accounts are frozen and after which no transfers of 1995 through 2000 allowances

will be recorded. The freeze on these accounts is removed when annual reconciliation is complete.

2

 General accounts can be established in the ATS by any utility, individual or other organization.

At an individual unit, the number of allowances surrendered was equal to the number of tons emitted at

the unit, except where the unit shared a common stack with other units. For the purposes of

surrendering allowances for emissions at a common stack, the utility was allowed to choose the

proportion of allowances deducted from each unit sharing the stack, as long as enough allowances were

surrendered to cover the total number of tons emitted. If no apportionment was made, EPA deducted

allowances equally among the units sharing the stack to cover total emissions reported by the stack. 
Acid Rain Program: Annual Progress Report, 2000 Page 9

Appendix A reflects the deductions for emissions at each unit after the common stack apportionment

was made. Units sharing a common stack are listed directly under the entry for their common stack.

Geographic Trends in Sulfur Dioxide Emissions

Total sulfur dioxide emissions from power generation have decreased significantly from 1990 levels,

and continue to decline in 2000, the first year of Phase II. Exhibit 7 displays state-level bar graphs

illustrating SO2 emission trends from power generation before the Acid Rain Program (1990), during

Phase I (1995-1999 average), and in Phase II (2000).

Exhibit 7

Sulfur Dioxide Emissions from Power Generation:

State-level Bar Graph (1990, 1995-1999 Phase I Average, 2000)
Acid Rain Program: Annual Progress Report, 2000 Page 10

Several geographic trends are shown:

• The bar graphs illustrate that total SO2 emissions, as well as the greatest reductions, are

largely taking place in the Midwest; 

• The states colored yellow represent states with lower SO2 emissions in Phase II (2000),

as compared to both 1990 levels and the 1995-1999 Phase I average. Unlike the SO2

emission reductions achieved during Phase I which occurred predominantly in the

Eastern U.S. (since Phase I affected the larger, higher emitting utilities in the Eastern

half of the country), these Phase II reductions are geographically more widespread,

occurring in a larger number of Western states. 

Exhibit 8

Geographic and Temporal Trends in Sulfur Dioxide Emissions from Power Generation

(1990, 1995-1999 Phase I Average, 2000)

Exhibit 8 illustrates the geographic and temporal trends in state-level sulfur dioxide emissions from

power generation before the Acid Rain Program (1990), during Phase I (1995-1999 average), and in

Phase II (2000). 
Acid Rain Program: Annual Progress Report, 2000 Page 11

In 2000, Title IV sources achieved a 29 percent reduction from 1990 SO2 levels nationwide. As

illustrated in Exhibit 8, although most SO2 emissions occur in the Midwestern U.S., it is important to

note that over time, this same region has also seen the most significant decrease in SO2 emissions in the

country. The highest SO2 emitting states in 1990 (Ohio, Indiana, and Pennsylvania), have achieved an

average reduction of almost 40 percent in 2000 (45 percent, 42 percent, and 23 percent, respectively),

as compared to 1990 levels. Other states in the region are showing similar trends: Illinois (52 percent),

Kentucky (35 percent), Missouri (71 percent), Tennessee (47 percent) and West Virginia (39 percent),

have achieved an average reduction of almost 50 percent since 1990. 

SO2 ALLOWANCE MARKET

The flexibility provided by the Acid Rain Program enable the 2,262 units subject to the SO2

requirements in 2000 to pursue a variety of compliance options to meet their SO2 reduction obligations,

including scrubber installation, fuel switching, energy efficiency and allowance trading. The presence

of the allowance market has given some sources the incentive to reduce their SO2 emissions below the

level of their allowance allocation in order to bank their allowances for use in future years. Other

sources have been able to postpone and possibly avoid expenditures for control by acquiring

allowances from sources that controlled below their allowance allocation level. The flexibility in

compliance options is possible because of the accountability provided through strict monitoring

requirements for all affected units that ensure one allowance is equivalent to one ton of SO2. The

program’s flexibility significantly reduced the cost of achieving these emissions reductions as

compared to the cost of a technological mandate. 

The marginal cost of reducing a ton of SO2 from the utility sector should be reflected in the price of an

allowance. The cost of reductions continues to be lower than anticipated when the Clean Air Act

Amendments were enacted, and the price of allowances reflects this. The cost of compliance was

initially estimated at $400-1000/ton, however during 2000, SO2 allowances ranged in price from

$130/ton to $155/ton. At the time of the allowance auction, allowances were approximately $135/ton. 

The price rose through June, peaking at $155/ton. During the second half of 2000, prices dropped

down to $130/ton but showed signs of a rebound at the very end of the year. Some market observers

believe lower than expected allowances prices during the first several years of the program were due

primarily to lower than expected compliance costs and larger than expected emissions reductions,

which have increased the supply of allowances and put downward pressure on prices. Additionally,

Phase II’s more stringent limits most likely fueled the end-of-year price increases as sources realized

they would have to withdraw from the bank to comply. Exhibit 9 displays the price trend since mid1994, based on monthly price reports from Cantor Fitzgerald Environmental Brokerage Services, and a

market survey conducted by Fieldston Publications.

The level of activity in the allowance market created under the Acid Rain Program increased in 2000

compared to earlier years, with the increase in the number of sources required to comply with Phase II

of the program.
Acid Rain Program: Annual Progress Report, 2000 Page 12

0

50

100

150

200

250

8/1/942/1/958/1/952/1/968/1/962/1/978/1/972/1/988/1/982/1/998/1/992/1/008/1/00

Month/Year

Allowance Price in dollars

Fieldston Publications Price Index Cantor Fitzgerald Market Price Index

0

5

10

15

20

25

30

35

1994 1995 1996 1997 1998 1999 2000

Allowances Transferred 

(Millions)

Between Economically Related Organizations

Between Economically Unrelated Organizations

Exhibit 9

SO2 Allowance Price Indices

 In 2000, 4,690 allowance transfers were recorded in the Allowance Tracking System, the accounting

system developed to track holdings of allowances, moving about 30 million allowances. Of the

allowances transferred, 12.7 million, or 42 percent, were transferred in economically significant

transactions, i.e. between unrelated parties. Exhibit 10 shows the volume of SO2 allowances traded

under the Acid Rain Program since official recordation of trades began in 1994. The majority of the

allowances transferred in economically significant transactions were acquired by utilities. Trades

between unaffiliated utilities accounted for approximately 7 million allowances. 

Exhibit 10

SO2 Allowances Transferred Under the Acid Rain Program
Acid Rain Program: Annual Progress Report, 2000 Page 13

All transactions, along with data on account balances and ownership, are posted on the Clean Air

Markets Division’s Internet site (www.epa.gov/airmarkets) on a daily basis in order to better inform

trading participants. Also available are cumulative market statistics and analysis. 

NOX PROGRAM COMPLIANCE RESULTS

Instead of using allowance trading to facilitate emissions reductions, the Title IV NOX program

establishes standard emission limitations for certain affected units. Title IV of the 1990 Clean Air Act

Amendments required EPA to establish NOX annual average emission limits (in pounds of NOX per

million British thermal units of fuel consumed (lb/mmBtu)) for coal-fired electric utility units. The

NOX program was implemented in two phases.

In April 1995, EPA published regulations which established NOX emission limits beginning on January

1, 1996 for Group 1 boilers that were also part of the Phase I SO2 program (Group 1 boilers are dry

bottom, wall-fired boilers and tangentially-fired boilers). From 1996 through 1999, Phase I dry bottom

wall-fired boilers were subject to a NOX emission limit of 0.50 lb/mmBtu and Phase I tangentially-fired

boilers were subject to a NOX emission limit of 0.45 lb/mmBtu annually.

In addition, the April 1995 regulations allowed Phase II Group 1 units to use an “early election”

compliance option. Under this regulatory provision, Phase II Group 1 NOX affected units meet the

higher Phase I limits for their boiler type from 1997 through 2007. In return for meeting this limit

three years earlier than they would be required to meet the Phase II limit, early election units do not

become subject to the more stringent Phase II limits until 2008. If a utility fails to meet this annual

limit for the boiler during any year, the unit is subject to the more stringent Phase II limit for Group 1

boilers beginning in 2000, or the year following the exceedance, whichever is later.

In December 1996, EPA established the NOX emission limits for Phase II Group 1 boilers and for

Group 2 boilers (cell burner, cyclone, wet bottom, and vertically-fired boilers) that apply beginning on

January 1, 2000. As a result of the April 1995 and December 1996 regulations, NOX reductions were

projected to be approximately 400,000 tons per year in 1996 through 1999 (Phase I), and 2 million tons

per year in 2000 and subsequent years (Phase II) below what the emissions would have been without

the Acid Rain Program.

There were 1,046 units subject to NOX emissions limitations in 2000. Exhibit 11 shows the number of

NOX affected units by boiler type.

For each NOX affected unit, a utility can comply with the applicable standard emission limitation, or

may participate in two additional compliance options which add flexibility to the rate-based

compliance requirements: 
Acid Rain Program: Annual Progress Report, 2000 Page 14

! Emissions Averaging. A utility can meet the standard emission limitation by averaging the

heat-input weighted annual emission rates of two or more units. 

! Alternative Emission Limitation (AEL). A utility can petition for a less stringent alternative

emission limitation if it uses the properly installed and operated NOX emissions reduction

technology prescribed for that boiler, but cannot meet its standard limit. EPA determines

whether an AEL is warranted based on analyses of emissions data and information about the

NOX control equipment.

Exhibit 12 summarizes the compliance options chosen by NOX affected units for 2000. Averaging was

the most widely chosen compliance option, with 53 averaging plans involving 645 units in 2000. See

Appendix B-2 for a list of averaging plans and results in 2000. 

For 2000, 1,045 NOX units met the required emission limit through compliance with either the standard

emission limitation (including units that early elected), emissions averaging, or an alternative emission

limitation. (See Appendix B-1: Compliance Results for NOX Affected Units. For a more detailed

description of EPA's methodology for determining unit compliance with NOX limits, see Appendix B3: Description of NOX Compliance Assessment Methodology.) 

Exhibit 11

Phase II NOX Units by Boiler Type

Boiler Type

Standard 

Emission

Limit

Number

of Units

Phase I Group1 Tangentially-fired 0.45 135

Phase I Group1 Dry Bottom Wall-fired 0.50 130

Phase II Group 1 Tangentially-fired 0.40 304

Phase II Group 1 Dry Bottom Wall-fired 0.46 312

Cell Burners 0.68 37

Cyclones > 155 MW 0.86 56

Wet Bottom > 65 MW 0.84 31

Vertically-fired 0.80 41

Total 1,046
Acid Rain Program: Annual Progress Report, 2000 Page 15

Only one unit failed to meet its emissions limit in 2000. This unit had NOX excess emissions of 58

tons and was assessed a monetary penalty of $155,556 (58 tons x $2,682 per ton penalty).

Exhibit 12

Compliance Options Chosen in 2000

Compliance Option Number of Units

Standard Emission Limitation 133

Early Election 274

Emissions Averaging 645

Alternative Emission Limitation 27

TOTAL 1,0791

1 The numbers of units do not add to 1,046 because 29 units must meet both early election 

and emissions averaging limits, and 4 units must meet both AEL and emissions averaging limits.

 

NOX Mass Emissions Reductions Exceed Goal by One Million Tons:

Phase II Units Reduced Overall NOx Emissions by 23 Percent from 1990 Levels;

7 Percent from 1999 Levels

Total NOX emissions from all Title IV affected units were three million tons below what they would

have been without the Acid Rain Program in 2000, easily surpassing the goal of a two million ton

reduction. Exhibit 13 illustrates the change in NOX mass emissions since 1990 for all affected units. 

For the 2,262 Phase II units, total NOX mass emissions in 2000 were 1.55 million tons or 23.3 percent

lower than in 1990, and 0.38 million tons or 6.9 percent lower than in 1999. 

These reductions have been achieved while electrical production, as measured by heat input, has

increased 30 percent since 1990 and 2.7 percent compared to1999. As illustrated in Exhibit 14, many

states with increasing electrical production have also decreased total NOX emissions in 2000, as

compared to 1990 levels. Without further reductions in emissions rates, though, NOX emissions would

be expected to rise with increased utilization.
Acid Rain Program: Annual Progress Report, 2000 Page 16

Exhibit 13

NOX Mass Emissions for Phase II Units
Acid Rain Program: Annual Progress Report, 2000 Page 17

Exhibit 14

State-level Electrical Production (Heat Input): 1990, 1999, 2000

Geographic Trends in Nitrogen Oxide Emissions

Total nitrogen oxide emissions from Title IV sources have decreased 23 percent since 1990. Exhibit

15 displays state-level bar graphs illustrating NOX emission trends from power generation before the

Acid Rain Program (1990), during Phase I (1996-1999 average), and in Phase II (2000).

Several geographic trends are shown:

· The bar graphs illustrate that in the first year of Phase II, many states have reduced NOX

emissions from 1990 levels, with the greatest reduction occurring in the Eastern United States; 
Acid Rain Program: Annual Progress Report, 2000 Page 18

Exhibit 15

State-level Nitrogen Oxide Emissions from Power Generation: Bar Graphs 

(1990, 1996-1999 Phase I Average, 2000)

• The states colored yellow represent states with lower NOX emissions in Phase II (2000), as

compared to both 1990 levels and the 1996-1999 Phase I average. Like SO2, during Phase I, the

majority of NOX reductions occurred predominantly in the Eastern U.S. However, the Phase II

reductions are geographically more extensive, occurring in a larger number of Western states. 

As illustrated in Exhibit 16, in 1990, the greatest NOX emissions occurred in the Midwestern, MidAtlantic and Southern regions of the U.S. In 2000, many of these states have significantly reduced

emissions from 1990 levels. The highest emitting states in 1990 (Ohio, Texas, and Pennsylvania),

have achieved an average reduction of about 32 percent (30 percent, 16 percent, and 51 percent,

respectively) in 2000. Other states in the region are showing similar trends: Indiana (21 percent),

Kentucky (29 percent), Tennessee (34 percent) and West Virginia (23 percent), have achieved an

average reduction of 27 percent since 1990. 
Acid Rain Program: Annual Progress Report, 2000 Page 19

Exhibit 16

Geographic and Temporal Trends in Nitrogen Oxide Emissions from Power Generation

(1990, 1996-1999 Phase I Average, 2000)

SO2 AND NOX MONITORING IN 2000

In order to verify the reductions of SO2 and NOX emissions mandated under the Act and to support the

SO2 allowance trading program, a fundamental objective of the Acid Rain Program is to ensure

accurate accounting of all pollutant emissions from all affected boilers and turbines. To implement

this objective, concentrations and mass emissions of SO2 and NOX from each affected unit are

measured and recorded using Continuous Emissions Monitoring Systems (CEMS) (or an approved

alternate measurement method) certified by EPA to meet the high accuracy standards of the Acid Rain

Program.

SO2 mass emissions are determined using CEMS to measure SO2 concentration and stack flow rate. 

NOX emission rates, on the other hand, are determined with NOX and diluent gas (CO2 or O2)

concentration monitors. These monitors are required to meet strict initial and on-going performance

standards to demonstrate the accuracy, precision, and timeliness of their measurement capability. 
Acid Rain Program: Annual Progress Report, 2000 Page 20

One measure of the accuracy of a CEMS is the relative accuracy test audit (RATA), which is required

for initial certification of a CEMS and for on-going quality assurance. The RATA ensures that the

installed monitor measures the “true” value of the pollutant by comparing the monitor to a reference

method which simultaneously measures the stack gas pollutant. Thus, the lower the relative accuracy

resulting from the test audit, the more accurate the monitor. All monitoring systems must meet a

certain relative accuracy standard in order to be qualified to report emissions to the Acid Rain

Program. Because the RATA determines relative accuracy as an absolute value, it does not detect

whether the difference between the reference method values and the readings from the CEMS being

tested is due to random error or to systematic bias. Therefore, an additional test, the bias test, is

required to ensure that emissions are not underestimated. This test determines if the CEMS is

systematically biased low compared to the reference method and if so, a bias adjustment factor is

calculated and applied to all reported data from that monitoring system to ensure there is no systematic

underreporting. Exhibit 17 highlights the relative accuracy results achieved by Acid Rain CEMS in

2000. 

Exhibit 17

2000 Relative Accuracy Test Audit (RATA) Results 

SO2 Concentration Volumetric Flow

Rate

NOX Rate

Mean Relative Accuracy 3.65% 3.30% 4.22%

Median Relative Accuracy 2.84% 2.69% 3.36%

Percent Meeting Relative Accuracy

Standard

96.6% 98.6% 94.9%

Another metric used to determine the effectiveness of a CEMS is the percentage of hours that a monitoring

system is operating properly and meeting all performance standards and therefore, able to record and report

an emissions value. This metric is defined as the percent monitor availability (PMA). Exhibit 18 shows

the monitor availabilities reported in 2000 and indicates that the CEMS used to determine SO2 mass

emissions and NOX emission rates are well maintained and fulfilling the high performance standards

required by the Acid Rain Program. 

Exhibit 18

2000 CEMS Availability

Parameter Median % Availability at End of 2000

Coal-Fired Units Oil and Gas Units

SO2 99.5 98.7

Flow 99.6 99.2

NOX 99.2 98.2
Acid Rain Program: Annual Progress Report, 2000 Page 21

2

For more information on these regional NOx reduction programs, visit http://www.epa.gov/airmarkets.

CONCLUSION

Both SO2 and NOX emissions declined in the first year of Phase II of the Acid

Rain Program. Phase II sources continue to close in on the 10 million ton

reduction of SO2 emissions and exceeded the goal of a two million ton

reduction of NOX emissions by a sizeable margin.

In 2000, SO2 emissions fell, however the use of allowances saved by sources

from emitting less than required in Phase I resulted in SO2 emissions higher

than the year 2000 allowance allocations. This was both expected and allowed,

due to the substantial early reductions achieved in Phase I. EPA expects Phase II sources to continue to

use up the bank of allowances over the next several years, and to achieve the goal of an annual10 million

ton reduction from 1980 levels by 2010.

NOX emissions in 2000 were an impressive three million tons below what emissions would have been

without the Acid Rain Program. Furthermore, the implementation of regional NOX cap-and-trade

programs (i.e., the NOX Budget Program in the Ozone Transport Region and the NOX SIP Call2) are

changing expectations concerning future emissions levels. EPA’s expectation had been that over time,

NOX emissions would gradually rise due to increasing electricity production. However, because of the

eastern regional cap, it now appears that nationwide NOX emissions may decline over the next several

years as the NOX SIP call is implemented, and then remain stable or rise more slowly as energy demand

continues to grow and new sources continue to be built. 

For additional detailed emissions data see http://www.epa.gov/airmarkets/emissions/score00/index.html

 
APPENDIX A: ACID RAIN PROGRAM - YEAR 2000 SO2 ALLOWANCE HOLDINGS AND DEDUCTIONS

STATE PLANT NAME

PLANT 

CODE STACK/UNIT ID*

2000 

ALLOWANCES 

ALLOCATED

HELD IN 

ACCOUNTS AS 

OF 3/1/2001

ALLOWANCES 

DEDUCTED

AL Barry 3 CS0AAN (1, 2, 3)AL Barry 3 1 3,882 6,490 6,06AL Barry 3 2 4,292 6,854 6,40AL Barry 3 3 8,811 10,205 9,53AL Barry 3 4 10,051 15,429 14,42AL Barry 3 5 24,836 26,644 24,90AL Barry 3 6A 0 10 AL Barry 3 6B 0 10 AL Charles R Lowman 56 1 1,853 7,502 3,17AL Charles R Lowman 56 2 7,026 7,061 6,40AL Charles R Lowman 56 3 5,895 7,296 6,63AL Chickasaw 5 110 111 111 AL Colbert 47 CSCO14 (1, 2, 3, 4)AL Colbert 47 1 5,854 19,006 6,29AL Colbert 47 2 6,602 28,600 6,40AL Colbert 47 3 6,641 29,814 6,37AL Colbert 47 4 6,646 31,580 6,66AL Colbert 47 5 16,033 53,216 44,45AL E C Gaston 26 CS0CAN (1, 2)AL E C Gaston 26 1 7,805 26,699 18,18AL E C Gaston 26 2 7,996 31,283 18,68AL E C Gaston 26 CS0CBN (3, 4)AL E C Gaston 26 3 7,896 25,750 20,17AL E C Gaston 26 4 8,313 37,572 17,90AL E C Gaston 26 5 25,805 82,427 42,91AL Gadsden 7 1 1,957 5,385 5,03AL Gadsden 7 2 2,024 6,055 4,70AL General Electric Company 7698 CC1 0 10 AL Gorgas 8 5 1,756 1,756 AL Gorgas 8 CS0DAN (6, 7)AL Gorgas 8 6 3,036 12,026 11,14AL Gorgas 8 7 3,139 10,082 9,42AL Gorgas 8 8 4,759 10,571 9,87AL Gorgas 8 9 4,747 9,166 8,63AL Gorgas 8 10 22,443 34,062 31,83AL Greene County 10 1 8,488 24,800 23,61AL Greene County 10 2 7,923 25,109 23,91AL Greene County 10 CT2 0 100 4AL Greene County 10 CT3 0 100 3AL Greene County 10 CT4 0 100 4AL Greene County 10 CT5 0 100 5AL Greene County 10 CT6 0 100 3AL Greene County 10 CT7 0 100 4AL Greene County 10 CT8 0 100 2

A, 1
APPENDIX A: ACID RAIN PROGRAM - YEAR 2000 SO2 ALLOWANCE HOLDINGS AND DEDUCTIONS

STATE PLANT NAME

PLANT 

CODE STACK/UNIT ID*

2000 

ALLOWANCES 

ALLOCATED

HELD IN 

ACCOUNTS AS 

OF 3/1/2001

ALLOWANCES 

DEDUCTED

AL Greene County 10 CT9 0 100 4AL Greene County 10 CT10 0 100 4AL James H Miller Jr 6002 1 14,217 17,558 16,40AL James H Miller Jr 6002 2 17,769 17,769 16,37AL James H Miller Jr 6002 3 17,422 17,422 15,46AL James H Miller Jr 6002 4 8,049 18,134 16,94AL McIntosh 7063 **1 938 503 AL McIntosh 7063 **2 0 5 AL McIntosh 7063 **3 0 5 AL Mcwilliams 533 **4 0 5 AL Washington County Cogen (Olin) 7697 CC1 0 10 AL Widows Creek 50 CSWC16 (1, 2, 3, 4, 5, 6)AL Widows Creek 50 1 3,340 5,340 4,64AL Widows Creek 50 2 3,212 6,212 5,85AL Widows Creek 50 3 3,356 5,856 5,27AL Widows Creek 50 4 3,454 4,954 4,13AL Widows Creek 50 5 3,565 5,065 4,81AL Widows Creek 50 6 3,279 6,779 6,57AL Widows Creek 50 7 7,805 11,005 10,39AL Widows Creek 50 8 7,460 12,460 11,05AR Carl Bailey 202 01 10 310 26AR Cecil Lynch 167 1 0 0 AR Cecil Lynch 167 2 0 1 AR Cecil Lynch 167 3 3 2 AR Flint Creek 6138 1 15,192 15,192 12,86AR Hamilton Moses 168 1 0 2 AR Hamilton Moses 168 2 0 2 AR Harvey Couch 169 1 7 2 AR Harvey Couch 169 2 112 3 AR Independence 6641 1 18,155 14,574 10,60AR Independence 6641 2 18,401 17,844 11,25AR Lake Catherine 170 1 0 2 AR Lake Catherine 170 2 0 2 AR Lake Catherine 170 3 8 4 AR Lake Catherine 170 4 156 6 AR Mcclellan 203 01 15 2,115 1,64AR Robert E Ritchie 173 1 53 6 AR Robert E Ritchie 173 2 2,148 2,153 AR Thomas Fitzhugh 201 1 1 601 14AR White Bluff 6009 1 20,940 22,378 19,67AR White Bluff 6009 2 23,900 20,640 18,59AZ Agua Fria 141 1 54 54 1AZ Agua Fria 141 2 65 65 2AZ Agua Fria 141 3 77 77 3

A, 2
APPENDIX A: ACID RAIN PROGRAM - YEAR 2000 SO2 ALLOWANCE HOLDINGS AND DEDUCTIONS

STATE PLANT NAME

PLANT 

CODE STACK/UNIT ID*

2000 

ALLOWANCES 

ALLOCATED

HELD IN 

ACCOUNTS AS 

OF 3/1/2001

ALLOWANCES 

DEDUCTED

AZ Apache Station 160 1 331 11 AZ Apache Station 160 2 1,609 3,417 3,41AZ Apache Station 160 3 3,011 3,223 3,15AZ Cholla 113 1 2,223 945 85AZ Cholla 113 2 5,443 1,528 1,38AZ Cholla 113 3 5,147 9,355 8,37AZ Cholla 113 4 8,334 8,334 7,27AZ Cholla 113 **5 0 0 AZ Coronado 6177 U1B 5,733 10,052 10,05AZ Coronado 6177 U2B 5,903 9,409 9,40AZ De Moss Petrie 124 4 0 0 AZ Gila Bend 923 **GT1 0 0 AZ Gila Bend 923 **GT2 0 0 AZ Gila Bend 923 **GT3 0 0 AZ Gila Bend 923 **GT4 0 0 AZ Irvington 126 1 16 2 AZ Irvington 126 2 28 3 AZ Irvington 126 3 0 5 AZ Irvington 126 4 2,854 3,816 3,41AZ Kyrene 147 K-1 7 46 4AZ Kyrene 147 K-2 18 46 4AZ Navajo 4941 1 26,220 3,458 1,20AZ Navajo 4941 2 24,262 3,451 1,68AZ Navajo 4941 3 25,042 3,451 1,94AZ Ocotillo 116 1 56 7 AZ Ocotillo 116 2 132 5 AZ Saguaro 118 1 204 161 14AZ Saguaro 118 2 25 3 AZ Springerville 8223 1 6,566 10,051 9,03AZ Springerville 8223 2 5,756 11,048 10,01AZ Springerville 8223 3 0 0 AZ West Phoenix 117 4 11 0 AZ West Phoenix 117 6 22 0 AZ Yuma Axis 120 1 42 42 1CA AES Alamitos, LLC 315 1 2,775 51 CA AES Alamitos, LLC 315 2 105 1 CA AES Alamitos, LLC 315 3 290 3 CA AES Alamitos, LLC 315 4 819 13 CA AES Alamitos, LLC 315 5 4,227 76 CA AES Alamitos, LLC 315 6 1,484 23 CA AES Huntington Beach, LLC 335 1 1,325 26 CA AES Huntington Beach, LLC 335 2 1,134 21 CA AES Huntington Beach, LLC 335 3 161 0 CA AES Huntington Beach, LLC 335 4 176 0 

A, 3
APPENDIX A: ACID RAIN PROGRAM - YEAR 2000 SO2 ALLOWANCE HOLDINGS AND DEDUCTIONS

STATE PLANT NAME

PLANT 

CODE STACK/UNIT ID*

2000 

ALLOWANCES 

ALLOCATED

HELD IN 

ACCOUNTS AS 

OF 3/1/2001

ALLOWANCES 

DEDUCTED

CA AES Redondo Beach, LLC 356 5 80 2 CA AES Redondo Beach, LLC 356 6 105 2 CA AES Redondo Beach, LLC 356 7 554 11 CA AES Redondo Beach, LLC 356 8 597 13 CA AES Redondo Beach, LLC 356 11 36 0 CA AES Redondo Beach, LLC 356 12 0 0 CA AES Redondo Beach, LLC 356 13 0 0 CA AES Redondo Beach, LLC 356 14 0 0 CA AES Redondo Beach, LLC 356 15 0 0 CA AES Redondo Beach, LLC 356 16 0 0 CA AES Redondo Beach, LLC 356 17 0 0 CA Almond Power Plant 7315 1 0 20 CA Alta (Cool Water) 329 1 10 2 CA Alta (Cool Water) 329 2 6 2 CA Alta (Cool Water) 329 31 0 2 CA Alta (Cool Water) 329 32 0 2 CA Alta (Cool Water) 329 41 0 4 CA Alta (Cool Water) 329 42 0 4 CA Anaheim Combustion Turbine 7693 1 0 0 CA Avon 216 1 17 0 CA Avon 216 2 0 0 CA Avon 216 3 0 0 CA Broadway 420 B1 127 27 CA Broadway 420 B2 164 27 CA Broadway 420 B3 74 26 CA Cabrillo Power I LLC (Encina) 302 CS0001 (1, 2, 3, 4, 5)CA Cabrillo Power I LLC (Encina) 302 1 491 0 CA Cabrillo Power I LLC (Encina) 302 2 1,131 0 CA Cabrillo Power I LLC (Encina) 302 3 737 0 CA Cabrillo Power I LLC (Encina) 302 4 1,946 1 CA Cabrillo Power I LLC (Encina) 302 5 2,495 160 6CA Carson Cogeneration 7527 1 0 15 CA Carson Cogeneration 7527 2 0 5 CA Contra Costa 228 1 125 0 CA Contra Costa 228 2 2 0 CA Contra Costa 228 3 0 0 CA Contra Costa 228 4 0 0 CA Contra Costa 228 5 0 0 CA Contra Costa 228 6 0 0 CA Contra Costa 228 7 28 0 CA Contra Costa 228 8 53 0 CA Contra Costa 228 9 356 30 CA Contra Costa 228 10 4,286 4 CA Duke Energy Morro Bay LLC 259 1 1,561 12 

A, 4
APPENDIX A: ACID RAIN PROGRAM - YEAR 2000 SO2 ALLOWANCE HOLDINGS AND DEDUCTIONS

STATE PLANT NAME

PLANT 

CODE STACK/UNIT ID*

2000 

ALLOWANCES 

ALLOCATED

HELD IN 

ACCOUNTS AS 

OF 3/1/2001

ALLOWANCES 

DEDUCTED

CA Duke Energy Morro Bay LLC 259 2 139 18 CA Duke Energy Morro Bay LLC 259 3 3,822 11 CA Duke Energy Morro Bay LLC 259 4 3,053 26 CA Duke Energy South Bay LLC 310 1 2,492 68 CA Duke Energy South Bay LLC 310 2 1,775 64 CA Duke Energy South Bay LLC 310 3 2,177 16 CA Duke Energy South Bay LLC 310 4 603 59 CA El Centro 389 3 614 514 CA El Centro 389 4 586 586 CA El Centro 389 2-2 0 100 CA El Segundo 330 1 440 12 CA El Segundo 330 2 90 2 CA El Segundo 330 3 182 4 CA El Segundo 330 4 370 7 CA Glenarm 422 16 0 0 CA Glenarm 422 17 0 0 CA Grayson 377 4 102 102 CA Grayson 377 5 36 36 CA Harbor Gen Station 399 1 68 0 CA Harbor Gen Station 399 2 121 0 CA Harbor Gen Station 399 3 94 0 CA Harbor Gen Station 399 4 104 0 CA Harbor Gen Station 399 5 171 0 CA Harbor Gen Station 399 **10A 699 6 CA Harbor Gen Station 399 **10B 699 0 CA Haynes Gen Station 400 1 681 131 CA Haynes Gen Station 400 2 338 338 CA Haynes Gen Station 400 3 1,244 1,244 CA Haynes Gen Station 400 4 1,002 1,002 CA Haynes Gen Station 400 5 1,401 1,401 CA Haynes Gen Station 400 6 1,527 1,527 CA Humboldt Bay 246 1 358 302 CA Humboldt Bay 246 2 24 300 10CA Hunters Point 247 3 76 2 CA Hunters Point 247 4 5 2 CA Hunters Point 247 5 74 2 CA Hunters Point 247 6 1 2 CA Hunters Point 247 7 192 35 CA Kern 251 1 3 0 CA Kern 251 2 0 0 CA Kern 251 3 13 0 CA Kern 251 4 0 0 CA Magnolia 375 M4 37 0 CA Martinez 256 1 1 0 

A, 5
APPENDIX A: ACID RAIN PROGRAM - YEAR 2000 SO2 ALLOWANCE HOLDINGS AND DEDUCTIONS

STATE PLANT NAME

PLANT 

CODE STACK/UNIT ID*

2000 

ALLOWANCES 

ALLOCATED

HELD IN 

ACCOUNTS AS 

OF 3/1/2001

ALLOWANCES 

DEDUCTED

CA Martinez 256 2 1 0 CA Martinez 256 3 1 0 CA Moss Landing 260 1 122 1 CA Moss Landing 260 2 0 0 CA Moss Landing 260 3 0 0 CA Moss Landing 260 4 0 0 CA Moss Landing 260 5 0 0 CA Moss Landing 260 6 0 0 CA Moss Landing 260 7 79 0 CA Moss Landing 260 8 466 4 CA Moss Landing 260 6-1 8,924 40 CA Moss Landing 260 7-1 976 31 1CA Mountain Vista (Etiwanda) 331 1 117 3 CA Mountain Vista (Etiwanda) 331 2 29 2 CA Mountain Vista (Etiwanda) 331 3 1,372 19 CA Mountain Vista (Etiwanda) 331 4 261 6 CA Mountainview (San Bernadino) 358 1 118 3 CA Mountainview (San Bernadino) 358 2 17 0 CA NCPA Combustion Turbine Project #2 7449 NA1 0 25 CA Ocean Vista (Mandalay) 345 1 1,379 24 CA Ocean Vista (Mandalay) 345 2 1,291 21 CA Oleum 263 1 146 0 CA Oleum 263 2 138 0 CA Oleum 263 3 244 4 CA Oleum 263 4 102 0 CA Oleum 263 5 174 2 CA Oleum 263 6 204 2 CA Olive 6013 01 133 15 CA Olive 6013 02 25 0 CA Ormond Beach 350 1 4,520 77 CA Ormond Beach 350 2 4,586 81 CA Pittsburg 271 1 1,641 1 CA Pittsburg 271 2 1,350 2 CA Pittsburg 271 3 1,586 1 CA Pittsburg 271 4 1,581 2 CA Pittsburg 271 5 285 12 CA Pittsburg 271 6 3,754 4 CA Pittsburg 271 7 740 30 1CA Potrero 273 3-1 321 25 CA Riverside Canal (Highgrove) 334 1 4 4 CA Riverside Canal (Highgrove) 334 2 1 1 CA Riverside Canal (Highgrove) 334 3 1 2 CA Riverside Canal (Highgrove) 334 4 3 3 CA Sacramento Power Authority Cogen 7552 1 0 10 

A, 6
APPENDIX A: ACID RAIN PROGRAM - YEAR 2000 SO2 ALLOWANCE HOLDINGS AND DEDUCTIONS

STATE PLANT NAME

PLANT 

CODE STACK/UNIT ID*

2000 

ALLOWANCES 

ALLOCATED

HELD IN 

ACCOUNTS AS 

OF 3/1/2001

ALLOWANCES 

DEDUCTED

CA SCA Cogen II 7551 1A 0 5 CA SCA Cogen II 7551 1B 0 5 CA Scattergood Gen Sta 404 1 752 418 CA Scattergood Gen Sta 404 2 658 658 1CA Scattergood Gen Sta 404 3 262 262 CA Silver Gate 309 1 0 0 CA Silver Gate 309 2 0 0 CA Silver Gate 309 3 0 0 CA Silver Gate 309 4 0 0 CA Silver Gate 309 5 0 0 CA Silver Gate 309 6 0 0 CA Valley Gen Station 408 1 122 631 CA Valley Gen Station 408 2 141 141 CA Valley Gen Station 408 3 389 389 CA Valley Gen Station 408 4 351 351 CA Woodland Generation Station 7266 1 0 20 CO Arapahoe 465 CS1 (1, 2)CO Arapahoe 465 1 221 904 84CO Arapahoe 465 2 247 598 58CO Arapahoe 465 3 181 1,084 1,07CO Arapahoe 465 4 1,927 1,816 1,66CO Arapahoe Combustion Turbines 55200 CT5 0 0 CO Arapahoe Combustion Turbines 55200 CT6 0 0 CO Brush 4 55209 GT4 0 0 CO Brush 4 55209 GT5 0 0 CO Cameo 468 2 904 2,295 2,28CO Cherokee 469 1 2,138 2,631 2,62CO Cherokee 469 2 2,838 4,571 4,56CO Cherokee 469 3 3,761 5,053 5,01CO Cherokee 469 4 7,535 6,965 6,94CO Comanche 470 1 7,698 5,980 5,95CO Comanche 470 2 6,914 8,415 8,40CO Craig 6021 C1 8,218 6,812 4,20CO Craig 6021 C2 7,845 6,994 4,05CO Craig 6021 C3 2,602 2,602 1,80CO Fort St. Vrain 6112 2 0 5 CO Fort St. Vrain 6112 3 0 5 CO Hayden 525 H1 6,063 2,096 69CO Hayden 525 H2 9,230 2,895 1,60CO Manchief Electric Gen Station 55127 CT1 0 1 CO Manchief Electric Gen Station 55127 CT2 0 1 CO Martin Drake 492 5 1,149 1,399 1,34CO Martin Drake 492 6 2,030 2,380 2,33CO Martin Drake 492 7 3,219 4,894 4,64

A, 7
APPENDIX A: ACID RAIN PROGRAM - YEAR 2000 SO2 ALLOWANCE HOLDINGS AND DEDUCTIONS

STATE PLANT NAME

PLANT 

CODE STACK/UNIT ID*

2000 

ALLOWANCES 

ALLOCATED

HELD IN 

ACCOUNTS AS 

OF 3/1/2001

ALLOWANCES 

DEDUCTED

CO Nucla 527 1 1,122 1,522 1,27CO Pawnee 6248 1 14,443 14,745 14,67CO Pawnee 6248 **2 0 0 CO Rawhide 6761 101 1,800 1,160 84CO Ray D Nixon 8219 1 4,477 5,500 5,22CO Ray D Nixon 8219 2 0 1 CO Ray D Nixon 8219 3 0 1 CO Valmont 477 5 3,137 4,716 4,50CO Valmont 477 14 4 0 CO Valmont 477 21 20 0 CO Valmont 477 24 0 0 CO Valmont Combustion Turbine 55207 CT7 0 0 CO Zuni 478 1 340 3 CO Zuni 478 2 0 2 CO Zuni 478 3 5 3 CT Bridgeport Energy 55042 BE1 0 10 CT Bridgeport Energy 55042 BE2 0 10 CT Bridgeport Harbor 568 BHB1 2,079 1 CT Bridgeport Harbor 568 BHB2 4,727 530 47CT Bridgeport Harbor 568 BHB3 11,481 9,226 8,74CT Devon 544 3 980 940 CT Devon 544 6 898 863 CT Devon 544 CS0001 (7, 8)CT Devon 544 7 2,808 2,699 1,14CT Devon 544 8 3,003 2,886 1,43CT Devon 544 11 0 0 CT Devon 544 12 0 1 CT Devon 544 13 0 1 CT Devon 544 14 0 0 CT Devon 544 4A 170 164 CT Devon 544 4B 171 164 CT Devon 544 5A 155 149 CT Devon 544 5B 155 149 CT English 569 EB13 114 114 CT English 569 EB14 157 157 CT Mid-Conn/S. Meadow 563 15 0 0 CT Middletown 562 1 461 442 CT Middletown 562 2 1,328 996 62CT Middletown 562 3 3,339 3,209 1,19CT Middletown 562 4 2,390 2,576 2,57CT Montville 546 5 1,208 1,311 1,29CT Montville 546 6 5,675 5,304 3,41CT New Haven Harbor 6156 NHB1 13,070 9,292 9,25CT Norwalk Harbor 548 CS0001 (1, 2)

A, 8
APPENDIX A: ACID RAIN PROGRAM - YEAR 2000 SO2 ALLOWANCE HOLDINGS AND DEDUCTIONS

STATE PLANT NAME

PLANT 

CODE STACK/UNIT ID*

2000 

ALLOWANCES 

ALLOCATED

HELD IN 

ACCOUNTS AS 

OF 3/1/2001

ALLOWANCES 

DEDUCTED

CT Norwalk Harbor 548 1 5,141 4,941 3,37CT Norwalk Harbor 548 2 5,458 5,245 3,38DC Benning 603 15 517 517 39DC Benning 603 16 856 856 56DE Delaware City Refinery (Motiva) 52193 DCPP4 0 1,300 1,19DE Edge Moor 593 3 3,558 19,678 3,29DE Edge Moor 593 4 6,295 6,295 5,98DE Edge Moor 593 5 6,463 6,463 1,69DE Hay Road 7153 **3 158 158 DE Indian River 594 1 2,998 5,998 5,67DE Indian River 594 2 3,182 6,132 5,74DE Indian River 594 3 5,441 7,870 7,40DE Indian River 594 4 13,414 8,914 8,39DE McKee Run 599 3 2,585 1,085 56DE Van Sant 7318 **11 138 138 FL Anclote 8048 1 13,890 16,000 14,65FL Anclote 8048 2 13,895 12,500 11,42FL Arvah B Hopkins 688 1 81 101 8FL Arvah B Hopkins 688 2 5,524 5,504 77FL Auburndale Power Partners, LP 54658 1 0 2 FL Avon Park 624 2 495 0 FL Big Bend 645 XS12 (BB01, BB02)FL Big Bend 645 BB01 12,136 25,931 24,54FL Big Bend 645 BB02 12,200 7,799 6,78FL Big Bend 645 XS23 (BB03, BB04)FL Big Bend 645 BB03 11,448 13,501 12,80FL Big Bend 645 BB04 8,783 4,997 3,96FL C D Mcintosh Jr 676 1 907 1,131 1,11FL C D Mcintosh Jr 676 2 1,029 1,029 14FL C D Mcintosh Jr 676 3 9,931 9,931 8,42FL C D Mcintosh Jr 676 5 0 2 FL Cane Island 7238 2 0 26 FL Cane Island 7238 **1 0 10 FL Cape Canaveral 609 PCC1 4,225 7,812 7,41FL Cape Canaveral 609 PCC2 4,963 5,814 5,52FL Combined Cycle 1 7254 32432 60 60 FL Crist 641 CS001(1, 2, 3)FL Crist 641 1 35 35 FL Crist 641 2 3 3 FL Crist 641 3 4 4 FL Crist 641 4 2,468 36,724 3,65FL Crist 641 5 2,431 33,047 5,94FL Crist 641 6 8,399 37,497 13,67FL Crist 641 7 12,526 53,830 29,80

A, 9
APPENDIX A: ACID RAIN PROGRAM - YEAR 2000 SO2 ALLOWANCE HOLDINGS AND DEDUCTIONS

STATE PLANT NAME

PLANT 

CODE STACK/UNIT ID*

2000 

ALLOWANCES 

ALLOCATED

HELD IN 

ACCOUNTS AS 

OF 3/1/2001

ALLOWANCES 

DEDUCTED

FL Crystal River 628 1 12,429 19,500 18,36FL Crystal River 628 2 14,295 20,000 18,98FL Crystal River 628 4 23,659 27,500 26,30FL Crystal River 628 5 25,257 30,000 28,56FL Cutler 610 PCU5 0 5 FL Cutler 610 PCU6 0 5 FL Debary 6046 **7 705 55 4FL Debary 6046 **8 705 60 5FL Debary 6046 **9 705 45 3FL Debary 6046 **10 705 135 11FL Deerhaven 663 B1 98 502 50FL Deerhaven 663 B2 8,271 7,918 7,91FL Deerhaven 663 CT3 0 3 FL Deerhaven 663 **NA2 0 0 FL F J Gannon 646 GB01 3,843 7,843 6,89FL F J Gannon 646 GB02 4,426 6,426 5,90FL F J Gannon 646 GB03 5,666 7,666 7,34FL F J Gannon 646 GB04 6,225 8,125 7,83FL F J Gannon 646 GB05 6,539 11,539 10,77FL F J Gannon 646 GB06 10,084 10,084 9,31FL Fort Myers 612 PFM1 3,189 4,373 4,15FL Fort Myers 612 PFM2 9,460 15,233 14,46FL Fort Myers 612 FMCT2A 0 4 FL Fort Myers 612 FMCT2B 0 4 FL G E Turner 629 2 543 0 FL G E Turner 629 3 718 0 FL G E Turner 629 4 611 0 FL Hardee Power Station 50949 CT2B 0 50 FL Henry D King 658 7 63 63 FL Henry D King 658 8 26 26 FL Higgins 630 1 423 0 FL Higgins 630 2 475 0 FL Higgins 630 3 969 0 FL Hines Facility 7302 1A 0 8 FL Hines Facility 7302 1B 0 8 FL Hookers Point 647 CS001 (HB01, HB02, HB05)FL Hookers Point 647 HB01 177 177 FL Hookers Point 647 HB02 207 207 20FL Hookers Point 647 CS002 (HB03, HB04)FL Hookers Point 647 HB03 469 408 20FL Hookers Point 647 HB04 701 401 27FL Hookers Point 647 HB05 1,253 553 33FL Hookers Point 647 HB06 478 478 30FL Indian River 55318 CS1 (1, 2)

A, 10
APPENDIX A: ACID RAIN PROGRAM - YEAR 2000 SO2 ALLOWANCE HOLDINGS AND DEDUCTIONS

STATE PLANT NAME

PLANT 

CODE STACK/UNIT ID*

2000 

ALLOWANCES 

ALLOCATED

HELD IN 

ACCOUNTS AS 

OF 3/1/2001

ALLOWANCES 

DEDUCTED

FL Indian River 55318 1 1,192 403 39FL Indian River 55318 2 1,569 2,166 2,16FL Indian River 55318 3 3,647 3,728 3,72FL Indian River 683 **C 0 1 FL Indian River 683 **D 639 6 FL Intercession City 8049 **7 705 35 2FL Intercession City 8049 **8 705 35 2FL Intercession City 8049 **9 705 25 1FL Intercession City 8049 **10 705 30 1FL Intercession City 8049 **11 0 125 9FL J D Kennedy 666 7 0 20 FL J D Kennedy 666 8 196 0 FL J D Kennedy 666 9 553 0 FL J D Kennedy 666 10 1,976 20 FL J R Kelly 664 JRK8 58 29 2FL Lansing Smith 643 1 6,478 12,673 9,20FL Lansing Smith 643 2 7,603 13,614 11,52FL Larsen Memorial 675 7 307 558 55FL Larsen Memorial 675 **8 665 188 FL Larsen Memorial 675 **9 0 0 FL Lauderdale 613 4GT1 948 8 FL Lauderdale 613 4GT2 948 8 FL Lauderdale 613 5GT1 948 8 FL Lauderdale 613 5GT2 948 8 FL Lauderdale 613 PFL4 0 0 FL Lauderdale 613 PFL5 0 0 FL Manatee 6042 PMT1 13,777 14,654 13,91FL Manatee 6042 PMT2 12,701 15,790 14,99FL Martin 6043 PMR1 5,094 8,779 8,33FL Martin 6043 PMR2 6,041 7,942 7,54FL Martin 6043 HRSG3A 1,275 8 FL Martin 6043 HRSG3B 1,275 8 FL Martin 6043 HRSG4A 1,275 8 FL Martin 6043 HRSG4B 1,275 9 FL Mulberry Cogeneration Facility 54426 1 0 4 FL Northside 667 1 6,224 10,356 7,28FL Northside 667 2 6,268 0 FL Northside 667 3 11,126 10,889 8,01FL Orange Cogeneration Facility 54365 1 0 2 FL Orange Cogeneration Facility 54365 2 0 2 FL Orlando CoGen 54466 1 0 4 FL P L Bartow 634 1 2,806 6,000 5,11FL P L Bartow 634 2 2,962 6,000 5,23FL P L Bartow 634 3 5,430 11,000 9,95

A, 11
APPENDIX A: ACID RAIN PROGRAM - YEAR 2000 SO2 ALLOWANCE HOLDINGS AND DEDUCTIONS

STATE PLANT NAME

PLANT 

CODE STACK/UNIT ID*

2000 

ALLOWANCES 

ALLOCATED

HELD IN 

ACCOUNTS AS 

OF 3/1/2001

ALLOWANCES 

DEDUCTED

FL Polk 7242 **1 0 1,011 91FL Polk 7242 **2 0 550 40FL Polk 7242 **3 0 0 FL Polk 7242 **4 0 0 FL Port Everglades 617 PPE1 2,340 3,102 2,94FL Port Everglades 617 PPE2 2,414 4,066 3,86FL Port Everglades 617 PPE3 5,882 7,785 7,39FL Port Everglades 617 PPE4 5,964 7,107 6,74FL Putnam 6246 HRSG11 1,644 6 FL Putnam 6246 HRSG12 1,644 7 FL Putnam 6246 HRSG21 1,568 6 FL Putnam 6246 HRSG22 1,568 7 FL Riviera 619 PRV2 94 0 FL Riviera 619 PRV3 3,574 7,934 7,54FL Riviera 619 PRV4 3,546 9,697 9,22FL S O Purdom 689 7 443 433 9FL S O Purdom 689 8 0 10 FL Sanford 620 PSN3 1,085 2,278 2,16FL Sanford 620 PSN4 8,615 8,682 8,24FL Sanford 620 PSN5 3,222 8,852 8,42FL Scholz 642 1 1,959 27,638 1,60FL Scholz 642 2 2,051 26,431 1,41FL Seminole 136 1 18,388 18,388 14,83FL Seminole 136 2 18,388 18,388 17,90FL Southside 668 1 930 0 FL Southside 668 2 963 0 FL Southside 668 3 227 0 FL Southside 668 4 616 1,416 95FL Southside 668 5 1,811 2,082 1,27FL St Johns River Power 207 1 11,586 14,472 11,01FL St Johns River Power 207 2 11,374 13,420 10,29FL Stanton Energy 564 1 11,294 6,910 6,57FL Stanton Energy 564 2 0 3,253 3,09FL Stock Island 6584 1 2,572 1 FL Suwannee River 638 1 254 1,600 1,35FL Suwannee River 638 2 253 1,500 1,27FL Suwannee River 638 3 649 1,700 1,49FL Tiger Bay 7699 1 0 8 FL Tom G Smith 673 S-3 9 89 6FL Tom G Smith 673 S-4 80 0 FL Turkey Point 621 PTP1 5,870 5,803 5,51FL Turkey Point 621 PTP2 5,913 5,858 5,56FL University of Florida 7345 1 0 5 FL Vero Beach Municipal 693 3 315 315 

A, 12
APPENDIX A: ACID RAIN PROGRAM - YEAR 2000 SO2 ALLOWANCE HOLDINGS AND DEDUCTIONS

STATE PLANT NAME

PLANT 

CODE STACK/UNIT ID*

2000 

ALLOWANCES 

ALLOCATED

HELD IN 

ACCOUNTS AS 

OF 3/1/2001

ALLOWANCES 

DEDUCTED

FL Vero Beach Municipal 693 4 107 107 FL Vero Beach Municipal 693 **5 317 317 GA Arkwright 699 CS001 (1, 2, 3, 4)GA Arkwright 699 1 1,449 5,811 1,23GA Arkwright 699 2 1,470 5,242 1,23GA Arkwright 699 3 1,539 10,423 1,23GA Arkwright 699 4 1,255 7,785 1,23GA Atkinson 700 A2 4 4 GA Atkinson 700 A3 6 6 GA Atkinson 700 A4 5 5 GA Atkinson 700 A1A 2 2 GA Atkinson 700 A1B 2 2 GA Baconton 55304 CT1 0 3 GA Baconton 55304 CT4 0 3 GA Baconton 55304 CT5 0 3 GA Baconton 55304 CT6 0 3 GA Bowen 703 1BLR 23,617 46,592 28,95GA Bowen 703 2BLR 24,288 35,414 35,09GA Bowen 703 3BLR 30,942 117,749 41,47GA Bowen 703 4BLR 30,934 98,345 49,83GA Doyle Generating Facility 55244 CTG-1 0 1 GA Doyle Generating Facility 55244 CTG-2 0 1 GA Doyle Generating Facility 55244 CTG-3 0 1 GA Doyle Generating Facility 55244 CTG-4 0 1 GA Doyle Generating Facility 55244 CTG-5 0 1 GA Hammond 708 CS001 (1, 2, 3)GA Hammond 708 1 3,786 19,834 3,84GA Hammond 708 2 3,975 21,306 3,84GA Hammond 708 3 3,842 20,272 3,84GA Hammond 708 4 16,232 101,111 16,74GA Harllee Branch 709 CS001 (1, 2)GA Harllee Branch 709 1 9,859 33,349 11,60GA Harllee Branch 709 2 11,661 52,722 11,60GA Harllee Branch 709 CS002 (3, 4)GA Harllee Branch 709 3 16,044 46,490 23,18GA Harllee Branch 709 4 15,921 45,176 23,18GA Hartwell Energy Facility 70454 MAG1 0 2 GA Hartwell Energy Facility 70454 MAG2 0 4 GA Jack Mcdonough 710 CS001 (MB1, MB2)GA Jack Mcdonough 710 MB1 8,584 45,622 14,12GA Jack Mcdonough 710 MB2 8,885 48,611 14,12GA Jackson County Combustion Turbine 7765 1 0 5 GA Jackson County Combustion Turbine 7765 2 0 5 GA Jackson County Combustion Turbine 7765 3 0 5 

A, 13
APPENDIX A: ACID RAIN PROGRAM - YEAR 2000 SO2 ALLOWANCE HOLDINGS AND DEDUCTIONS

STATE PLANT NAME

PLANT 

CODE STACK/UNIT ID*

2000 

ALLOWANCES 

ALLOCATED

HELD IN 

ACCOUNTS AS 

OF 3/1/2001

ALLOWANCES 

DEDUCTED

GA Jackson County Combustion Turbine 7765 4 0 5 GA Jackson County Combustion Turbine 7765 5 0 5 GA Jackson County Combustion Turbine 7765 6 0 5 GA Jackson County Combustion Turbine 7765 7 0 5 GA Jackson County Combustion Turbine 7765 8 0 5 GA Kraft 733 CS001 (1, 2, 3, 4)GA Kraft 733 1 1,530 3,936 2,23GA Kraft 733 2 1,510 3,513 1,79GA Kraft 733 3 2,964 5,591 4,41GA Kraft 733 4 436 4 GA McIntosh 6124 1 5,556 14,001 7,83GA McIntosh 6124 CT1 0 54 1GA McIntosh 6124 CT2 0 54 GA McIntosh 6124 CT3 0 54 GA McIntosh 6124 CT4 0 54 GA McIntosh 6124 CT5 0 54 GA McIntosh 6124 CT6 0 54 GA McIntosh 6124 CT7 0 54 GA McIntosh 6124 CT8 0 54 GA Mcmanus 715 CS001 (1, 2)GA Mcmanus 715 1 844 2,678 2,67GA Mcmanus 715 2 1,279 2,661 2,66GA Mid-Georgia Cogeneration 55040 1 0 25 2GA Mid-Georgia Cogeneration 55040 2 0 25 1GA Mitchell 727 3 5,463 35,688 4,92GA Monroe Power Plant 7764 1 0 10 GA Riverside 734 12 5 5 GA Robins 7348 CT1 0 30 2GA Robins 7348 CT2 0 20 1GA Scherer 6257 1 21,083 53,599 27,59GA Scherer 6257 2 21,232 44,705 25,69GA Scherer 6257 3 21,266 15,767 15,59GA Scherer 6257 4 21,242 22,412 22,40GA Sewell Creek Energy (Smarr 2) 7813 1 0 5 GA Sewell Creek Energy (Smarr 2) 7813 2 0 5 GA Sewell Creek Energy (Smarr 2) 7813 3 0 5 GA Sewell Creek Energy (Smarr 2) 7813 4 0 5 GA Smarr Energy Facility 7829 1 0 5 GA Smarr Energy Facility 7829 2 0 5 GA Sowega Power Project 7768 CT2 0 0 GA Sowega Power Project 7768 CT3 0 0 GA Wansley 6052 1 30,517 108,924 37,07GA Wansley 6052 2 28,211 102,622 32,14GA West Georgia Generating Co, LP 55267 1 0 12 

A, 14
APPENDIX A: ACID RAIN PROGRAM - YEAR 2000 SO2 ALLOWANCE HOLDINGS AND DEDUCTIONS

STATE PLANT NAME

PLANT 

CODE STACK/UNIT ID*

2000 

ALLOWANCES 

ALLOCATED

HELD IN 

ACCOUNTS AS 

OF 3/1/2001

ALLOWANCES 

DEDUCTED

GA West Georgia Generating Co, LP 55267 2 0 3 GA West Georgia Generating Co, LP 55267 3 0 12 GA West Georgia Generating Co, LP 55267 4 0 7 GA Yates 728 Y1BR 3,107 35,148 30GA Yates 728 CS001 (Y2BR, Y3BR)GA Yates 728 Y2BR 3,036 20,222 3,34GA Yates 728 Y3BR 2,998 19,832 3,34GA Yates 728 CS002 (Y4BR, Y5BR)GA Yates 728 Y4BR 3,843 25,223 4,14GA Yates 728 Y5BR 4,056 27,381 4,14GA Yates 728 Y6BR 10,678 77,524 16,27GA Yates 728 Y7BR 10,502 61,863 13,55IA Ames 1122 7 403 403 31IA Ames 1122 8 1,834 1,316 65IA Burlington (IA) 1104 1 4,499 22,314 6,37IA Council Bluffs 1082 1 1,110 1,310 1,22IA Council Bluffs 1082 2 1,651 1,951 1,89IA Council Bluffs 1082 3 15,956 18,153 17,71IA Des Moines 1083 10 163 1 IA Des Moines 1083 11 244 2 IA Des Moines 1083 **5 0 0 IA Dubuque 1046 1 1,120 2,199 2,18IA Dubuque 1046 5 305 1,454 1,44IA Dubuque 1046 6 0 2 IA Earl F Wisdom 1217 1 379 1,229 1,19IA Fair Station 1218 2 5,575 6,315 6,21IA George Neal North 1091 1 2,310 3,864 3,43IA George Neal North 1091 2 9,082 6,482 6,18IA George Neal North 1091 3 12,296 11,396 11,07IA George Neal South 7343 4 15,144 15,940 14,97IA Grinnell 7137 **2 189 0 IA Lansing 1047 CS1 (1, 2)IA Lansing 1047 1 0 35 2IA Lansing 1047 2 0 295 28IA Lansing 1047 3 478 948 93IA Lansing 1047 4 4,629 5,712 5,70IA Lime Creek 7155 **1 255 255 1IA Lime Creek 7155 **2 255 255 1IA Louisa 6664 101 15,593 15,181 14,77IA Maynard Station 1096 1 31 0 IA Milton L Kapp 1048 2 5,795 38,797 4,92IA Muscatine 1167 8 1,362 2,990 2,51IA Muscatine 1167 9 2,027 2,027 64IA Na 1 -- 7230 7230 **2 0 0 

A, 15
APPENDIX A: ACID RAIN PROGRAM - YEAR 2000 SO2 ALLOWANCE HOLDINGS AND DEDUCTIONS

STATE PLANT NAME

PLANT 

CODE STACK/UNIT ID*

2000 

ALLOWANCES 

ALLOCATED

HELD IN 

ACCOUNTS AS 

OF 3/1/2001

ALLOWANCES 

DEDUCTED

IA Ottumwa 6254 1 19,095 19,095 18,41IA Pella 1175 CS67 (6, 7)IA Pella 1175 6 757 757 26IA Pella 1175 7 978 978 26IA Pella 1175 8 68 68 IA Pleasant Hill Energy Center 7145 3 0 31 IA Prairie Creek 1073 3 725 1,000 98IA Prairie Creek 1073 4 3,434 21,429 3,07IA Riverside 1081 9 1,745 3,198 2,50IA Sixth Street 1058 1 814 7 IA Sixth Street 1058 2 177 322 31IA Sixth Street 1058 3 154 309 29IA Sixth Street 1058 4 77 309 22IA Sixth Street 1058 5 308 1,008 99IA Streeter Station 1131 7 554 754 52IA Sutherland 1077 1 199 899 89IA Sutherland 1077 2 376 696 66IA Sutherland 1077 3 2,191 3,191 3,11ID Rathdrum Combustion Turbine Project 7456 1 0 2 ID Rathdrum Combustion Turbine Project 7456 2 0 2 IL Baldwin 889 1 18,116 8,440 8,24IL Baldwin 889 2 19,154 5,533 5,33IL Baldwin 889 3 18,350 24,015 23,02IL Coffeen 861 CS0001 (01, 02)IL Coffeen 861 01 5,085 15,183 14,58IL Coffeen 861 02 15,381 25,056 24,50IL Collins 6025 CS1230 (1, 2, 3)IL Collins 6025 1 1,327 579 27IL Collins 6025 2 1,133 579 27IL Collins 6025 3 2,001 578 27IL Collins 6025 CS0405 (4, 5)IL Collins 6025 4 1,633 519 21IL Collins 6025 5 1,810 518 21IL Crawford 867 7 7,236 4,291 3,99IL Crawford 867 8 9,850 5,641 5,34IL Dallman 963 CS3132 (31, 32)IL Dallman 963 31 1,385 11,242 10,30IL Dallman 963 32 1,568 11,899 10,72IL Dallman 963 33 5,199 1,757 1,39IL Duck Creek 6016 1 11,201 11,201 11,11IL E D Edwards 856 1 2,899 16,766 16,43IL E D Edwards 856 2 6,916 18,066 16,96IL E D Edwards 856 3 9,125 23,935 23,41IL Elwood Energy Facility 55199 1 0 25 

A, 16
APPENDIX A: ACID RAIN PROGRAM - YEAR 2000 SO2 ALLOWANCE HOLDINGS AND DEDUCTIONS

STATE PLANT NAME

PLANT 

CODE STACK/UNIT ID*

2000 

ALLOWANCES 

ALLOCATED

HELD IN 

ACCOUNTS AS 

OF 3/1/2001

ALLOWANCES 

DEDUCTED

IL Elwood Energy Facility 55199 2 0 25 IL Elwood Energy Facility 55199 3 0 25 IL Elwood Energy Facility 55199 4 0 25 IL Fisk 886 19 10,032 5,148 4,84IL Freedom Power Project 7842 CT1 0 0 IL Gibson City Power Plant 55201 GCTG1 0 5 IL Gibson City Power Plant 55201 GCTG2 0 5 IL Grand Tower 862 07 248 3,483 3,01IL Grand Tower 862 08 235 3,279 2,80IL Grand Tower 862 09 2,547 8,621 7,95IL Havana 891 1 35 82 6IL Havana 891 2 45 76 6IL Havana 891 3 35 66 5IL Havana 891 4 35 95 8IL Havana 891 5 35 71 6IL Havana 891 6 35 16 IL Havana 891 7 35 35 2IL Havana 891 8 35 25 1IL Havana 891 9 8,805 11,518 10,58IL Hennepin 892 CS3 (1, 2)IL Hennepin 892 1 2,018 1,404 1,20IL Hennepin 892 2 7,940 5,030 4,52IL Hutsonville 863 05 2,591 6,913 6,30IL Hutsonville 863 06 3,238 8,163 7,52IL Indeck-Rockford Energy Center 55238 0001 0 25 IL Indeck-Rockford Energy Center 55238 0002 0 25 IL Interstate 7425 1 0 5 IL Joliet 29 384 CS7172 (71, 72)IL Joliet 29 384 71 7,580 4,580 4,33IL Joliet 29 384 72 6,177 4,634 4,33IL Joliet 29 384 CS8182 (81, 82)IL Joliet 29 384 81 7,296 5,296 5,25IL Joliet 29 384 82 7,558 5,559 5,25IL Joliet 9 874 5 8,676 4,508 4,30IL Joppa Steam 887 CS1 (1, 2)IL Joppa Steam 887 1 5,288 46,424 6,54IL Joppa Steam 887 2 4,523 36,807 1,22IL Joppa Steam 887 CS2 (3, 4)IL Joppa Steam 887 3 5,153 45,063 5,01IL Joppa Steam 887 4 4,773 40,253 2,35IL Joppa Steam 887 CS3 (5, 6)IL Joppa Steam 887 5 4,795 37,849 5,31IL Joppa Steam 887 6 4,460 33,623 2,98IL Kincaid 876 CS0102 (1, 2)

A, 17
APPENDIX A: ACID RAIN PROGRAM - YEAR 2000 SO2 ALLOWANCE HOLDINGS AND DEDUCTIONS

STATE PLANT NAME

PLANT 

CODE STACK/UNIT ID*

2000 

ALLOWANCES 

ALLOCATED

HELD IN 

ACCOUNTS AS 

OF 3/1/2001

ALLOWANCES 

DEDUCTED

IL Kincaid 876 1 13,596 8,512 8,48IL Kincaid 876 2 14,982 9,987 9,96IL Lakeside 964 CS0078 (7, 8)IL Lakeside 964 7 2,554 2,537 2,13IL Lakeside 964 8 1,446 1,437 1,19IL Lincoln Generating Facility LLC 55222 CTG-1 0 2 IL Lincoln Generating Facility LLC 55222 CTG-2 0 2 IL Lincoln Generating Facility LLC 55222 CTG-3 0 2 IL Lincoln Generating Facility LLC 55222 CTG-4 0 2 IL Lincoln Generating Facility LLC 55222 CTG-5 0 2 IL Lincoln Generating Facility LLC 55222 CTG-6 0 2 IL Lincoln Generating Facility LLC 55222 CTG-7 0 2 IL Lincoln Generating Facility LLC 55222 CTG-8 0 2 IL Marion 976 CS0001 (1, 2)IL Marion 976 1 2,080 5,480 3,03IL Marion 976 2 2,130 3,951 3,03IL Marion 976 3 2,310 7,310 4,41IL Marion 976 4 6,841 11,570 3,15IL MEPI GT Facility 7858 1 0 5 IL MEPI GT Facility 7858 2 0 5 IL MEPI GT Facility 7858 3 0 5 IL MEPI GT Facility 7858 4 0 5 IL MEPI GT Facility 7858 5 0 5 IL Meredosia 864 CS0001 (01, 02, 03, 04)IL Meredosia 864 01 298 2,682 2,23IL Meredosia 864 02 322 3,130 2,47IL Meredosia 864 03 280 2,942 2,42IL Meredosia 864 04 255 3,571 3,10IL Meredosia 864 05 5,991 12,382 11,95IL Meredosia 864 06 46 679 32IL Newton 6017 1 16,185 8,065 7,37IL Newton 6017 2 13,932 9,056 8,58IL Pinckneyville Power Plant 55202 CT01 0 0 IL Pinckneyville Power Plant 55202 CT02 0 0 IL Pinckneyville Power Plant 55202 CT03 0 0 IL Pinckneyville Power Plant 55202 CT04 0 0 IL Powerton 879 CS0506 (51, 52, 61, 62)IL Powerton 879 51 10,704 5,993 5,69IL Powerton 879 52 10,574 5,993 5,69IL Powerton 879 61 10,516 5,993 5,69IL Powerton 879 62 10,599 5,822 5,69IL R S Wallace 859 9 901 0 IL R S Wallace 859 10 2,432 0 IL Rocky Road Power, LLC 55109 T1 0 0 

A, 18
APPENDIX A: ACID RAIN PROGRAM - YEAR 2000 SO2 ALLOWANCE HOLDINGS AND DEDUCTIONS

STATE PLANT NAME

PLANT 

CODE STACK/UNIT ID*

2000 

ALLOWANCES 

ALLOCATED

HELD IN 

ACCOUNTS AS 

OF 3/1/2001

ALLOWANCES 

DEDUCTED

IL Rocky Road Power, LLC 55109 T2 0 0 IL Rocky Road Power, LLC 55109 T3 0 0 IL Rocky Road Power, LLC 55109 T4 0 0 IL Shelby Energy Center 55237 CP1 (SCE1, SCE2, SCE3, SCE4, SCE5, SCE6)IL Shelby Energy Center 55237 SCE1 0 0 IL Shelby Energy Center 55237 SCE2 0 0 IL Shelby Energy Center 55237 SCE3 0 0 IL Shelby Energy Center 55237 SCE4 0 0 IL Shelby Energy Center 55237 SCE5 0 0 IL Shelby Energy Center 55237 SCE6 0 0 IL Tilton 7760 1 0 0 IL Tilton 7760 2 0 0 IL Tilton 7760 3 0 0 IL Tilton 7760 4 0 0 IL Venice 913 1 5 5 IL Venice 913 2 2 2 IL Venice 913 3 17 7 IL Venice 913 4 14 4 IL Venice 913 5 10 10 IL Venice 913 6 10 10 IL Venice 913 7 2 12 IL Venice 913 8 2 12 IL Vermilion 897 CS3 (1, 2)IL Vermilion 897 1 2,835 6,167 5,72IL Vermilion 897 2 3,831 7,712 7,28IL Waukegan 883 7 8,214 7,161 6,88IL Waukegan 883 8 7,840 8,881 8,54IL Waukegan 883 17 3,104 2,328 2,22IL Will County 884 1 5,322 2,492 2,30IL Will County 884 2 4,850 2,648 2,34IL Will County 884 3 6,995 5,247 5,09IL Will County 884 4 13,804 6,781 6,48IL Wood River 898 CS1 (1, 2, 3)IL Wood River 898 1 3 6 IL Wood River 898 2 3 3 IL Wood River 898 3 3 3 IL Wood River 898 4 2,259 3,077 2,89IL Wood River 898 5 9,481 11,543 10,67IN A B Brown 6137 1 5,358 5,358 4,58IN A B Brown 6137 2 4,530 4,530 2,27IN A B Brown 6137 3 639 639 IN Anderson 7336 ACT1 0 5 IN Anderson 7336 ACT2 0 5 IN Bailly 995 XS12 (7, 8)

A, 19
APPENDIX A: ACID RAIN PROGRAM - YEAR 2000 SO2 ALLOWANCE HOLDINGS AND DEDUCTIONS

STATE PLANT NAME

PLANT 

CODE STACK/UNIT ID*

2000 

ALLOWANCES 

ALLOCATED

HELD IN 

ACCOUNTS AS 

OF 3/1/2001

ALLOWANCES 

DEDUCTED

IN Bailly 995 7 4,812 3,133 2,78IN Bailly 995 8 6,871 9,585 2,35IN Breed 984 1 7,977 17,889 IN Cayuga 1001 1 14,390 38,812 34,97IN Cayuga 1001 2 14,715 34,313 30,75IN Cayuga 1001 4 0 15 IN Clifty Creek 983 CS001 (1, 2, 3)IN Clifty Creek 983 1 8,465 7,754 7,25IN Clifty Creek 983 2 8,324 7,754 7,25IN Clifty Creek 983 3 8,573 7,754 7,25IN Clifty Creek 983 CS002 (4, 5, 6)IN Clifty Creek 983 4 8,434 7,473 6,97IN Clifty Creek 983 5 8,132 7,473 6,97IN Clifty Creek 983 6 8,560 7,473 6,97IN Dean H Mitchell 996 CS45 (4, 5)IN Dean H Mitchell 996 4 3,116 889 76IN Dean H Mitchell 996 5 3,018 2,072 1,69IN Dean H Mitchell 996 CS611 (6, 11)IN Dean H Mitchell 996 6 2,970 2,009 1,96IN Dean H Mitchell 996 11 2,658 2,358 1,94IN Edwardsport 1004 6-1 0 29 1IN Edwardsport 1004 7-1 347 4,281 3,96IN Edwardsport 1004 7-2 354 4,005 3,67IN Edwardsport 1004 8-1 375 3,475 3,14IN Elmer W Stout 990 1 0 0 IN Elmer W Stout 990 2 0 0 IN Elmer W Stout 990 3 0 0 IN Elmer W Stout 990 4 0 0 IN Elmer W Stout 990 5 0 0 IN Elmer W Stout 990 6 0 0 IN Elmer W Stout 990 7 0 0 IN Elmer W Stout 990 8 0 0 IN Elmer W Stout 990 9 1 51 IN Elmer W Stout 990 10 2 52 IN Elmer W Stout 990 50 1,674 8,040 7,77IN Elmer W Stout 990 60 2,058 7,849 7,61IN Elmer W Stout 990 70 10,180 25,679 24,90IN Elmer W Stout 990 GT4 0 50 IN Elmer W Stout 990 GT5 0 50 IN F B Culley 1012 1 827 2,227 2,14IN F B Culley 1012 XS23 (2, 3)IN F B Culley 1012 2 1,759 9,872 9,59IN F B Culley 1012 3 7,318 36,724 IN Frank E Ratts 1043 1SG1 3,593 11,715 11,19

A, 20
APPENDIX A: ACID RAIN PROGRAM - YEAR 2000 SO2 ALLOWANCE HOLDINGS AND DEDUCTIONS

STATE PLANT NAME

PLANT 

CODE STACK/UNIT ID*

2000 

ALLOWANCES 

ALLOCATED

HELD IN 

ACCOUNTS AS 

OF 3/1/2001

ALLOWANCES 

DEDUCTED

IN Frank E Ratts 1043 2SG1 3,660 13,534 11,85IN Georgetown 7759 GT1 0 0 IN Georgetown 7759 GT2 0 0 IN Georgetown 7759 GT3 0 0 IN Gibson 6113 CS0003 (1, 2)IN Gibson 6113 1 17,420 72,443 50,62IN Gibson 6113 2 17,683 66,582 44,02IN Gibson 6113 XS34 (3, 4)IN Gibson 6113 3 17,714 67,512 28,07IN Gibson 6113 4 17,389 183,311 28,07IN Gibson 6113 5 18,187 26,576 20,70IN H T Pritchard 991 1 0 31 IN H T Pritchard 991 2 1 141 IN H T Pritchard 991 CS592 (3, 4)IN H T Pritchard 991 3 240 3,457 3,34IN H T Pritchard 991 4 533 3,883 3,71IN H T Pritchard 991 CS596 (5, 6)IN H T Pritchard 991 5 596 3,728 3,61IN H T Pritchard 991 6 2,488 7,200 6,98IN Merom 6213 1SG1 14,925 8,325 7,53IN Merom 6213 2SG1 14,823 9,817 9,28IN Michigan City 997 4 909 0 IN Michigan City 997 5 1,010 0 IN Michigan City 997 6 1,019 0 IN Michigan City 997 12 10,052 24,694 11,29IN Mirant State Line Energy, LLC (IN) 981 3 4,726 3,920 3,89IN Mirant State Line Energy, LLC (IN) 981 4 6,924 5,124 5,09IN Na 1 -- 7221 7221 **1 0 0 IN Na 1 -- 7221 7221 **3 0 0 IN Na 1 -- 7221 7221 **4 0 0 IN Na 1 -- 7228 7228 **2 0 0 IN Na 1 -- 7228 7228 **3 0 0 IN Noblesville 1007 1 66 2,357 2,31IN Noblesville 1007 2 54 2,332 2,29IN Noblesville 1007 3 40 2,292 2,26IN Perry K Steam Plant 992 11 432 32 1IN Petersburg 994 1 7,088 1,719 1,63IN Petersburg 994 2 13,965 3,240 3,12IN Petersburg 994 3 16,886 20,939 20,32IN Petersburg 994 4 16,155 17,485 16,97IN R Gallagher 1008 CS0001 (1, 2)IN R Gallagher 1008 1 2,909 16,857 15,37IN R Gallagher 1008 2 3,138 15,880 14,68IN R Gallagher 1008 CS0002 (3, 4)

A, 21
APPENDIX A: ACID RAIN PROGRAM - YEAR 2000 SO2 ALLOWANCE HOLDINGS AND DEDUCTIONS

STATE PLANT NAME

PLANT 

CODE STACK/UNIT ID*

2000 

ALLOWANCES 

ALLOCATED

HELD IN 

ACCOUNTS AS 

OF 3/1/2001

ALLOWANCES 

DEDUCTED

IN R Gallagher 1008 3 2,815 16,425 14,90IN R Gallagher 1008 4 2,933 15,511 14,04IN R M Schahfer 6085 14 10,357 11,403 11,31IN R M Schahfer 6085 15 10,693 13,370 13,28IN R M Schahfer 6085 17 5,224 6,185 5,62IN R M Schahfer 6085 18 5,189 4,939 4,70IN Richmond (IN) 7335 RCT1 0 19 IN Richmond (IN) 7335 RCT2 0 5 IN Rockport 6166 CS012 (MB1, MB2)IN Rockport 6166 MB1 33,003 42,462 32,94IN Rockport 6166 MB2 33,003 33,003 30,44IN Tanners Creek 988 CS013 (U1, U2, U3)IN Tanners Creek 988 U1 2,776 4,945 4,80IN Tanners Creek 988 U2 2,798 5,234 5,08IN Tanners Creek 988 U3 4,080 6,854 6,65IN Tanners Creek 988 U4 10,705 118,159 50,91IN Vermillion Generating Station 55111 1 0 4 IN Vermillion Generating Station 55111 2 0 4 IN Vermillion Generating Station 55111 3 0 4 IN Vermillion Generating Station 55111 4 0 4 IN Vermillion Generating Station 55111 5 0 4 IN Vermillion Generating Station 55111 6 0 4 IN Vermillion Generating Station 55111 7 0 4 IN Vermillion Generating Station 55111 8 0 4 IN Wabash River 1010 1 1,723 17,223 65IN Wabash River 1010 CS0005 (2, 3, 4, 5, 6)IN Wabash River 1010 2 1,392 7,151 6,53IN Wabash River 1010 3 1,616 12,078 7,57IN Wabash River 1010 4 1,532 6,723 6,09IN Wabash River 1010 5 1,582 9,662 8,85IN Wabash River 1010 6 5,295 30,947 28,75IN Warrick 6705 1 30,372 20,606 20,58IN Warrick 6705 2 30,732 29,037 20,06IN Warrick 6705 3 27,668 19,201 19,14IN Warrick 6705 4 10,509 32,487 31,59IN Warrick 6705 XS123 (1, 2, 3)IN Whitewater Valley 1040 CS12 (1, 2)IN Whitewater Valley 1040 1 2,237 2,237 2,22IN Whitewater Valley 1040 2 6,695 9,895 9,84KS Arthur Mullergren 1235 3 1 1 KS Cimarron River 1230 1 12 12 KS Coffeyville 1271 4 11 11 KS East 12Th St 7013 4 10 10 KS Garden City 1336 S-2 0 10 

A, 22
APPENDIX A: ACID RAIN PROGRAM - YEAR 2000 SO2 ALLOWANCE HOLDINGS AND DEDUCTIONS

STATE PLANT NAME

PLANT 

CODE STACK/UNIT ID*

2000 

ALLOWANCES 

ALLOCATED

HELD IN 

ACCOUNTS AS 

OF 3/1/2001

ALLOWANCES 

DEDUCTED

KS Gordon Evans 1240 1 64 244 22KS Gordon Evans 1240 2 25 418 37KS Gordon Evans 1240 E1CT 0 10 KS Gordon Evans 1240 E2CT 0 10 KS Holcomb 108 SGU1 4,011 2,501 2,09KS Hutchinson 1248 CP001(1,2,3)KS Hutchinson 1248 1 0 0 KS Hutchinson 1248 2 0 0 KS Hutchinson 1248 3 0 0 KS Hutchinson 1248 4 18 1,098 99KS Jeffrey Energy Centr 6068 1 17,113 18,774 18,18KS Jeffrey Energy Centr 6068 2 18,087 20,383 19,77KS Jeffrey Energy Centr 6068 3 20,635 21,235 20,54KS Judson Large 1233 4 39 39 KS Kaw 1294 1 787 2 KS Kaw 1294 2 619 0 KS Kaw 1294 3 516 2 KS La Cygne 1241 1 17,946 11,431 9,69KS La Cygne 1241 2 15,061 21,161 20,98KS Lawrence 1250 2 2 2 KS Lawrence 1250 3 2,148 2,148 1,48KS Lawrence 1250 4 1,819 539 21KS Lawrence 1250 5 5,377 1,677 1,26KS Mcpherson 2 1305 1 1 76 KS McPherson 3 7515 1 0 40 KS Murray Gill 1242 1 1 1 KS Murray Gill 1242 2 5 5 KS Murray Gill 1242 3 50 430 38KS Murray Gill 1242 4 62 1,262 1,16KS Nearman Creek 6064 N1 6,930 8,987 7,59KS Neosho 1243 7 13 33 1KS Quindaro 1295 1 2,032 2,032 1,03KS Quindaro 1295 2 2,079 7,486 2,13KS Ripley 1244 **2 0 0 KS Ripley 1244 **3 0 0 KS Riverton 1239 39 1,039 2,539 1,79KS Riverton 1239 40 1,764 1,264 89KS Tecumseh 1252 9 2,256 2,036 1,78KS Tecumseh 1252 10 3,916 3,916 3,62KS Wamego 1328 7 0 0 KY Big Sandy 1353 CS012 (BSU1, BSU2)KY Big Sandy 1353 BSU1 6,430 20,271 13,98KY Big Sandy 1353 BSU2 19,718 47,911 37,83KY Cane Run 1363 3 39 0 

A, 23
APPENDIX A: ACID RAIN PROGRAM - YEAR 2000 SO2 ALLOWANCE HOLDINGS AND DEDUCTIONS

STATE PLANT NAME

PLANT 

CODE STACK/UNIT ID*

2000 

ALLOWANCES 

ALLOCATED

HELD IN 

ACCOUNTS AS 

OF 3/1/2001

ALLOWANCES 

DEDUCTED

KY Cane Run 1363 4 4,522 6,958 6,24KY Cane Run 1363 5 4,341 5,341 5,32KY Cane Run 1363 6 5,500 6,103 5,86KY Cane Run 1363 **12 0 0 KY Cane Run 1363 **13 0 0 KY Coleman 1381 C1 4,854 16,210 15,48KY Coleman 1381 C2 5,536 15,268 14,36KY Coleman 1381 C3 5,324 16,266 15,35KY Cooper 1384 CS1 (1, 2)KY Cooper 1384 1 3,210 9,124 5,97KY Cooper 1384 2 6,608 20,595 12,12KY D B Wilson 6823 W1 12,465 10,965 10,10KY Dale 1385 CS2 (3, 4)KY Dale 1385 3 1,984 3,184 3,14KY Dale 1385 4 1,847 3,247 3,14KY E W Brown 1355 1 3,066 18,432 7,86KY E W Brown 1355 CS003 (2, 3)KY E W Brown 1355 2 5,807 28,632 10,85KY E W Brown 1355 3 11,254 71,257 31,63KY E W Brown 1355 6 0 100 1KY E W Brown 1355 7 0 100 1KY E W Brown 1355 8 0 100 KY E W Brown 1355 9 0 100 KY E W Brown 1355 10 0 100 KY E W Brown 1355 11 0 100 KY East Bend 6018 2 18,322 25,898 14,85KY Elmer Smith 1374 XS12 (1, 2)KY Elmer Smith 1374 1 2,805 8,330 2,05KY Elmer Smith 1374 2 6,213 18,464 4,79KY Ghent 1356 1 12,252 103,708 4,10KY Ghent 1356 2 12,737 17,737 17,24KY Ghent 1356 CS002 (3, 4)KY Ghent 1356 3 13,960 19,960 18,81KY Ghent 1356 4 13,717 19,717 19,02KY Green River 1357 XS123 (1, 2, 3)KY Green River 1357 1 130 130 12KY Green River 1357 2 851 851 17KY Green River 1357 3 744 744 22KY Green River 1357 4 2,826 12,826 9,98KY Green River 1357 5 3,372 14,229 12,85KY H L Spurlock 6041 1 9,824 40,954 16,30KY H L Spurlock 6041 2 16,591 25,618 22,35KY Henderson I 1372 6 810 810 69KY Hmp&L Station 2 1382 H1 5,758 11,746 2,79

A, 24
APPENDIX A: ACID RAIN PROGRAM - YEAR 2000 SO2 ALLOWANCE HOLDINGS AND DEDUCTIONS

STATE PLANT NAME

PLANT 

CODE STACK/UNIT ID*

2000 

ALLOWANCES 

ALLOCATED

HELD IN 

ACCOUNTS AS 

OF 3/1/2001

ALLOWANCES 

DEDUCTED

KY Hmp&L Station 2 1382 H2 5,936 9,289 3,10KY J K Smith 54 SCT1 0 10 KY J K Smith 54 SCT2 0 10 KY J K Smith 54 SCT3 0 10 KY Mill Creek 1364 1 8,082 8,082 7,67KY Mill Creek 1364 2 8,142 10,142 9,84KY Mill Creek 1364 3 10,982 9,982 8,80KY Mill Creek 1364 4 13,622 8,622 8,17KY Na 1 -- 7220 7220 **3 0 0 KY Na 1 -- 7220 7220 **4 0 0 KY Na 1 -- 7220 7220 **5 0 0 KY Paradise 1378 1 10,821 20,321 17,73KY Paradise 1378 2 12,304 24,804 24,38KY Paradise 1378 3 25,513 183,941 102,92KY Pineville 1360 3 914 2,914 1,44KY R D Green 6639 G1 5,294 2,617 1,83KY R D Green 6639 G2 6,378 2,616 1,54KY Robert Reid 1383 R1 942 8,942 7,43KY Shawnee 1379 CSSH15 (1, 2, 3, 4, 5)KY Shawnee 1379 1 3,644 4,144 3,49KY Shawnee 1379 2 3,673 4,173 3,32KY Shawnee 1379 3 3,708 4,708 4,02KY Shawnee 1379 4 3,594 4,094 3,67KY Shawnee 1379 5 3,826 4,326 3,89KY Shawnee 1379 CSSH60 (6, 7, 8, 9, 10)KY Shawnee 1379 6 3,712 3,712 2,60KY Shawnee 1379 7 3,640 4,640 3,79KY Shawnee 1379 8 3,571 4,571 3,87KY Shawnee 1379 9 3,666 4,166 3,40KY Shawnee 1379 10 4,895 4,992 1,99KY Trimble County 6071 1 9,634 9,969 7,58KY Tyrone 1361 1 0 0 KY Tyrone 1361 2 0 0 KY Tyrone 1361 3 0 0 KY Tyrone 1361 4 0 0 KY Tyrone 1361 5 1,713 3,713 2,60LA A B Paterson 1407 3 7 2 LA A B Paterson 1407 4 8 2 LA Arsenal Hill 1416 5A 30 30 LA Big Cajun 1 1464 1B1 27 27 LA Big Cajun 1 1464 1B2 27 27 LA Big Cajun 2 6055 2B1 14,868 16,079 16,06LA Big Cajun 2 6055 2B2 14,640 17,036 17,02LA Big Cajun 2 6055 2B3 14,657 17,304 17,28

A, 25
APPENDIX A: ACID RAIN PROGRAM - YEAR 2000 SO2 ALLOWANCE HOLDINGS AND DEDUCTIONS

STATE PLANT NAME

PLANT 

CODE STACK/UNIT ID*

2000 

ALLOWANCES 

ALLOCATED

HELD IN 

ACCOUNTS AS 

OF 3/1/2001

ALLOWANCES 

DEDUCTED

LA Calcasieu Power, LLC 55165 GTG1 0 0 LA D G Hunter 6558 3 0 0 LA D G Hunter 6558 4 32 32 1LA Doc Bonin 1443 1 12 12 LA Doc Bonin 1443 2 24 24 LA Doc Bonin 1443 3 45 45 LA Dolet Hills 51 1 20,501 20,501 19,51LA Evangeline (Coughlin) 1396 6 46 0 LA Evangeline (Coughlin) 1396 7 128 0 LA Evangeline (Coughlin) 1396 6-1 0 46 LA Evangeline (Coughlin) 1396 7-1 0 64 LA Evangeline (Coughlin) 1396 7-2 0 64 LA Houma 1439 15 10 10 LA Houma 1439 16 14 14 LA Lieberman 1417 3 86 111 10LA Lieberman 1417 4 72 47 LA Little Gypsy 1402 1 245 245 LA Little Gypsy 1402 2 378 378 1LA Little Gypsy 1402 3 543 543 LA Louisiana 1 1391 1A 116 6 LA Louisiana 1 1391 2A 2 7 LA Louisiana 1 1391 3A 2 7 LA Louisiana 1 1391 4A 0 36 1LA Louisiana 1 1391 5A 0 33 1LA Louisiana 2 1392 10 0 2 LA Louisiana 2 1392 11 0 2 LA Louisiana 2 1392 12 0 2 LA Michoud 1409 1 71 3 LA Michoud 1409 2 106 5 LA Michoud 1409 3 491 2,321 2,25LA Monroe 1448 11 13 13 LA Monroe 1448 12 45 45 LA Morgan City 1449 4 5 5 LA Natchitoches 1450 10 0 1 LA Ninemile Point 1403 1 62 62 LA Ninemile Point 1403 2 112 112 LA Ninemile Point 1403 3 96 96 LA Ninemile Point 1403 4 691 691 16LA Ninemile Point 1403 5 930 930 1LA Opelousas 1454 10 1 1 LA R S Nelson 1393 3 39 4 LA R S Nelson 1393 4 123 8 LA R S Nelson 1393 6 19,569 20,834 20,42LA Rodemacher 6190 1 3,249 3,249 13

A, 26
APPENDIX A: ACID RAIN PROGRAM - YEAR 2000 SO2 ALLOWANCE HOLDINGS AND DEDUCTIONS

STATE PLANT NAME

PLANT 

CODE STACK/UNIT ID*

2000 

ALLOWANCES 

ALLOCATED

HELD IN 

ACCOUNTS AS 

OF 3/1/2001

ALLOWANCES 

DEDUCTED

LA Rodemacher 6190 2 18,909 18,909 14,70LA Ruston 1458 2 4 4 LA Ruston 1458 3 5 5 LA Sterlington 1404 10 174 174 LA Sterlington 1404 7C 0 15 LA Sterlington 1404 7AB 72 57 LA Teche 1400 2 27 27 LA Teche 1400 3 446 446 5LA Waterford 1 & 2 8056 1 4,554 4,554 1,18LA Waterford 1 & 2 8056 2 3,535 3,535 62LA Willow Glen 1394 1 99 4 LA Willow Glen 1394 2 26 6 LA Willow Glen 1394 3 93 8 LA Willow Glen 1394 4 291 11 LA Willow Glen 1394 5 458 746 70MA Berkshire Power 55041 1 0 10 MA Brayton Point 1619 1 8,481 10,873 9,37MA Brayton Point 1619 2 8,911 10,532 9,07MA Brayton Point 1619 3 18,625 22,505 21,42MA Brayton Point 1619 4 12,139 4,959 4,71MA Canal 1599 1 13,235 13,235 12,47MA Canal 1599 2 17,999 12,999 11,37MA Cannon Street 1616 3 374 374 MA Cleary Flood 1682 8 143 158 13MA Cleary Flood 1682 9 2,679 2,664 14MA Dighton 55026 1 0 34 MA Kendall Square 1595 CS12 (1, 2)MA Kendall Square 1595 1 199 199 4MA Kendall Square 1595 2 208 208 4MA Kendall Square 1595 3 421 421 9MA Millennium Power Partners, L.P. 55079 1 0 5 MA Mount Tom 1606 1 6,347 12,440 7,37MA Mystic 1588 4 2,607 1,607 1,10MA Mystic 1588 5 3,092 2,092 1,11MA Mystic 1588 6 3,076 2,076 1,01MA Mystic 1588 7 17,244 7,604 6,14MA New Boston 1589 1 6,158 58 MA New Boston 1589 2 6,324 64 MA Salem Harbor 1626 1 3,339 3,753 3,57MA Salem Harbor 1626 2 3,408 4,072 3,87MA Salem Harbor 1626 3 5,461 5,885 5,60MA Salem Harbor 1626 4 12,571 7,834 7,45MA Somerset 1613 1 0 0 MA Somerset 1613 2 0 0 

A, 27
APPENDIX A: ACID RAIN PROGRAM - YEAR 2000 SO2 ALLOWANCE HOLDINGS AND DEDUCTIONS

STATE PLANT NAME

PLANT 

CODE STACK/UNIT ID*

2000 

ALLOWANCES 

ALLOCATED

HELD IN 

ACCOUNTS AS 

OF 3/1/2001

ALLOWANCES 

DEDUCTED

MA Somerset 1613 3 0 0 MA Somerset 1613 4 0 0 MA Somerset 1613 5 0 0 MA Somerset 1613 6 0 0 MA Somerset 1613 7 2,765 1,715 MA Somerset 1613 8 3,985 5,035 5,02MA West Springfield 1642 1 378 352 MA West Springfield 1642 2 356 331 MA West Springfield 1642 3 3,012 2,803 84MD Brandon Shores 602 1 18,510 32,099 28,46MD Brandon Shores 602 2 7,795 27,834 21,23MD C P Crane 1552 1 4,349 24,129 15,63MD C P Crane 1552 2 4,043 16,705 15,04MD Chalk Point 1571 CSE12 (1, 2)MD Chalk Point 1571 1 9,202 19,202 17,25MD Chalk Point 1571 2 10,219 17,219 15,34MD Chalk Point 1571 3 12,610 12,503 1,64MD Chalk Point 1571 4 3,557 2,600 1,21MD Chalk Point 1571 **GT3 707 707 MD Chalk Point 1571 **GT4 707 707 MD Chalk Point 1571 **GT5 894 894 1MD Chalk Point 1571 **GT6 894 894 MD Dickerson 1572 XS123 (1, 2, 3)MD Dickerson 1572 1 5,848 8,848 8,14MD Dickerson 1572 2 5,500 13,500 11,76MD Dickerson 1572 3 5,846 10,846 9,30MD Dickerson 1572 CW1 0 0 MD Dickerson 1572 GT2 1,082 1,082 MD Dickerson 1572 GT3 1,082 1,082 MD Dickerson 1572 HCT3 0 0 MD Dickerson 1572 HCT4 0 0 MD Easton 2 4257 **25 0 0 MD Easton 2 4257 **26 0 0 MD Easton 2 4257 **27 0 0 MD Gould Street 1553 3 821 814 58MD Herbert A Wagner 1554 1 1,291 1,418 81MD Herbert A Wagner 1554 2 1,299 7,316 5,61MD Herbert A Wagner 1554 3 8,381 17,858 14,93MD Herbert A Wagner 1554 4 1,520 2,800 2,24MD Morgantown 1573 1 16,932 43,263 37,89MD Morgantown 1573 2 16,189 43,189 37,72MD Nanticoke 4207 **ST1 0 0 MD Panda Brandywine 54832 1 0 1 MD Panda Brandywine 54832 2 0 1 

A, 28
APPENDIX A: ACID RAIN PROGRAM - YEAR 2000 SO2 ALLOWANCE HOLDINGS AND DEDUCTIONS

STATE PLANT NAME

PLANT 

CODE STACK/UNIT ID*

2000 

ALLOWANCES 

ALLOCATED

HELD IN 

ACCOUNTS AS 

OF 3/1/2001

ALLOWANCES 

DEDUCTED

MD Perryman 1556 **51 0 2,401 13MD Perryman 1556 **52 0 0 MD Perryman 1556 **61 0 0 MD Perryman 1556 **62 0 0 MD R P Smith 1570 9 634 722 48MD R P Smith 1570 11 2,314 4,117 4,01MD Riverside 1559 1 189 0 MD Riverside 1559 2 171 0 MD Riverside 1559 3 354 0 MD Riverside 1559 4 455 4 MD Riverside 1559 5 294 0 MD Vienna 1564 8 3,645 3,645 3,31MD Westport 1560 3 186 0 MD Westport 1560 4 258 0 ME Androscoggin Cogeneration Center 55031 CT01 0 2 ME Androscoggin Cogeneration Center 55031 CT02 0 2 ME Androscoggin Cogeneration Center 55031 CT03 0 2 ME Graham Station 1470 5 344 3 ME Maine Independence Station 55068 1 0 10 ME Maine Independence Station 55068 2 0 10 ME Mason Steam 1496 3 2 8 ME Mason Steam 1496 4 1 7 ME Mason Steam 1496 5 1 9 ME Rumford Power Associates 55100 1 0 33 ME William F Wyman 1507 1 1,159 1,159 89ME William F Wyman 1507 2 1,161 1,161 87ME William F Wyman 1507 3 2,946 5,018 4,12ME William F Wyman 1507 4 6,274 6,274 4,67MI 48th Street Peaking Station 7258 9 0 10 MI 48th Street Peaking Station 7258 **7 298 88 MI 48th Street Peaking Station 7258 **8 298 98 MI B C Cobb 1695 1 1,142 63,186 MI B C Cobb 1695 2 1,229 2,022 MI B C Cobb 1695 3 1,223 1,223 MI B C Cobb 1695 4 4,573 9,950 8,29MI B C Cobb 1695 5 4,695 9,349 7,79MI Belle River 6034 1 18,505 18,505 15,17MI Belle River 6034 2 18,769 18,769 14,17MI Belle River 6034 CTG121 0 5 MI Belle River 6034 CTG122 0 5 MI Belle River 6034 CTG131 0 5 MI Conners Creek 1726 15 4,285 171 MI Conners Creek 1726 16 4,279 981 MI Conners Creek 1726 17 4,034 4,034 

A, 29
APPENDIX A: ACID RAIN PROGRAM - YEAR 2000 SO2 ALLOWANCE HOLDINGS AND DEDUCTIONS

STATE PLANT NAME

PLANT 

CODE STACK/UNIT ID*

2000 

ALLOWANCES 

ALLOCATED

HELD IN 

ACCOUNTS AS 

OF 3/1/2001

ALLOWANCES 

DEDUCTED

MI Conners Creek 1726 18 3,353 3,353 MI Dan E Karn 1702 1 8,388 12,737 8,61MI Dan E Karn 1702 2 8,567 13,097 8,91MI Dan E Karn 1702 CS0009 (3, 4)MI Dan E Karn 1702 3 1,020 3,912 3,25MI Dan E Karn 1702 4 948 3,468 2,89MI Dearborn Industrial Generation 55088 GTP1 0 0 MI Delray 1728 7 0 0 MI Delray 1728 8 12 12 MI Delray 1728 9 0 0 MI Delray 1728 10 14 14 MI Delray 1728 11 0 0 MI Delray 1728 12 14 14 MI Delray 1728 CTG111 0 5 MI Delray 1728 CTG121 0 5 MI Eckert Station 1831 1 1,298 1,298 77MI Eckert Station 1831 2 1,354 1,354 72MI Eckert Station 1831 3 1,327 1,327 57MI Eckert Station 1831 4 2,223 2,223 1,77MI Eckert Station 1831 5 2,666 2,666 1,83MI Eckert Station 1831 6 2,343 2,343 98MI Endicott Generating 4259 1 1,810 1,810 75MI Erickson 1832 1 6,646 6,646 6,50MI Greenwood 6035 1 539 1,696 1,15MI Greenwood 6035 CTG111 0 5 MI Greenwood 6035 CTG112 0 5 MI Greenwood 6035 CTG121 0 5 MI Harbor Beach 1731 1 3,520 3,520 2,24MI J B Sims 1825 3 1,484 1,484 62MI J C Weadock 1720 CS0009 (7, 8)MI J C Weadock 1720 7 4,745 5,885 4,90MI J C Weadock 1720 8 4,691 5,653 4,71MI J H Campbell 1710 CS0009 (1, 2)MI J H Campbell 1710 1 8,098 15,521 9,21MI J H Campbell 1710 2 9,685 16,986 10,82MI J H Campbell 1710 3 27,805 23,949 20,72MI J R Whiting 1723 1 3,412 3,797 3,34MI J R Whiting 1723 2 3,842 4,253 2,85MI J R Whiting 1723 3 4,919 5,413 4,16MI James De Young 1830 5 1,048 1,448 1,43MI Kalamazoo River Generating Station 55101 1 0 0 MI Livingston Generating Station 55102 1 0 0 MI Livingston Generating Station 55102 2 0 0 MI Livingston Generating Station 55102 3 0 0 

A, 30
APPENDIX A: ACID RAIN PROGRAM - YEAR 2000 SO2 ALLOWANCE HOLDINGS AND DEDUCTIONS

STATE PLANT NAME

PLANT 

CODE STACK/UNIT ID*

2000 

ALLOWANCES 

ALLOCATED

HELD IN 

ACCOUNTS AS 

OF 3/1/2001

ALLOWANCES 

DEDUCTED

MI Livingston Generating Station 55102 4 0 0 MI Marysville 1732 CS0001 (9, 10)MI Marysville 1732 9 1,637 1,637 31MI Marysville 1732 10 1,261 1,261 45MI Marysville 1732 CS0002 (11, 12)MI Marysville 1732 11 1,315 1,315 31MI Marysville 1732 12 1,061 1,061 39MI Michigan Power Limited Partnership 54915 1 0 4 MI Mistersky 1822 5 257 257 MI Mistersky 1822 6 437 437 MI Mistersky 1822 7 485 485 MI Monroe 1733 CS0012 (1, 2)MI Monroe 1733 1 23,669 32,630 28,54MI Monroe 1733 2 24,307 44,013 29,70MI Monroe 1733 CS0034 (3, 4)MI Monroe 1733 3 22,771 49,164 26,39MI Monroe 1733 4 24,617 45,334 22,89MI Presque Isle 1769 CS4 (1, 2, 3, 4)MI Presque Isle 1769 2 637 637 31MI Presque Isle 1769 3 1,907 2,711 2,51MI Presque Isle 1769 4 1,677 2,549 2,36MI Presque Isle 1769 5 2,934 4,619 4,19MI Presque Isle 1769 6 2,941 4,086 3,71MI Presque Isle 1769 7 2,216 1,770 1,70MI Presque Isle 1769 8 2,192 2,302 2,09MI Presque Isle 1769 9 2,346 2,138 1,94MI River Rouge 1740 1 79 4 MI River Rouge 1740 2 6,323 6,323 5,93MI River Rouge 1740 3 9,103 9,103 6,54MI Shiras 1843 3 500 500 35MI St Clair 1743 1 3,666 5,756 5,75MI St Clair 1743 2 3,543 5,567 5,13MI St Clair 1743 3 3,525 4,473 4,47MI St Clair 1743 4 3,396 5,596 5,59MI St Clair 1743 5 0 0 MI St Clair 1743 6 7,342 7,452 7,45MI St Clair 1743 7 13,459 21,912 21,91MI Trenton Channel 1745 CS0006 (16, 17, 18, 19)MI Trenton Channel 1745 16 3,292 3,357 3,35MI Trenton Channel 1745 17 767 3,222 3,22MI Trenton Channel 1745 18 3,563 3,563 2,62MI Trenton Channel 1745 19 698 2,875 2,87MI Trenton Channel 1745 9A 14,507 15,684 15,68MI Wyandotte 1866 5 960 151 

A, 31
APPENDIX A: ACID RAIN PROGRAM - YEAR 2000 SO2 ALLOWANCE HOLDINGS AND DEDUCTIONS

STATE PLANT NAME

PLANT 

CODE STACK/UNIT ID*

2000 

ALLOWANCES 

ALLOCATED

HELD IN 

ACCOUNTS AS 

OF 3/1/2001

ALLOWANCES 

DEDUCTED

MI Wyandotte 1866 7 953 1,525 1,52MI Wyandotte 1866 8 0 237 23MN Allen S King 1915 1 15,628 30,399 27,25MN Black Dog 1904 CS1 (1, 2, 3, 4)MN Black Dog 1904 1 1,914 1,914 1MN Black Dog 1904 2 3,683 3,683 1MN Black Dog 1904 3 2,275 2,275 1,07MN Black Dog 1904 4 4,056 4,056 2,35MN Clay Boswell 1893 CS0003 (1, 2, 3)MN Clay Boswell 1893 1 1,827 1,827 1,82MN Clay Boswell 1893 2 1,800 1,800 1,80MN Clay Boswell 1893 3 9,866 8,753 8,74MN Clay Boswell 1893 4 10,324 3,311 2,77MN Cottage Grove 55010 01 0 5 MN Fox Lake 1888 3 2,069 2,069 MN High Bridge 1912 CS0001 (3, 4, 5, 6)MN High Bridge 1912 3 2,118 5,314 25MN High Bridge 1912 4 1,458 3,059 27MN High Bridge 1912 5 2,194 3,062 1,09MN High Bridge 1912 6 1,852 9,546 1,84MN Hoot Lake 1943 2 1,242 1,850 1,20MN Hoot Lake 1943 3 1,978 1,978 1,43MN Hutchinson Utils Comm - Plant 2 6358 1 0 1 MN M L Hibbard 1897 CS0001 (3, 4)MN M L Hibbard 1897 3 987 55 5MN M L Hibbard 1897 4 1,094 55 5MN Minnesota Valley 1918 4 938 938 MN Northeast Station 1961 NEPP 1,052 4,006 1,90MN Riverside 1927 XS67 (6, 7)MN Riverside 1927 6 3,076 2,797 1,10MN Riverside 1927 7 1,339 1,339 1,10MN Riverside 1927 8 5,068 11,645 10,58MN Sherburne County 6090 CS1 (1, 2)MN Sherburne County 6090 1 13,091 14,679 6,39MN Sherburne County 6090 2 13,184 14,833 5,27MN Sherburne County 6090 3 12,956 12,979 11,09MN Silver Lake 2008 4 3,133 3,132 2,02MN Syl Laskin 1891 CS0001 (1, 2)MN Syl Laskin 1891 1 1,692 808 75MN Syl Laskin 1891 2 1,649 807 75MO Asbury 2076 1 6,975 42,870 3,73MO Blue Valley 2132 3 4,670 4,670 3,90MO Chamois 2169 2 5,457 2,701 2,65MO Columbia 2123 CS5 (6, 7)

A, 32
APPENDIX A: ACID RAIN PROGRAM - YEAR 2000 SO2 ALLOWANCE HOLDINGS AND DEDUCTIONS

STATE PLANT NAME

PLANT 

CODE STACK/UNIT ID*

2000 

ALLOWANCES 

ALLOCATED

HELD IN 

ACCOUNTS AS 

OF 3/1/2001

ALLOWANCES 

DEDUCTED

MO Columbia 2123 6 903 903 23MO Columbia 2123 7 3,631 3,220 40MO Columbia 2123 8 125 125 MO Combustion Turbine 1 7160 **1 0 0 MO Combustion Turbine 1 7160 **NA4 0 0 MO Combustion Turbine 1 7160 **NA5 0 0 MO Combustion Turbine 1 7160 **NA6 0 0 MO Combustion Turbine 2 7161 **2 0 0 MO Combustion Turbine 3 7162 **3 0 0 MO Essex Power Plant 7749 1 0 50 MO Hawthorn 2079 5 12,773 33,639 MO Hawthorn 2079 6 0 5 MO Hawthorn 2079 7 0 5 MO Hawthorn 2079 8 0 5 MO Hawthorn 2079 9 0 5 MO Iatan 6065 1 16,208 16,208 13,43MO Iatan 6065 **2 0 0 MO James River 2161 3 3,327 1,863 1,50MO James River 2161 4 5,975 2,277 1,53MO James River 2161 5 2,133 4,045 3,47MO James River 2161 **GT2 604 4 MO Jim Hill 2073 **1 0 0 MO Labadie 2103 1 17,553 12,413 8,27MO Labadie 2103 2 16,363 16,233 9,94MO Labadie 2103 3 17,487 17,347 11,45MO Labadie 2103 4 15,584 15,460 9,61MO Lake Road 2098 6 605 2,840 1,76MO Meramec 2104 1 2,745 2,736 1,35MO Meramec 2104 2 2,778 4,251 1,24MO Meramec 2104 3 6,058 6,049 5,14MO Meramec 2104 4 7,175 12,154 10,18MO Montrose 2080 1 3,189 4,990 3,02MO Montrose 2080 CS023 (2, 3)MO Montrose 2080 2 3,535 5,724 2,69MO Montrose 2080 3 4,349 8,498 3,79MO Na 1 -- 7223 7223 **1 0 0 MO Na 1 -- 7223 7223 **2 0 0 MO Na 1 -- 7223 7223 **3 0 0 MO Na 1 -- 7226 7226 **1 0 0 MO New Madrid 2167 1 12,178 8,425 8,32MO New Madrid 2167 2 14,009 8,243 8,12MO Nodaway Power Plant 7754 1 0 50 MO Nodaway Power Plant 7754 2 0 50 MO Rg 1 & 2 212 **1 0 0 

A, 33
APPENDIX A: ACID RAIN PROGRAM - YEAR 2000 SO2 ALLOWANCE HOLDINGS AND DEDUCTIONS

STATE PLANT NAME

PLANT 

CODE STACK/UNIT ID*

2000 

ALLOWANCES 

ALLOCATED

HELD IN 

ACCOUNTS AS 

OF 3/1/2001

ALLOWANCES 

DEDUCTED

MO Rg 1 & 2 212 **2 0 0 MO Rush Island 6155 1 14,960 17,327 13,64MO Rush Island 6155 2 15,652 18,230 13,25MO Sibley 2094 CS0001 (1, 2, 3)MO Sibley 2094 1 519 2,190 1,58MO Sibley 2094 2 638 3,727 1,58MO Sibley 2094 3 7,634 13,767 12,70MO Sikeston 6768 1 6,791 7,063 6,52MO Sioux 2107 1 10,823 23,737 20,01MO Sioux 2107 2 9,492 23,417 16,52MO Southwest 6195 1 4,184 4,376 2,73MO St. Francis 7604 1 0 50 MO State Line (MO) 7296 1 0 30 MO State Line (MO) 7296 2-2 0 110 MO Thomas Hill 2168 MB1 4,421 2,985 2,94MO Thomas Hill 2168 MB2 7,432 4,088 4,02MO Thomas Hill 2168 MB3 18,257 11,492 11,33MS Batesville Generation Facility 55063 1 0 2 MS Batesville Generation Facility 55063 2 0 2 MS Batesville Generation Facility 55063 3 0 2 MS Baxter Wilson 2050 1 360 60 5MS Baxter Wilson 2050 2 3,564 10,151 9,95MS Caledonia Power I, LLC 2783 AA-001 0 1 MS Caledonia Power I, LLC 2783 AA-002 0 1 MS Caledonia Power I, LLC 2783 AA-003 0 1 MS Caledonia Power I, LLC 2783 AA-004 0 1 MS Caledonia Power I, LLC 2783 AA-005 0 1 MS Caledonia Power I, LLC 2783 AA-006 0 1 MS Chevron Cogenerating Station 2047 5 0 25 MS Daniel Electric Generating Plant 6073 1 11,228 16,056 13,94MS Daniel Electric Generating Plant 6073 2 14,277 14,690 13,06MS Delta 2051 1 26 6 MS Delta 2051 2 50 5 MS Gerald Andrus 8054 1 3,282 33,390 31,74MS Jack Watson 2049 1 172 172 MS Jack Watson 2049 2 180 180 MS Jack Watson 2049 3 273 273 MS Jack Watson 2049 4 7,525 26,555 16,15MS Jack Watson 2049 5 15,415 39,813 36,75MS Moselle 2070 1 35 35 MS Moselle 2070 2 76 66 MS Moselle 2070 3 42 42 MS Moselle 2070 **4 0 10 MS Moselle 2070 **5 0 0 

A, 34
APPENDIX A: ACID RAIN PROGRAM - YEAR 2000 SO2 ALLOWANCE HOLDINGS AND DEDUCTIONS

STATE PLANT NAME

PLANT 

CODE STACK/UNIT ID*

2000 

ALLOWANCES 

ALLOCATED

HELD IN 

ACCOUNTS AS 

OF 3/1/2001

ALLOWANCES 

DEDUCTED

MS Moselle 2070 **6 0 0 MS Moselle 2070 **7 0 0 MS Natchez 2052 1 2 2 MS New Albany Power I, LLC 13213 AA-001 0 1 MS New Albany Power I, LLC 13213 AA-002 0 1 MS New Albany Power I, LLC 13213 AA-003 0 1 MS New Albany Power I, LLC 13213 AA-004 0 1 MS New Albany Power I, LLC 13213 AA-005 0 1 MS New Albany Power I, LLC 13213 AA-006 0 1 MS R D Morrow 6061 1 4,800 6,414 4,13MS R D Morrow 6061 2 5,254 8,197 4,09MS Rex Brown 2053 3 41 2 MS Rex Brown 2053 4 159 3 MS Rex Brown 2053 1A 6 1 MS Rex Brown 2053 1B 6 1 MS Sweatt 2048 CS01 (1, 2)MS Sweatt 2048 1 78 78 MS Sweatt 2048 2 86 86 MS Wright 2063 W4 0 0 MT Colstrip 6076 1 7,859 5,208 5,05MT Colstrip 6076 2 7,870 5,624 5,55MT Colstrip 6076 3 4,405 2,933 2,85MT Colstrip 6076 4 2,917 2,329 2,31MT Frank Bird 2184 1 0 0 MT J E Corette 2187 2 5,062 3,614 3,31MT Lewis & Clark 6089 B1 1,444 1,444 1,14NC Asheville 2706 1 6,622 10,893 10,79NC Asheville 2706 2 5,261 9,475 9,37NC Asheville 2706 3 0 10 NC Asheville 2706 4 0 10 NC Belews Creek 8042 1 134,376 27,108 24,64NC Belews Creek 8042 2 131,213 52,453 47,68NC Buck 2720 5 1,709 828 75NC Buck 2720 6 1,208 837 76NC Buck 2720 7 1,831 922 83NC Buck 2720 8 6,407 3,572 3,24NC Buck 2720 9 7,354 5,093 4,64NC Cape Fear 2708 3 599 0 NC Cape Fear 2708 4 599 0 NC Cape Fear 2708 5 3,382 5,955 5,85NC Cape Fear 2708 6 3,913 6,897 6,79NC Cliffside 2721 1 1,612 1,313 1,19NC Cliffside 2721 2 1,625 1,346 1,22NC Cliffside 2721 3 2,486 2,080 1,89

A, 35
APPENDIX A: ACID RAIN PROGRAM - YEAR 2000 SO2 ALLOWANCE HOLDINGS AND DEDUCTIONS

STATE PLANT NAME

PLANT 

CODE STACK/UNIT ID*

2000 

ALLOWANCES 

ALLOCATED

HELD IN 

ACCOUNTS AS 

OF 3/1/2001

ALLOWANCES 

DEDUCTED

NC Cliffside 2721 4 2,555 973 88NC Cliffside 2721 5 33,588 26,323 23,94NC Dan River 2723 1 3,749 1,448 1,31NC Dan River 2723 2 4,665 1,578 1,43NC Dan River 2723 3 7,467 3,393 3,08NC G G Allen 2718 1 11,374 6,018 5,47NC G G Allen 2718 2 11,552 4,768 4,33NC G G Allen 2718 3 23,354 10,045 9,13NC G G Allen 2718 4 21,382 10,266 9,33NC G G Allen 2718 5 22,823 6,368 5,78NC L V Sutton 2713 CS0002 (1, 2)NC L V Sutton 2713 1 2,051 3,807 3,70NC L V Sutton 2713 2 2,270 3,807 3,70NC L V Sutton 2713 3 8,298 15,236 15,13NC Lee 2709 1 2,226 3,519 3,41NC Lee 2709 2 2,277 3,426 3,32NC Lee 2709 3 7,132 10,195 10,09NC Lee 2709 10 0 10 NC Lee 2709 11 0 10 NC Lee 2709 12 0 10 NC Lee 2709 13 0 10 NC Lincoln 7277 1 0 6 NC Lincoln 7277 2 0 4 NC Lincoln 7277 3 0 4 NC Lincoln 7277 4 0 4 NC Lincoln 7277 5 0 4 NC Lincoln 7277 6 0 4 NC Lincoln 7277 7 0 4 NC Lincoln 7277 8 0 4 NC Lincoln 7277 9 0 6 NC Lincoln 7277 10 0 5 NC Lincoln 7277 11 0 5 NC Lincoln 7277 12 0 5 NC Lincoln 7277 13 0 4 NC Lincoln 7277 14 0 5 NC Lincoln 7277 15 0 4 NC Lincoln 7277 16 0 4 NC Marshall 2727 1 24,311 17,054 15,50NC Marshall 2727 2 26,809 15,631 14,30NC Marshall 2727 3 43,969 26,260 23,87NC Marshall 2727 4 44,018 27,772 25,36NC Mayo 6250 CS0005 (1A, 1B)NC Mayo 6250 1A 12,785 14,857 14,75NC Mayo 6250 1B 12,785 14,857 14,75

A, 36
APPENDIX A: ACID RAIN PROGRAM - YEAR 2000 SO2 ALLOWANCE HOLDINGS AND DEDUCTIONS

STATE PLANT NAME

PLANT 

CODE STACK/UNIT ID*

2000 

ALLOWANCES 

ALLOCATED

HELD IN 

ACCOUNTS AS 

OF 3/1/2001

ALLOWANCES 

DEDUCTED

NC Riverbend 2732 7 3,754 3,574 3,25NC Riverbend 2732 8 3,759 3,411 3,10NC Riverbend 2732 9 5,071 6,263 5,69NC Riverbend 2732 10 5,406 5,959 5,41NC Rockingham Power, LLC 55116 CT1 0 5 NC Rockingham Power, LLC 55116 CT2 0 5 NC Rockingham Power, LLC 55116 CT3 0 4 NC Rockingham Power, LLC 55116 CT4 0 4 NC Rockingham Power, LLC 55116 CT5 0 5 NC Roxboro 2712 1 11,088 16,158 16,05NC Roxboro 2712 2 19,642 30,386 30,28NC Roxboro 2712 CS0003 (3A, 3B)NC Roxboro 2712 3A 9,096 15,458 15,35NC Roxboro 2712 3B 9,096 15,458 15,35NC Roxboro 2712 CS0004 (4A, 4B)NC Roxboro 2712 4A 10,407 10,029 9,92NC Roxboro 2712 4B 10,407 10,029 9,92NC W H Weatherspoon 2716 CS0001 (1, 2)NC W H Weatherspoon 2716 1 1,122 2,097 1,99NC W H Weatherspoon 2716 2 1,125 2,097 1,99NC W H Weatherspoon 2716 3 1,626 2,732 2,63ND Antelope Valley 6469 B1 11,947 11,947 6,64ND Antelope Valley 6469 B2 11,131 11,131 6,40ND Coal Creek 6030 1 23,310 14,410 14,33ND Coal Creek 6030 2 21,187 17,587 12,81ND Coyote 8222 B1 16,182 16,117 14,52ND Leland Olds 2817 1 9,105 17,605 16,86ND Leland Olds 2817 2 26,401 32,901 28,58ND Milton R Young 2823 B1 12,951 25,512 18,09ND Milton R Young 2823 B2 15,885 23,291 21,13ND R M Heskett 2790 B2 3,202 3,162 1,77ND Stanton 2824 1 7,447 11,847 7,66ND Stanton 2824 10 1,334 1,334 97NE Bluffs 2276 4 18 18 NE C W Burdick 2241 B-3 0 10 NE Canaday 2226 1 627 627 8NE Gerald Gentleman Sta 6077 1 10,805 10,714 9,60NE Gerald Gentleman Sta 6077 2 17,572 17,302 12,98NE Gerald Whelan Energy Center 60 1 2,335 2,335 2,16NE Harold Kramer 2269 1 38 38 NE Harold Kramer 2269 2 40 40 NE Harold Kramer 2269 3 1,052 1,052 NE Harold Kramer 2269 4 2,079 2,079 NE Lon Wright 2240 8 2,044 2,044 84

A, 37
APPENDIX A: ACID RAIN PROGRAM - YEAR 2000 SO2 ALLOWANCE HOLDINGS AND DEDUCTIONS

STATE PLANT NAME

PLANT 

CODE STACK/UNIT ID*

2000 

ALLOWANCES 

ALLOCATED

HELD IN 

ACCOUNTS AS 

OF 3/1/2001

ALLOWANCES 

DEDUCTED

NE Na 1 -- 7019 7019 **NA1 0 0 NE Nebraska City 6096 1 13,194 15,234 15,22NE North Omaha 2291 CS000A (1, 2, 3)NE North Omaha 2291 1 2,388 2,388 2,04NE North Omaha 2291 2 3,287 3,287 2,04NE North Omaha 2291 3 3,208 3,208 2,04NE North Omaha 2291 4 3,849 3,849 2,87NE North Omaha 2291 5 4,647 4,647 3,63NE Platte 59 1 2,927 2,917 2,49NE Rokeby 6373 2 0 20 NE Sarpy County Station 2292 CT3 0 0 NE Sarpy County Station 2292 CT4A 0 0 NE Sarpy County Station 2292 CT4B 0 0 NE Sarpy County Station 2292 CT5A 0 0 NE Sarpy County Station 2292 CT5B 0 0 NE Sheldon 2277 1 2,168 2,190 2,10NE Sheldon 2277 2 2,280 2,308 2,08NH Merrimack 2364 1 4,288 14,634 14,11NH Merrimack 2364 2 9,242 27,596 26,42NH Newington 8002 1 12,103 25,764 4,96NH Schiller 2367 4 1,514 2,162 2,03NH Schiller 2367 5 1,457 2,072 1,99NH Schiller 2367 6 1,643 2,143 1,79NJ B L England 2378 1 3,811 14,775 13,60NJ B L England 2378 2 4,931 1,535 1,08NJ B L England 2378 3 2,420 1,170 81NJ Bergen 2398 1 1,978 6,500 NJ Bergen 2398 2 2,044 0 NJ Bergen 2398 1101 0 4 NJ Bergen 2398 1201 0 3 NJ Bergen 2398 1301 0 3 NJ Bergen 2398 1401 0 2 NJ Burlington (NJ) 2399 7 561 0 NJ Burlington (NJ) 2399 101 0 2 NJ Burlington (NJ) 2399 102 0 2 NJ Burlington (NJ) 2399 103 0 2 NJ Burlington (NJ) 2399 104 0 2 NJ Burlington (NJ) 2399 121 0 8 NJ Burlington (NJ) 2399 122 0 12 NJ Burlington (NJ) 2399 123 0 17 1NJ Burlington (NJ) 2399 124 0 12 NJ Butler 7152 **1 0 0 NJ Deepwater 2384 1 1,164 14 NJ Deepwater 2384 3 11 11 

A, 38
APPENDIX A: ACID RAIN PROGRAM - YEAR 2000 SO2 ALLOWANCE HOLDINGS AND DEDUCTIONS

STATE PLANT NAME

PLANT 

CODE STACK/UNIT ID*

2000 

ALLOWANCES 

ALLOCATED

HELD IN 

ACCOUNTS AS 

OF 3/1/2001

ALLOWANCES 

DEDUCTED

NJ Deepwater 2384 4 59 59 NJ Deepwater 2384 5 5 5 NJ Deepwater 2384 6 59 59 NJ Deepwater 2384 8 2,744 3,894 3,19NJ Deepwater 2384 9 1,814 1,814 NJ Gilbert 2393 1 60 60 NJ Gilbert 2393 2 37 37 NJ Gilbert 2393 3 700 700 NJ Gilbert 2393 9 0 4 NJ Gilbert 2393 04 600 596 NJ Gilbert 2393 05 596 596 NJ Gilbert 2393 06 593 593 NJ Gilbert 2393 07 605 605 NJ Hudson 2403 1 1,197 119 11NJ Hudson 2403 2 15,972 23,134 23,11NJ Kearny 2404 7 145 145 12NJ Kearny 2404 8 153 314 28NJ Linden 2406 2 644 644 29NJ Linden 2406 4 423 0 NJ Linden 2406 5 0 11 1NJ Linden 2406 6 0 7 NJ Linden 2406 7 0 45 3NJ Linden 2406 8 0 2 NJ Linden 2406 11 968 968 15NJ Linden 2406 12 665 665 NJ Linden 2406 13 877 246 17NJ Mercer 2408 1 7,683 8,448 8,44NJ Mercer 2408 2 7,439 8,375 8,37NJ Na 1 -- 7139 7139 **1 0 0 NJ Na 2 -- 7140 7140 **1 0 0 NJ Na 3 -- 7141 7141 **1 0 0 NJ Na 3 -- 7141 7141 **2 0 0 NJ Na 4 -- 7142 7142 **1 0 0 NJ Na 5 -- 7217 7217 **1 0 0 NJ Na 6 -- 7218 7218 **1 0 0 NJ Pedricktown Cogen 10099 001001 0 5 NJ Pedricktown Cogen 10099 005004 0 2 NJ Sayreville 2390 2 2 2 NJ Sayreville 2390 3 2 2 NJ Sayreville 2390 5 41 41 NJ Sayreville 2390 6 39 39 NJ Sayreville 2390 07 766 766 NJ Sayreville 2390 08 892 892 NJ Sewaren 2411 1 117 117 5

A, 39
APPENDIX A: ACID RAIN PROGRAM - YEAR 2000 SO2 ALLOWANCE HOLDINGS AND DEDUCTIONS

STATE PLANT NAME

PLANT 

CODE STACK/UNIT ID*

2000 

ALLOWANCES 

ALLOCATED

HELD IN 

ACCOUNTS AS 

OF 3/1/2001

ALLOWANCES 

DEDUCTED

NJ Sewaren 2411 2 340 40 2NJ Sewaren 2411 3 254 254 3NJ Sewaren 2411 4 574 574 4NJ Sewaren 2411 5 0 0 NJ Sherman Avenue 7288 1 0 100 NJ Werner 2385 4 194 194 NM Cunningham 2454 121B 42 42 NM Cunningham 2454 122B 269 265 NM Cunningham 2454 123T 0 2 NM Cunningham 2454 124T 0 2 NM Four Corners 2442 1 3,593 3,980 3,61NM Four Corners 2442 2 3,589 3,989 3,62NM Four Corners 2442 3 4,478 4,550 4,14NM Four Corners 2442 4 12,507 14,515 11,93NM Four Corners 2442 5 13,275 18,211 15,01NM Maddox 2446 051B 170 170 NM Milagro 54814 1 0 1 NM Milagro 54814 2 0 1 NM North Lovington 2473 S2 0 0 NM Person 2448 3 0 0 NM Person 2448 4 0 0 NM Person Generating Project 55039 GT-1 0 5 NM Prewitt Escalante Generating Statio 87 1 1,874 1,874 1,38NM Reeves 2450 1 4 4 NM Reeves 2450 2 7 7 NM Reeves 2450 3 104 104 NM Rio Grande 2444 6 3 3 NM Rio Grande 2444 7 1 1 NM Rio Grande 2444 8 80 80 NM San Juan 2451 1 7,941 6,629 5,54NM San Juan 2451 2 5,922 5,752 5,57NM San Juan 2451 3 13,878 13,878 9,11NM San Juan 2451 4 13,047 13,047 8,64NV Clark 2322 1 20 20 NV Clark 2322 2 273 151 NV Clark 2322 3 18 18 NV El Dorado Energy 55077 CP1 (EDE1, EDE2)NV El Dorado Energy 55077 EDE1 0 3 NV El Dorado Energy 55077 EDE2 0 3 NV Fort Churchill 2330 1 371 371 2NV Fort Churchill 2330 2 577 577 10NV Harry Allen 7082 **5 0 0 NV Harry Allen 7082 **6 0 0 NV Harry Allen 7082 **3 0 1 

A, 40
APPENDIX A: ACID RAIN PROGRAM - YEAR 2000 SO2 ALLOWANCE HOLDINGS AND DEDUCTIONS

STATE PLANT NAME

PLANT 

CODE STACK/UNIT ID*

2000 

ALLOWANCES 

ALLOCATED

HELD IN 

ACCOUNTS AS 

OF 3/1/2001

ALLOWANCES 

DEDUCTED

NV Harry Allen 7082 **GT1 0 0 NV Harry Allen 7082 **GT2 0 0 NV Mohave 2341 1 26,660 26,660 20,30NV Mohave 2341 2 26,556 26,556 22,45NV North Valmy 8224 1 6,960 6,315 5,67NV North Valmy 8224 2 4,262 2,916 1,56NV Reid Gardner 2324 1 2,173 1,273 71NV Reid Gardner 2324 2 2,202 1,402 76NV Reid Gardner 2324 3 2,125 1,325 72NV Reid Gardner 2324 4 2,814 1,114 76NV Sunrise 2326 1 50 50 2NV Tracy 2336 1 15 27 2NV Tracy 2336 2 46 46 3NV Tracy 2336 3 314 295 1NV Tracy 2336 4 0 2 NV Tracy 2336 5 0 3 NV Tracy 2336 6 0 2 NY 59Th Street 2503 110 64 0 NY 74Th Street 2504 CS0002 (120, 121, 122)NY 74Th Street 2504 120 447 447 41NY 74Th Street 2504 121 449 449 41NY 74Th Street 2504 122 447 447 41NY AES Cayuga, L.L.C.(Milliken) 2535 XS12 (1, 2)NY AES Cayuga, L.L.C.(Milliken) 2535 1 4,928 6,406 4,80NY AES Cayuga, L.L.C.(Milliken) 2535 2 5,215 6,296 4,20NY AES Greenidge LLC 2527 CSG003 (4, 5)NY AES Greenidge LLC 2527 4 982 7,018 7,01NY AES Greenidge LLC 2527 5 980 58 5NY AES Greenidge LLC 2527 6 3,185 12,819 12,81NY AES Hickling L.L.C. 2529 CSH001 (1, 2)NY AES Hickling L.L.C. 2529 1 725 235 23NY AES Hickling L.L.C. 2529 2 725 725 72NY AES Hickling L.L.C. 2529 CSH002 (3, 4)NY AES Hickling L.L.C. 2529 3 895 550 55NY AES Hickling L.L.C. 2529 4 933 933 93NY AES Jennison, L.L.C. 2531 CSJ001 (1, 2)NY AES Jennison, L.L.C. 2531 1 650 750 75NY AES Jennison, L.L.C. 2531 2 676 676 67NY AES Jennison, L.L.C. 2531 CSJ002 (3, 4)NY AES Jennison, L.L.C. 2531 3 724 1,088 1,08NY AES Jennison, L.L.C. 2531 4 724 725 72NY AES Somerset L.L.C. 6082 1 13,889 8,770 8,29NY AES Westover 2526 CSW003 (11, 12)NY AES Westover 2526 11 792 5,944 5,94

A, 41
APPENDIX A: ACID RAIN PROGRAM - YEAR 2000 SO2 ALLOWANCE HOLDINGS AND DEDUCTIONS

STATE PLANT NAME

PLANT 

CODE STACK/UNIT ID*

2000 

ALLOWANCES 

ALLOCATED

HELD IN 

ACCOUNTS AS 

OF 3/1/2001

ALLOWANCES 

DEDUCTED

NY AES Westover 2526 12 780 688 68NY AES Westover 2526 13 3,288 10,860 10,85NY Albany 2539 1 1,801 932 92NY Albany 2539 2 1,556 1,151 96NY Albany 2539 3 1,593 843 84NY Albany 2539 4 1,687 1,568 99NY Allegany Station #133 10619 00001 0 1 NY Arthur Kill 2490 CS0002 (20, 30)NY Arthur Kill 2490 20 1,478 600 NY Arthur Kill 2490 30 2,367 401 NY Astoria 8906 10 1,216 0 NY Astoria 8906 20 1,554 0 NY Astoria 8906 30 3,024 475 46NY Astoria 8906 40 2,376 409 39NY Astoria 8906 50 2,700 219 21NY Bowline Point 2625 1 4,240 900 89NY Bowline Point 2625 2 4,241 581 57NY Brooklyn Navy Yard Cogeneration Fac 54914 1 0 0 1NY Brooklyn Navy Yard Cogeneration Fac 54914 2 0 0 NY Carthage Energy, LLC 10620 1 0 2 NY CH Resources - Niagara Falls 50202 1 0 1,190 1,10NY CH Resources - Syracuse 10621 1 0 10 NY Charles Poletti 2491 001 6,438 6,238 2,33NY Dunkirk 2554 1 2,843 11,001 11,00NY Dunkirk 2554 2 3,229 11,633 11,65NY Dunkirk 2554 CS0003 (3, 4)NY Dunkirk 2554 3 5,292 15,527 15,52NY Dunkirk 2554 4 5,906 17,597 16,52NY Dynegy Danskammer, LLC 2480 1 948 156 15NY Dynegy Danskammer, LLC 2480 2 920 200 19NY Dynegy Danskammer, LLC 2480 3 3,129 3,614 3,60NY Dynegy Danskammer, LLC 2480 4 6,030 8,475 8,47NY Dynegy Roseton, LLC 8006 1 15,584 14,966 7,40NY Dynegy Roseton, LLC 8006 2 14,912 14,294 9,25NY E F Barrett 2511 10 2,372 2,372 13NY E F Barrett 2511 20 2,337 2,337 37NY East River 2493 50 1,396 0 NY East River 2493 60 1,430 1,430 25NY East River 2493 70 1,033 1,033 27NY Far Rockaway 2513 40 469 469 NY Glenwood 2514 40 939 939 NY Glenwood 2514 50 903 903 NY Huntley Power 2549 CS0002 (63, 64, 65, 66)NY Huntley Power 2549 63 2,657 3,790 3,79

A, 42
APPENDIX A: ACID RAIN PROGRAM - YEAR 2000 SO2 ALLOWANCE HOLDINGS AND DEDUCTIONS

STATE PLANT NAME

PLANT 

CODE STACK/UNIT ID*

2000 

ALLOWANCES 

ALLOCATED

HELD IN 

ACCOUNTS AS 

OF 3/1/2001

ALLOWANCES 

DEDUCTED

NY Huntley Power 2549 64 2,664 8,397 8,39NY Huntley Power 2549 65 2,693 5,592 5,59NY Huntley Power 2549 66 2,729 3,651 3,65NY Huntley Power 2549 CS0001 (67, 68)NY Huntley Power 2549 67 5,775 16,004 16,00NY Huntley Power 2549 68 5,381 15,971 14,86NY Lovett 2629 3 225 225 1NY Lovett 2629 4 4,569 5,019 5,01NY Lovett 2629 5 4,988 4,888 4,87NY Northport 2516 1 8,323 23,048 7,39NY Northport 2516 2 10,130 12,096 4,52NY Northport 2516 3 11,122 30,518 9,66NY Northport 2516 4 5,794 18,539 4,07NY Oswego 2594 1 0 0 NY Oswego 2594 2 0 0 NY Oswego 2594 3 90 0 NY Oswego 2594 4 398 0 NY Oswego 2594 5 17,242 1,492 1,50NY Oswego 2594 6 4,808 4,767 21NY Port Jefferson 2517 1 475 475 NY Port Jefferson 2517 2 498 498 NY Port Jefferson 2517 3 4,397 12,300 3,08NY Port Jefferson 2517 4 5,181 19,002 4,22NY Ravenswood 2500 10 3,165 401 NY Ravenswood 2500 20 2,678 901 38NY Ravenswood 2500 30 4,992 2,702 1,57NY Richard M Flynn 7314 001 0 200 9NY Rochester 3, Beebee Station 2640 1 0 0 NY Rochester 3, Beebee Station 2640 2 0 0 NY Rochester 3, Beebee Station 2640 3 2 0 NY Rochester 3, Beebee Station 2640 4 0 0 NY Rochester 3, Beebee Station 2640 7 201 0 NY Rochester 3, Beebee Station 2640 8 0 0 NY Rochester 3, Beebee Station 2640 12 2,269 0 NY Rochester 7, Russell Station 2642 CS1 (1, 2)NY Rochester 7, Russell Station 2642 1 1,093 5,632 5,56NY Rochester 7, Russell Station 2642 2 1,626 5,609 5,56NY Rochester 7, Russell Station 2642 CS2 (3, 4)NY Rochester 7, Russell Station 2642 3 1,586 7,375 7,19NY Rochester 7, Russell Station 2642 4 2,213 7,335 7,19NY S A Carlson 2682 CS0001 (9, 12)NY S A Carlson 2682 9 664 664 65NY S A Carlson 2682 CS0002 (10, 11)NY S A Carlson 2682 10 673 673 67

A, 43
APPENDIX A: ACID RAIN PROGRAM - YEAR 2000 SO2 ALLOWANCE HOLDINGS AND DEDUCTIONS

STATE PLANT NAME

PLANT 

CODE STACK/UNIT ID*

2000 

ALLOWANCES 

ALLOCATED

HELD IN 

ACCOUNTS AS 

OF 3/1/2001

ALLOWANCES 

DEDUCTED

NY S A Carlson 2682 11 424 847 84NY S A Carlson 2682 12 1,276 1,053 91NY South Glens Falls Energy, LLC 10618 1 0 3 NY Waterside 2502 41 252 0 NY Waterside 2502 42 247 0 NY Waterside 2502 51 416 0 NY Waterside 2502 52 417 0 NY Waterside 2502 CS0002 (61, 62)NY Waterside 2502 61 431 431 NY Waterside 2502 62 507 507 NY Waterside 2502 CS0003 (80, 90)NY Waterside 2502 80 1,128 1,128 NY Waterside 2502 90 1,234 1,234 OH Acme 2877 9 1 0 OH Acme 2877 11 7 0 OH Acme 2877 13 1,846 0 OH Acme 2877 14 2,519 0 OH Acme 2877 15 3,365 0 OH Acme 2877 16 2,421 0 OH Acme 2877 91 2,012 0 OH Acme 2877 92 1,800 0 OH AMP-Ohio Bowling Green 7783 P001 0 1 OH AMP-Ohio Hamilton 7782 P001 0 1 OH Ashtabula 2835 7 7,220 4,403 3,64OH Ashtabula 2835 CS1 (8, 9, 10, 11)OH Ashtabula 2835 8 2,337 800 73OH Ashtabula 2835 9 1,990 0 OH Ashtabula 2835 10 1,795 2,141 2,04OH Ashtabula 2835 11 1,890 1,519 1,43OH Avon Lake 2836 9 2,567 0 OH Avon Lake 2836 10 2,254 2,800 2,72OH Avon Lake 2836 11 5,025 0 OH Avon Lake 2836 12 15,199 20,000 19,37OH Bay Shore 2878 XS14 (1, 2, 3, 4)OH Bay Shore 2878 1 4,719 796 76OH Bay Shore 2878 2 4,495 2,488 2,39OH Bay Shore 2878 3 4,277 2,229 2,13OH Bay Shore 2878 4 7,038 3,885 3,77OH Cardinal 2828 1 14,778 71,986 69,88OH Cardinal 2828 2 16,526 47,289 26,69OH Cardinal 2828 3 17,301 23,460 22,77OH Conesville 2840 CS012 (1, 2)OH Conesville 2840 1 1,814 17,076 16,57OH Conesville 2840 2 2,110 15,173 14,73

A, 44
APPENDIX A: ACID RAIN PROGRAM - YEAR 2000 SO2 ALLOWANCE HOLDINGS AND DEDUCTIONS

STATE PLANT NAME

PLANT 

CODE STACK/UNIT ID*

2000 

ALLOWANCES 

ALLOCATED

HELD IN 

ACCOUNTS AS 

OF 3/1/2001

ALLOWANCES 

DEDUCTED

OH Conesville 2840 3 2,370 16,843 16,35OH Conesville 2840 4 21,031 77,478 76,27OH Conesville 2840 CS056 (5, 6)OH Conesville 2840 5 9,025 7,483 7,26OH Conesville 2840 6 9,394 6,947 6,74OH Dover 2914 **6 153 0 OH Eastlake 2837 1 3,366 4,953 4,85OH Eastlake 2837 2 3,725 5,338 5,28OH Eastlake 2837 3 4,319 7,025 6,95OH Eastlake 2837 4 6,258 8,946 8,85OH Eastlake 2837 5 16,605 37,017 36,64OH Edgewater 2857 11 878 0 OH Edgewater 2857 12 947 0 OH Edgewater 2857 13 2,179 113 1OH Frank M Tait 2847 1 0 4 OH Frank M Tait 2847 2 0 4 OH Frank M Tait 2847 3 0 4 OH Gen J M Gavin 8102 1 34,099 12,763 12,38OH Gen J M Gavin 8102 2 34,738 12,697 12,31OH Gorge 2858 25 1,498 0 OH Gorge 2858 26 1,677 0 OH Greenville Electric Gen Station 55228 G1CT1 0 0 OH Greenville Electric Gen Station 55228 G1CT2 0 0 OH Greenville Electric Gen Station 55228 G2CT1 0 0 OH Greenville Electric Gen Station 55228 G2CT2 0 0 OH Greenville Electric Gen Station 55228 G3CT1 0 0 OH Greenville Electric Gen Station 55228 G3CT2 0 0 OH Greenville Electric Gen Station 55228 G4CT1 0 0 OH Greenville Electric Gen Station 55228 G4CT2 0 0 OH Hamilton 2917 9 1,665 1,665 99OH J M Stuart 2850 1 19,632 45,673 29,04OH J M Stuart 2850 2 18,611 38,922 28,50OH J M Stuart 2850 3 18,454 39,008 22,68OH J M Stuart 2850 4 19,503 40,571 25,42OH Killen Station 6031 2 16,928 24,937 24,63OH Kyger Creek 2876 CS001 (1, 2, 3, 4, 5)OH Kyger Creek 2876 1 8,100 25,736 25,23OH Kyger Creek 2876 2 7,797 25,736 25,23OH Kyger Creek 2876 3 7,524 25,736 25,23OH Kyger Creek 2876 4 7,860 25,736 25,23OH Kyger Creek 2876 5 7,874 25,736 25,23OH Lake Road 2908 6 1,340 1,340 OH Lake Shore 2838 18 6,033 1,302 1,23OH Lake Shore 2838 91 47 0 

A, 45
APPENDIX A: ACID RAIN PROGRAM - YEAR 2000 SO2 ALLOWANCE HOLDINGS AND DEDUCTIONS

STATE PLANT NAME

PLANT 

CODE STACK/UNIT ID*

2000 

ALLOWANCES 

ALLOCATED

HELD IN 

ACCOUNTS AS 

OF 3/1/2001

ALLOWANCES 

DEDUCTED

OH Lake Shore 2838 92 84 0 OH Lake Shore 2838 93 65 0 OH Lake Shore 2838 94 107 0 OH Madison Generating Station 55110 1 0 4 OH Madison Generating Station 55110 2 0 4 OH Madison Generating Station 55110 3 0 4 OH Madison Generating Station 55110 4 0 4 OH Madison Generating Station 55110 5 0 4 OH Madison Generating Station 55110 6 0 4 OH Madison Generating Station 55110 7 0 4 OH Madison Generating Station 55110 8 0 4 OH Miami Fort 2832 CS056 (5-1, 5-2, 6)OH Miami Fort 2832 6 4,908 20,521 16,67OH Miami Fort 2832 7 16,607 40,929 39,66OH Miami Fort 2832 8 18,233 19,418 18,80OH Miami Fort 2832 5-1 144 3,342 3,18OH Miami Fort 2832 5-2 144 3,341 3,18OH Muskingum River 2872 CS014 1, 2, 3, 4)OH Muskingum River 2872 1 6,414 31,148 30,23OH Muskingum River 2872 2 6,108 30,348 29,46OH Muskingum River 2872 3 6,018 37,158 36,07OH Muskingum River 2872 4 5,080 37,583 36,48OH Muskingum River 2872 5 17,450 25,495 23,77OH Niles 2861 XS12 (1, 2)OH Niles 2861 1 2,995 5,925 5,82OH Niles 2861 2 3,924 14,444 14,01OH O H Hutchings 2848 CS0001 (H-1, H-2)OH O H Hutchings 2848 H-1 1,736 594 58OH O H Hutchings 2848 H-2 1,671 538 53OH O H Hutchings 2848 CS0002 (H-3, H-4)OH O H Hutchings 2848 H-3 1,603 1,421 1,40OH O H Hutchings 2848 H-4 1,623 1,340 1,32OH O H Hutchings 2848 CS0003 (H-5, H-6)OH O H Hutchings 2848 H-5 1,630 1,338 1,32OH O H Hutchings 2848 H-6 1,660 1,499 1,48OH Picway 2843 9 2,128 10,879 10,56OH Poston 2844 1 787 0 OH Poston 2844 2 731 0 OH Poston 2844 3 957 0 OH R E Burger 2864 CS0001 (1, 2, 3, 4, 5, 6, 7, 8)OH R E Burger 2864 1 1,233 0 OH R E Burger 2864 2 1,206 0 OH R E Burger 2864 3 1,246 0 OH R E Burger 2864 4 1,275 0 

A, 46
APPENDIX A: ACID RAIN PROGRAM - YEAR 2000 SO2 ALLOWANCE HOLDINGS AND DEDUCTIONS

STATE PLANT NAME

PLANT 

CODE STACK/UNIT ID*

2000 

ALLOWANCES 

ALLOCATED

HELD IN 

ACCOUNTS AS 

OF 3/1/2001

ALLOWANCES 

DEDUCTED

OH R E Burger 2864 5 1,327 722 70OH R E Burger 2864 6 1,325 799 75OH R E Burger 2864 7 4,648 25,538 25,27OH R E Burger 2864 8 5,361 33,218 20,50OH Refuse & Coal 312 CSSA12 (001, 002)OH Refuse & Coal 312 001 426 0 OH Refuse & Coal 312 002 381 0 OH Refuse & Coal 312 CSSA34 (003, 004)OH Refuse & Coal 312 003 402 0 OH Refuse & Coal 312 004 438 0 OH Refuse & Coal 312 CSSA56 (005, 006)OH Refuse & Coal 312 005 375 0 OH Refuse & Coal 312 006 366 0 OH Richard Gorsuch 7253 CS0001 (1, 2, 3, 4)OH Richard Gorsuch 7253 1 6,152 9,285 8,42OH Richard Gorsuch 7253 2 5,064 9,285 8,42OH Richard Gorsuch 7253 3 6,880 9,285 8,42OH Richard Gorsuch 7253 4 1,404 9,283 8,42OH Tidd 2828 **1 714 0 OH Toronto 2867 9 1,873 0 OH Toronto 2867 10 3,343 0 OH Toronto 2867 11 3,612 0 OH W H Sammis 2866 CS0001 (1, 2)OH W H Sammis 2866 1 6,239 12,468 12,34OH W H Sammis 2866 2 5,472 13,081 12,95OH W H Sammis 2866 CS0002 (3, 4)OH W H Sammis 2866 3 6,238 12,713 12,57OH W H Sammis 2866 4 5,529 11,764 11,65OH W H Sammis 2866 5 10,422 21,507 21,29OH W H Sammis 2866 6 19,953 25,976 25,71OH W H Sammis 2866 7 18,639 24,339 24,09OH W H Zimmer 6019 1 16,154 21,465 19,41OH Walter C Beckjord 2830 1 1,834 4,657 4,43OH Walter C Beckjord 2830 2 1,859 5,163 4,94OH Walter C Beckjord 2830 3 2,530 8,110 7,75OH Walter C Beckjord 2830 4 3,262 8,081 7,72OH Walter C Beckjord 2830 5 3,858 16,870 16,13OH Walter C Beckjord 2830 6 9,925 38,017 30,44OH Woodsdale 7158 **GT1 294 294 OH Woodsdale 7158 **GT2 294 294 OH Woodsdale 7158 **GT3 294 294 OH Woodsdale 7158 **GT4 294 294 OH Woodsdale 7158 **GT5 294 294 OH Woodsdale 7158 **GT6 294 294 

A, 47
APPENDIX A: ACID RAIN PROGRAM - YEAR 2000 SO2 ALLOWANCE HOLDINGS AND DEDUCTIONS

STATE PLANT NAME

PLANT 

CODE STACK/UNIT ID*

2000 

ALLOWANCES 

ALLOCATED

HELD IN 

ACCOUNTS AS 

OF 3/1/2001

ALLOWANCES 

DEDUCTED

OH Woodsdale 7158 **GT7 0 0 OH Woodsdale 7158 **GT8 0 0 OH Woodsdale 7158 **GT9 0 0 OH Woodsdale 7158 **GT10 0 0 OH Woodsdale 7158 **GT11 0 0 OH Woodsdale 7158 **GT12 0 0 OK Anadarko 3006 3 0 1 OK Arbuckle 2947 ARB 45 45 OK Chouteau Power Plant 7757 1 0 76 OK Chouteau Power Plant 7757 2 0 75 OK Comanche 8059 7251 333 323 OK Comanche 8059 7252 2 12 OK Conoco 7185 **1 222 222 OK Conoco 7185 **2 222 222 1OK Grda 165 1 14,642 15,633 15,51OK Grda 165 2 8,396 7,405 4,87OK Horseshoe Lake 2951 6 173 173 OK Horseshoe Lake 2951 7 231 231 OK Horseshoe Lake 2951 8 313 253 OK Horseshoe Lake 2951 9 0 30 OK Horseshoe Lake 2951 10 0 30 OK Hugo 6772 1 11,877 9,377 7,37OK Mooreland 3008 1 0 1 OK Mooreland 3008 2 44 42 OK Mooreland 3008 3 7 7 OK Muskogee 2952 3 141 141 OK Muskogee 2952 4 9,311 9,811 9,35OK Muskogee 2952 5 8,277 11,277 10,32OK Muskogee 2952 6 14,425 10,925 9,73OK Mustang 2953 1 32 32 OK Mustang 2953 2 26 26 OK Mustang 2953 3 1 1 OK Mustang 2953 4 163 163 OK Na 1 -- 5030 5030 **1 0 0 OK Na 1 -- 5030 5030 **2 0 0 OK Na 1 -- 5030 5030 **3 0 0 OK Northeastern 2963 3301 1,742 1,742 OK Northeastern 2963 3302 5,935 5,935 OK Northeastern 2963 CS100 (3313, 3314)OK Northeastern 2963 3313 13,833 13,833 8,84OK Northeastern 2963 3314 14,884 14,884 8,84OK Ponca 762 2 0 0 OK Ponca 762 3 0 0 OK Riverside 4940 1501 519 489 28

A, 48
APPENDIX A: ACID RAIN PROGRAM - YEAR 2000 SO2 ALLOWANCE HOLDINGS AND DEDUCTIONS

STATE PLANT NAME

PLANT 

CODE STACK/UNIT ID*

2000 

ALLOWANCES 

ALLOCATED

HELD IN 

ACCOUNTS AS 

OF 3/1/2001

ALLOWANCES 

DEDUCTED

OK Riverside 4940 1502 285 315 30OK Seminole 2956 1 412 412 OK Seminole 2956 2 453 453 OK Seminole 2956 3 494 494 OK Sooner 6095 1 10,471 10,471 8,94OK Sooner 6095 2 9,979 9,979 8,92OK Southwestern 2964 CP001(8002,8003,801N,801S)OK Southwestern 2964 8002 15 15 OK Southwestern 2964 8003 164 164 2OK Southwestern 2964 801N 3 3 OK Southwestern 2964 801S 0 0 OK Tulsa 2965 CP001(1402,1403,1404)OK Tulsa 2965 1402 98 98 OK Tulsa 2965 1403 4 4 OK Tulsa 2965 1404 58 58 OR Boardman 6106 1SG 13,377 14,375 14,37OR Coyote Springs 7350 CTG1 0 4 OR Hermiston 54761 1 0 7 OR Hermiston 54761 2 0 7 PA Allegheny Energy Unit 1 and Unit 2 55196 1 0 1 PA Allegheny Energy Unit 1 and Unit 2 55196 2 0 1 PA Allegheny Energy Unit 8 and Unit 9 55377 8 0 1 PA Allegheny Energy Unit 8 and Unit 9 55377 9 0 1 PA Armstrong 3178 1 6,215 17,621 17,42PA Armstrong 3178 2 6,654 17,166 16,96PA Bruce Mansfield 6094 1 12,717 14,134 8,54PA Bruce Mansfield 6094 2 14,069 14,793 8,38PA Bruce Mansfield 6094 3 14,473 14,473 12,13PA Brunner Island 3140 CS102 (1, 2)PA Brunner Island 3140 1 11,972 14,701 14,67PA Brunner Island 3140 2 13,414 17,371 17,30PA Brunner Island 3140 3 23,209 28,957 28,91PA Cheswick 8226 1 16,891 46,544 44,90PA Conemaugh 3118 1 25,938 10,764 3,11PA Conemaugh 3118 2 28,752 11,198 3,98PA Cromby 3159 1 2,203 4,668 3,97PA Cromby 3159 2 2,110 2,110 95PA Delaware 3160 71 743 743 18PA Delaware 3160 81 537 1,071 22PA Eddystone 3161 1 2,845 3,851 2,91PA Eddystone 3161 2 3,005 4,241 3,66PA Eddystone 3161 CS034 (3, 4)PA Eddystone 3161 3 1,895 1,895 1,25PA Eddystone 3161 4 2,011 2,011 1,20

A, 49
APPENDIX A: ACID RAIN PROGRAM - YEAR 2000 SO2 ALLOWANCE HOLDINGS AND DEDUCTIONS

STATE PLANT NAME

PLANT 

CODE STACK/UNIT ID*

2000 

ALLOWANCES 

ALLOCATED

HELD IN 

ACCOUNTS AS 

OF 3/1/2001

ALLOWANCES 

DEDUCTED

PA Elrama 3098 CS001 (1, 2, 3, 4)PA Elrama 3098 1 1,650 910 88PA Elrama 3098 2 1,616 700 68PA Elrama 3098 3 1,568 555 54PA Elrama 3098 4 2,580 2,580 2,51PA F R Phillips 3099 CS001 (1, 2, 3, 4, 5, 6)PA F R Phillips 3099 1 663 0 PA F R Phillips 3099 2 504 0 PA F R Phillips 3099 3 1,165 0 PA F R Phillips 3099 4 1,112 0 PA F R Phillips 3099 5 1,131 0 PA F R Phillips 3099 6 2,022 0 PA Front Street 3121 7 294 0 PA Front Street 3121 8 294 0 PA Front Street 3121 9 1,176 0 PA Front Street 3121 10 1,176 0 PA Grays Ferry Cogen 54785 2 0 9 PA Hatfields Ferry 3179 XS123 (1, 2, 3)PA Hatfields Ferry 3179 1 16,313 56,715 56,11PA Hatfields Ferry 3179 2 16,094 56,690 56,09PA Hatfields Ferry 3179 3 17,365 54,090 53,49PA Holtwood 3145 17 3,571 1 PA Homer City 3122 1 17,759 61,674 52,86PA Homer City 3122 2 16,314 51,007 50,53PA Homer City 3122 3 27,629 28,362 27,86PA Hunlock Power 3176 6 2,257 3,578 3,57PA Keystone 3136 1 28,219 77,886 77,47PA Keystone 3136 2 30,045 76,366 76,01PA Martins Creek 3148 CS102 (1, 2)PA Martins Creek 3148 1 5,457 9,919 8,82PA Martins Creek 3148 2 5,528 10,630 9,95PA Martins Creek 3148 3 13,183 4,180 4,16PA Martins Creek 3148 4 12,127 2,792 2,75PA Mitchell 3181 1 0 37 1PA Mitchell 3181 2 1 50 3PA Mitchell 3181 3 0 44 2PA Mitchell 3181 33 5,495 1,356 1,25PA Montour 3149 1 24,191 58,361 58,24PA Montour 3149 2 24,680 49,795 49,72PA New Castle 3138 1 1,292 0 PA New Castle 3138 2 1,439 0 PA New Castle 3138 3 2,843 7,871 7,61PA New Castle 3138 4 2,817 8,294 8,01PA New Castle 3138 5 4,514 9,335 9,02

A, 50
APPENDIX A: ACID RAIN PROGRAM - YEAR 2000 SO2 ALLOWANCE HOLDINGS AND DEDUCTIONS

STATE PLANT NAME

PLANT 

CODE STACK/UNIT ID*

2000 

ALLOWANCES 

ALLOCATED

HELD IN 

ACCOUNTS AS 

OF 3/1/2001

ALLOWANCES 

DEDUCTED

PA Portland 3113 1 2,560 9,056 9,03PA Portland 3113 2 4,413 11,265 11,26PA Portland 3113 5 0 2 PA Richmond 3168 63 0 0 PA Richmond 3168 64 0 0 PA Schuylkill 3169 1 572 572 12PA Seward 3130 CS2 (12, 14, 15)PA Seward 3130 12 1,096 1,096 1,09PA Seward 3130 14 1,096 1,217 1,21PA Seward 3130 15 5,002 8,593 8,58PA Shawville 3131 1 4,430 9,478 9,47PA Shawville 3131 2 4,456 10,956 10,95PA Shawville 3131 CS1 (3, 4)PA Shawville 3131 3 6,111 12,806 12,80PA Shawville 3131 4 6,070 15,033 15,02PA Southwark 3170 11 0 0 PA Southwark 3170 12 0 0 PA Southwark 3170 21 0 0 PA Southwark 3170 22 0 0 PA Springdale 3182 77 0 0 PA Springdale 3182 88 0 0 PA Sunbury 3152 3 4,029 16,527 8,00PA Sunbury 3152 4 5,250 9,654 7,80PA Sunbury 3152 CS1 (1A, 1B)PA Sunbury 3152 1A 1,818 3,718 3,43PA Sunbury 3152 1B 1,817 3,582 3,38PA Sunbury 3152 CS2 (2A, 2B)PA Sunbury 3152 2A 1,818 2,818 2,70PA Sunbury 3152 2B 1,818 3,018 2,73PA Titus 3115 1 2,150 5,459 5,45PA Titus 3115 2 2,272 4,858 4,85PA Titus 3115 3 2,195 4,991 4,98PA Warren 3132 CS3 (1, 2, 3, 4)PA Warren 3132 1 720 525 50PA Warren 3132 2 720 584 57PA Warren 3132 3 740 876 87PA Warren 3132 4 740 935 93PA Westwood 50611 031 0 350 29PA Williamsburg 3135 11 935 935 RI Manchester Street 3236 6 693 0 RI Manchester Street 3236 7 458 0 RI Manchester Street 3236 9 0 7 RI Manchester Street 3236 10 0 7 RI Manchester Street 3236 11 0 7 

A, 51
APPENDIX A: ACID RAIN PROGRAM - YEAR 2000 SO2 ALLOWANCE HOLDINGS AND DEDUCTIONS

STATE PLANT NAME

PLANT 

CODE STACK/UNIT ID*

2000 

ALLOWANCES 

ALLOCATED

HELD IN 

ACCOUNTS AS 

OF 3/1/2001

ALLOWANCES 

DEDUCTED

RI Manchester Street 3236 12 512 0 RI South Street 3238 121 1,086 0 RI South Street 3238 122 946 0 RI Tiverton 55048 1 0 33 SC Broad River Energy Center (I) 55166 CT-1 0 6 SC Broad River Energy Center (I) 55166 CT-2 0 4 SC Broad River Energy Center (I) 55166 CT-3 0 3 SC Canadys Steam 3280 CAN1 3,248 10,432 5,08SC Canadys Steam 3280 CAN2 2,979 9,976 5,72SC Canadys Steam 3280 CAN3 4,223 12,324 7,85SC Cherokee County Cogen 55043 CCCP1 0 4 SC Cope Station 7210 COP1 2,616 4,884 2,01SC Cross 130 1 5,603 4,175 2,72SC Cross 130 2 8,941 10,109 9,72SC Darlington County 3250 12 0 10 SC Darlington County 3250 13 0 10 SC Dolphus M Grainger 3317 1 3,114 4,820 4,58SC Dolphus M Grainger 3317 2 277 4,054 3,96SC H B Robinson 3251 1 3,815 7,995 7,89SC Hagood 3285 HAG1 3 0 SC Hagood 3285 HAG2 451 0 SC Hagood 3285 HAG3 787 0 SC Hagood 3285 HAG4 948 982 3SC Jefferies 3319 1 0 656 31SC Jefferies 3319 2 1 692 36SC Jefferies 3319 3 3,886 10,622 9,69SC Jefferies 3319 4 3,743 10,991 8,95SC Mcmeekin 3287 MCM1 4,080 21,805 6,77SC Mcmeekin 3287 MCM2 4,038 13,915 7,38SC Na 1 -- 7106 7106 **GT1 0 0 SC Urquhart 3295 URQ1 2,195 7,249 3,85SC Urquhart 3295 URQ2 1,927 6,957 4,09SC Urquhart 3295 URQ3 2,914 10,285 6,04SC Urquhart 3295 URQ4 0 3 SC W S Lee 3264 1 3,381 2,582 2,34SC W S Lee 3264 2 3,727 2,995 2,72SC W S Lee 3264 3 6,800 5,631 5,20SC Wateree 3297 WAT1 9,717 19,225 16,12SC Wateree 3297 WAT2 9,270 27,923 15,05SC Williams 3298 WIL1 15,821 24,517 24,20

SC Winyah 6249 1 7,574 21,442 19,64SC Winyah 6249 2 6,234 9,818 9,23SC Winyah 6249 3 3,610 4,998 4,73SC Winyah 6249 4 3,427 4,008 3,92

A, 52
APPENDIX A: ACID RAIN PROGRAM - YEAR 2000 SO2 ALLOWANCE HOLDINGS AND DEDUCTIONS

STATE PLANT NAME

PLANT 

CODE STACK/UNIT ID*

2000 

ALLOWANCES 

ALLOCATED

HELD IN 

ACCOUNTS AS 

OF 3/1/2001

ALLOWANCES 

DEDUCTED

SD Angus Anson 7237 2 851 851 SD Angus Anson 7237 3 1,020 1,020 SD Big Stone 6098 1 13,715 13,780 13,52SD Huron 3344 **2A 80 5 SD Huron 3344 **2B 103 3 SD Pathfinder 3334 11 11 11 SD Pathfinder 3334 12 2 2 SD Pathfinder 3334 13 2 2 TN Allen 3393 1 6,608 27,049 6,46TN Allen 3393 2 7,231 22,894 7,53TN Allen 3393 3 6,756 23,901 4,86TN Brownsville Power I, LLC 2387 AA-001 0 1 TN Brownsville Power I, LLC 2387 AA-002 0 1 TN Brownsville Power I, LLC 2387 AA-003 0 1 TN Brownsville Power I, LLC 2387 AA-004 0 1 TN Bull Run 3396 1 25,047 39,513 36,66TN Cumberland 3399 1 37,386 123,716 8,99TN Cumberland 3399 2 40,896 150,697 10,86TN DuPont Johnsonville 880001 JVD1 1,778 0 TN DuPont Johnsonville 880001 JVD2 1,778 0 TN DuPont Johnsonville 880001 JVD3 1,777 0 TN DuPont Johnsonville 880001 JVD4 1,777 0 TN Gallatin 3403 CSGA12 (1, 2)TN Gallatin 3403 1 7,605 18,339 17,18TN Gallatin 3403 2 7,464 18,864 17,07TN Gallatin 3403 CSGA34 (3, 4)TN Gallatin 3403 3 8,635 21,881 19,86TN Gallatin 3403 4 9,168 26,361 24,18TN Gallatin 3403 GCT5 0 500 TN Gallatin 3403 GCT6 0 500 TN Gallatin 3403 GCT7 0 500 TN Gallatin 3403 GCT8 0 500 TN Gleason Generating Facility LLC 55251 CTG-1 0 2 TN Gleason Generating Facility LLC 55251 CTG-2 0 2 TN Gleason Generating Facility LLC 55251 CTG-3 0 2 TN John Sevier 3405 CSJS12 (1, 2)TN John Sevier 3405 1 6,361 16,361 14,07TN John Sevier 3405 2 6,358 16,858 14,25TN John Sevier 3405 CSJS34 (3, 4)TN John Sevier 3405 3 6,519 14,019 12,88TN John Sevier 3405 4 6,669 15,669 14,69TN Johnsonville 3406 CSJO10 (1, 2, 3, 4, 5, 6, 7, 8, 9, 10)TN Johnsonville 3406 1 3,358 13,610 11,99TN Johnsonville 3406 2 3,465 13,874 12,04

A, 53
APPENDIX A: ACID RAIN PROGRAM - YEAR 2000 SO2 ALLOWANCE HOLDINGS AND DEDUCTIONS

STATE PLANT NAME

PLANT 

CODE STACK/UNIT ID*

2000 

ALLOWANCES 

ALLOCATED

HELD IN 

ACCOUNTS AS 

OF 3/1/2001

ALLOWANCES 

DEDUCTED

TN Johnsonville 3406 3 3,628 13,340 11,60TN Johnsonville 3406 4 3,443 13,307 11,77TN Johnsonville 3406 5 3,553 11,650 10,46TN Johnsonville 3406 6 3,404 12,806 10,98TN Johnsonville 3406 7 3,871 14,212 12,43TN Johnsonville 3406 8 3,753 15,128 13,25TN Johnsonville 3406 9 3,052 14,422 11,75TN Johnsonville 3406 10 3,256 14,079 12,11TN Johnsonville 3406 JCT17 0 500 TN Johnsonville 3406 JCT18 0 500 TN Johnsonville 3406 JCT19 0 500 TN Johnsonville 3406 JCT20 0 500 TN Kingston 3407 CSKI15 (1, 2, 3, 4, 5)TN Kingston 3407 1 4,152 10,652 9,22TN Kingston 3407 2 3,992 10,492 9,39TN Kingston 3407 3 4,751 11,751 10,08TN Kingston 3407 4 5,041 9,541 8,22TN Kingston 3407 5 6,194 12,694 11,49TN Kingston 3407 CSKI69 (6, 7, 8, 9)TN Kingston 3407 6 6,347 12,347 11,42TN Kingston 3407 7 6,189 12,189 10,89TN Kingston 3407 8 5,784 14,284 13,32TN Kingston 3407 9 6,405 14,405 12,87TN Watts Bar 3419 A 0 0 TN Watts Bar 3419 B 0 0 TN Watts Bar 3419 C 0 0 TN Watts Bar 3419 D 0 0 TX Barney M. Davis 4939 1 496 456 14TX Barney M. Davis 4939 2 398 438 42TX Bay Port 10298 CG801 0 0 TX Bay Port 10298 CG802 0 0 TX Bay Port 10298 CG803 0 0 TX Bay Port 10298 CG804 0 0 TX Big Brown 3497 1 20,985 42,985 42,40TX Big Brown 3497 2 19,878 44,093 43,59TX Blackhawk Station 55064 001 0 5 TX Blackhawk Station 55064 002 0 5 TX Bosque County Power Plant 55172 GT-1 0 5 TX Bosque County Power Plant 55172 GT-2 0 5 TX Bryan 3561 6 19 19 TX C E Newman 3574 BW5 3 3 TX Cedar Bayou 3460 CBY1 814 814 10TX Cedar Bayou 3460 CBY2 921 921 19TX Cedar Bayou 3460 CBY3 725 725 6

A, 54
APPENDIX A: ACID RAIN PROGRAM - YEAR 2000 SO2 ALLOWANCE HOLDINGS AND DEDUCTIONS

STATE PLANT NAME

PLANT 

CODE STACK/UNIT ID*

2000 

ALLOWANCES 

ALLOCATED

HELD IN 

ACCOUNTS AS 

OF 3/1/2001

ALLOWANCES 

DEDUCTED

TX Cleburne Cogeneration Facility 54817 EAST 0 5 TX Cleburne Cogeneration Facility 54817 WEST 0 0 TX Coleto Creek 6178 1 14,721 14,741 14,72TX Coleto Creek 6178 **2 0 0 TX Collin 3500 1 92 62 TX Concho 3518 7 11 11 TX Dallas 3451 3 27 0 TX Dallas 3451 9 26 0 TX Dansby 6243 1 94 94 TX Decker Creek 3548 1 128 128 1TX Decker Creek 3548 2 195 195 2TX Decordova 8063 1 1,018 218 6TX Deepwater 3461 DWP1 0 0 TX Deepwater 3461 DWP2 0 0 TX Deepwater 3461 DWP3 0 0 TX Deepwater 3461 DWP4 0 0 TX Deepwater 3461 DWP5 0 0 TX Deepwater 3461 DWP6 0 0 TX Deepwater 3461 DWP7 0 0 TX Deepwater 3461 DWP8 0 0 TX Deepwater 3461 DWP9 28 28 TX Denver City 3480 6 0 0 TX E S Joslin 3436 1 260 260 5TX Eagle Mountain 3489 1 52 52 TX Eagle Mountain 3489 2 140 90 2TX Eagle Mountain 3489 3 100 60 TX Forest Grove 6148 **1 0 0 TX Fort Phantom 4938 1 126 136 12TX Fort Phantom 4938 2 187 177 5TX Frontera Power Facility 55098 1 0 8 TX Frontera Power Facility 55098 2 0 8 TX Generic Stat 7235 **1 0 0 TX Generic Stat 7235 **2 0 0 TX Gibbons Creek 6136 1 14,414 12,567 11,63TX Graham 3490 1 235 135 5TX Graham 3490 2 496 446 37TX Greens Bayou 3464 GBY1 1 1 TX Greens Bayou 3464 GBY2 2 2 TX Greens Bayou 3464 GBY3 15 15 TX Greens Bayou 3464 GBY4 19 19 TX Greens Bayou 3464 GBY5 352 352 1TX Gregory Power Facility 55086 101 0 5 TX Gregory Power Facility 55086 102 0 5 TX Handley 3491 2 21 21 

A, 55
APPENDIX A: ACID RAIN PROGRAM - YEAR 2000 SO2 ALLOWANCE HOLDINGS AND DEDUCTIONS

STATE PLANT NAME

PLANT 

CODE STACK/UNIT ID*

2000 

ALLOWANCES 

ALLOCATED

HELD IN 

ACCOUNTS AS 

OF 3/1/2001

ALLOWANCES 

DEDUCTED

TX Handley 3491 3 423 73 TX Handley 3491 4 118 468 10TX Handley 3491 5 136 106 3TX Handley 3491 1A 7 7 TX Handley 3491 1B 0 0 TX Harrington Station 6193 061B 8,234 9,018 8,81TX Harrington Station 6193 062B 8,721 8,621 8,30TX Harrington Station 6193 063B 9,269 8,585 8,36TX Hidalgo Energy Facility 7762 HRSG1 0 2 TX Hidalgo Energy Facility 7762 HRSG2 0 2 TX Hiram Clarke 3465 HOC1 0 0 TX Hiram Clarke 3465 HOC2 0 0 TX Hiram Clarke 3465 HOC3 3 3 TX Hiram Clarke 3465 HOC4 2 2 TX Holly Ave 3602 1 59 59 TX Holly Ave 3602 2 71 71 TX Holly Street 3549 1 49 49 TX Holly Street 3549 2 31 31 TX Holly Street 3549 3 68 68 TX Holly Street 3549 4 43 43 TX J K Spruce 7097 **1 6,692 6,692 3,64TX J K Spruce 7097 **2 0 0 TX J L Bates 3438 1 48 48 2TX J L Bates 3438 2 124 124 2TX J T Deely 6181 CS012 (1, 2)TX J T Deely 6181 1 13,136 13,136 9,80TX J T Deely 6181 2 13,705 13,705 9,80TX J. Robert Massengale Generating 3604 GT1 0 0 TX Jones Station 3482 151B 125 124 TX Jones Station 3482 152B 93 93 2TX Knox Lee 3476 2 0 5 TX Knox Lee 3476 3 5 5 TX Knox Lee 3476 4 29 24 TX Knox Lee 3476 5 251 251 14TX La Palma 3442 7 178 178 9TX Lake Creek 3502 1 39 39 TX Lake Creek 3502 2 191 91 TX Lake Hubbard 3452 1 170 120 3TX Lake Hubbard 3452 2 604 204 5TX Lamar Power (Paris Generating Stati 55097 1 0 2 TX Lamar Power (Paris Generating Stati 55097 2 0 2 TX Laredo 3439 1 15 15 TX Laredo 3439 2 14 14 TX Laredo 3439 3 85 85 

A, 56
APPENDIX A: ACID RAIN PROGRAM - YEAR 2000 SO2 ALLOWANCE HOLDINGS AND DEDUCTIONS

STATE PLANT NAME

PLANT 

CODE STACK/UNIT ID*

2000 

ALLOWANCES 

ALLOCATED

HELD IN 

ACCOUNTS AS 

OF 3/1/2001

ALLOWANCES 

DEDUCTED

TX Leon Creek 3609 3 2 2 TX Leon Creek 3609 4 10 10 TX Lewis Creek 3457 1 317 7 TX Lewis Creek 3457 2 271 7 TX Limestone 298 LIM1 23,787 21,787 16,86TX Limestone 298 LIM2 14,158 16,158 15,20TX Lon C Hill 3440 1 9 9 TX Lon C Hill 3440 2 10 10 TX Lon C Hill 3440 3 179 179 TX Lon C Hill 3440 4 197 197 4TX Lone Star 3477 1 0 0 TX Malakoff 370 **1 1,539 1,539 TX Martin Lake 6146 1 33,231 26,631 16,49TX Martin Lake 6146 2 32,266 31,266 21,17TX Martin Lake 6146 3 33,436 30,436 20,39TX Midlothian Energy 55091 STK1 0 1 TX Midlothian Energy 55091 STK2 0 1 TX Mission Road 3610 3 3 3 TX Monticello 6147 1 23,641 38,641 37,58TX Monticello 6147 2 22,938 34,246 33,18TX Monticello 6147 3 35,232 18,272 17,57TX Moore County Station 3483 3 0 1 TX Morgan Creek 3492 3 8 8 TX Morgan Creek 3492 4 72 72 TX Morgan Creek 3492 5 154 154 4TX Morgan Creek 3492 6 836 136 TX Mountain Creek 3453 2 4 4 TX Mountain Creek 3453 6 63 63 2TX Mountain Creek 3453 7 62 212 17TX Mountain Creek 3453 8 527 102 TX Mountain Creek 3453 3A 11 11 TX Mountain Creek 3453 3B 2 2 TX Mustang Station 55065 1 0 5 TX Mustang Station 55065 2 0 5 TX Na 1 -- 7219 7219 **1 0 0 TX Na 1 -- 7219 7219 **2 0 0 TX Na 2 -- 4274 4274 **NA1 0 0 TX Neches 3458 11 0 0 TX Neches 3458 13 0 0 TX Neches 3458 15 0 0 TX Neches 3458 18 0 0 TX Newgulf 50137 1 0 4 TX Newman 3456 1 14 14 TX Newman 3456 2 29 29 

A, 57
APPENDIX A: ACID RAIN PROGRAM - YEAR 2000 SO2 ALLOWANCE HOLDINGS AND DEDUCTIONS

STATE PLANT NAME

PLANT 

CODE STACK/UNIT ID*

2000 

ALLOWANCES 

ALLOCATED

HELD IN 

ACCOUNTS AS 

OF 3/1/2001

ALLOWANCES 

DEDUCTED

TX Newman 3456 3 88 7 TX Newman 3456 **4 99 49 TX Newman 3456 **5 0 50 TX Nichols Station 3484 141B 77 77 TX Nichols Station 3484 142B 86 86 TX Nichols Station 3484 143B 50 50 TX North Lake 3454 1 131 131 3TX North Lake 3454 2 150 100 1TX North Lake 3454 3 294 164 3TX North Main 3493 4 42 42 TX North Texas 3627 3 13 1 TX Nueces Bay 3441 5 1 1 TX Nueces Bay 3441 6 140 140 TX Nueces Bay 3441 7 496 476 17TX O W Sommers 3611 1 478 472 TX O W Sommers 3611 2 188 188 TX Oak Creek 3523 1 106 106 TX Oklaunion 127 1 7,859 7,859 5,60TX P H Robinson 3466 PHR1 645 645 TX P H Robinson 3466 PHR2 494 494 TX P H Robinson 3466 PHR3 685 685 TX P H Robinson 3466 PHR4 796 796 TX Paint Creek 3524 1 11 21 1TX Paint Creek 3524 2 11 41 2TX Paint Creek 3524 3 28 28 TX Paint Creek 3524 4 105 125 11TX Parkdale 3455 1 34 34 TX Parkdale 3455 2 62 62 TX Parkdale 3455 3 61 61 TX Pasadena Power Plant 55047 CG-1 0 7 TX Pasadena Power Plant 55047 CG-2 0 1 TX Pasadena Power Plant 55047 CG-3 0 1 TX Permian Basin 3494 5 103 53 TX Permian Basin 3494 6 804 254 11TX Pirkey 7902 1 20,532 20,532 18,82TX Plant X 3485 111B 0 1 TX Plant X 3485 112B 2 2 TX Plant X 3485 113B 89 76 TX Plant X 3485 114B 0 12 TX Port Neches 54748 GT1 0 0 TX Powerlane Plant 4195 2 459 459 TX Powerlane Plant 4195 3 37 37 TX R W Miller 3628 1 55 1 TX R W Miller 3628 2 98 2 

A, 58
APPENDIX A: ACID RAIN PROGRAM - YEAR 2000 SO2 ALLOWANCE HOLDINGS AND DEDUCTIONS

STATE PLANT NAME

PLANT 

CODE STACK/UNIT ID*

2000 

ALLOWANCES 

ALLOCATED

HELD IN 

ACCOUNTS AS 

OF 3/1/2001

ALLOWANCES 

DEDUCTED

TX R W Miller 3628 3 218 3 TX R W Miller 3628 **4 851 1 TX R W Miller 3628 **5 851 1 TX Ray Olinger 3576 BW2 60 60 TX Ray Olinger 3576 BW3 79 79 TX Ray Olinger 3576 CE1 42 42 TX Rio Pecos 3526 5 64 44 TX Rio Pecos 3526 6 179 139 TX River Crest 3503 1 61 61 TX Sabine 3459 1 152 7 TX Sabine 3459 2 164 9 TX Sabine 3459 3 576 11 TX Sabine 3459 4 504 9 TX Sabine 3459 5 323 13 TX Sabine Cogeneration Facility 55104 SAB-1 0 1 TX Sabine Cogeneration Facility 55104 SAB-2 0 1 TX Sam Bertron 3468 SRB1 57 57 TX Sam Bertron 3468 SRB2 18 18 TX Sam Bertron 3468 SRB3 120 100 TX Sam Bertron 3468 SRB4 79 79 TX Sam Seymour 6179 1 15,910 14,982 14,15TX Sam Seymour 6179 2 17,396 16,072 14,74TX Sam Seymour 6179 3 10,494 1,746 1,73TX San Angelo 3527 2 161 161 TX San Jacinto Steam Electric Station 7325 SJS1 0 10 TX San Jacinto Steam Electric Station 7325 SJS2 0 10 TX San Miguel 6183 SM-1 17,216 17,216 12,22TX Sandow 6648 4 25,698 25,698 19,54TX Seaholm 3550 9 4 4 TX Silas Ray 3559 9 0 5 TX Sim Gideon 3601 1 47 47 TX Sim Gideon 3601 2 56 56 TX Sim Gideon 3601 3 277 277 TX Spencer 4266 4 19 19 TX Spencer 4266 5 23 23 TX Stryker Creek 3504 1 170 120 3TX Stryker Creek 3504 2 525 425 18TX Sweeny Cogeneration Facility 55015 1 0 36 TX Sweeny Cogeneration Facility 55015 2 0 12 TX Sweeny Cogeneration Facility 55015 3 0 12 TX T C Ferguson 4937 1 253 253 TX T H Wharton 3469 THW1 7 7 TX T H Wharton 3469 THW2 97 97 TX Tenaska Frontier Generating Station 55062 1 0 2 

A, 59
APPENDIX A: ACID RAIN PROGRAM - YEAR 2000 SO2 ALLOWANCE HOLDINGS AND DEDUCTIONS

STATE PLANT NAME

PLANT 

CODE STACK/UNIT ID*

2000 

ALLOWANCES 

ALLOCATED

HELD IN 

ACCOUNTS AS 

OF 3/1/2001

ALLOWANCES 

DEDUCTED

TX Tenaska Frontier Generating Station 55062 2 0 2 TX Tenaska Frontier Generating Station 55062 3 0 2 TX TNP One 7030 U1 2,123 2,624 2,35TX TNP One 7030 U2 3,500 2,999 2,69TX Tolk Station 6194 171B 14,781 14,293 13,53TX Tolk Station 6194 172B 14,444 14,932 14,66TX Tradinghouse 3506 1 593 193 TX Tradinghouse 3506 2 995 395 9TX Trinidad 3507 7 6 6 TX Trinidad 3507 8 1 1 TX Trinidad 3507 9 135 85 TX Twin Oak 6180 1 8,015 0 TX Twin Oak 6180 2 1,540 0 TX V H Braunig 3612 1 78 78 TX V H Braunig 3612 2 121 121 TX V H Braunig 3612 3 416 416 TX V H Braunig 3612 CP01 (CT01, CT02)TX V H Braunig 3612 CT01 0 3 TX V H Braunig 3612 CT02 0 3 TX Valley (Texas Utilities) 3508 1 77 77 1TX Valley (Texas Utilities) 3508 2 518 168 3TX Valley (Texas Utilities) 3508 3 124 124 TX Victoria 3443 5 6 6 TX Victoria 3443 6 8 8 TX Victoria 3443 7 110 110 1TX Victoria 3443 8 238 238 3TX W a Parish 3470 WAP1 57 57 TX W a Parish 3470 WAP2 56 56 TX W a Parish 3470 WAP3 245 245 TX W a Parish 3470 WAP4 558 558 TX W a Parish 3470 WAP5 22,878 21,378 16,20TX W a Parish 3470 WAP6 20,761 19,261 14,89TX W a Parish 3470 WAP7 15,142 19,500 18,50TX W a Parish 3470 WAP8 7,287 5,929 4,93TX W B Tuttle 3613 1 2 2 TX W B Tuttle 3613 2 19 19 TX W B Tuttle 3613 3 11 11 TX W B Tuttle 3613 4 48 48 TX Webster 3471 WEB1 14 14 TX Webster 3471 WEB2 17 17 TX Webster 3471 WEB3 343 343 TX Welsh 6139 1 13,329 14,029 14,02TX Welsh 6139 2 12,846 12,846 12,59TX Welsh 6139 3 15,220 14,520 12,84

A, 60
APPENDIX A: ACID RAIN PROGRAM - YEAR 2000 SO2 ALLOWANCE HOLDINGS AND DEDUCTIONS

STATE PLANT NAME

PLANT 

CODE STACK/UNIT ID*

2000 

ALLOWANCES 

ALLOCATED

HELD IN 

ACCOUNTS AS 

OF 3/1/2001

ALLOWANCES 

DEDUCTED

TX Wilkes 3478 1 30 30 1TX Wilkes 3478 2 118 118 TX Wilkes 3478 3 129 129 UT Bonanza 7790 1-1 10,785 1,824 1,03UT Carbon 3644 1 1,913 1,560 1,53UT Carbon 3644 2 2,499 3,094 3,06UT Gadsby 3648 1 24 2 UT Gadsby 3648 2 1,690 2 UT Gadsby 3648 3 2,265 2 UT Hale 3652 1 1 0 UT Hunter (Emery) 6165 1 7,454 2,512 2,15UT Hunter (Emery) 6165 2 7,960 2,599 1,76UT Hunter (Emery) 6165 3 11,254 1,075 1,05UT Huntington 8069 1 7,925 1,853 1,79UT Huntington 8069 2 9,753 11,339 11,31UT Intermountain 6481 1SGA 2,875 2,875 1,85UT Intermountain 6481 2SGA 2,895 2,895 1,61VA Bellemeade 50966 1 0 25 VA Bellemeade 50966 2 0 25 VA Bremo 3796 3 2,029 6,029 3,85VA Bremo 3796 4 5,160 11,160 7,67VA Chesapeake 3803 1 2,117 10,117 5,36VA Chesapeake 3803 2 2,210 8,210 5,00VA Chesapeake 3803 3 4,560 12,560 8,27VA Chesapeake 3803 4 5,872 15,872 10,66VA Chesterfield 3797 3 2,561 9,561 5,51VA Chesterfield 3797 4 4,670 10,670 6,75VA Chesterfield 3797 5 9,166 19,166 18,06VA Chesterfield 3797 6 17,139 42,139 37,14VA Chesterfield 3797 **8A 1,387 1,387 4VA Chesterfield 3797 **8B 0 0 VA Clinch River 3775 CS012 (1, 2)VA Clinch River 3775 1 5,348 8,514 8,26VA Clinch River 3775 2 6,113 8,733 8,47VA Clinch River 3775 3 5,651 9,590 9,30VA Clover 7213 1 2,938 1,900 86VA Clover 7213 2 2,938 1,900 1,05VA Commonwealth Chesapeake Pwr Station 55381 CT-001 0 10 VA Commonwealth Chesapeake Pwr Station 55381 CT-002 0 10 VA Commonwealth Chesapeake Pwr Station 55381 CT-003 0 10 VA East Chandler 7186 **2 0 0 VA Glen Lyn 3776 6 5,535 9,827 9,53VA Glen Lyn 3776 51 1,152 2,458 2,38VA Glen Lyn 3776 52 1,113 2,803 2,72

A, 61
APPENDIX A: ACID RAIN PROGRAM - YEAR 2000 SO2 ALLOWANCE HOLDINGS AND DEDUCTIONS

STATE PLANT NAME

PLANT 

CODE STACK/UNIT ID*

2000 

ALLOWANCES 

ALLOCATED

HELD IN 

ACCOUNTS AS 

OF 3/1/2001

ALLOWANCES 

DEDUCTED

VA Possum Point 3804 1 0 0 VA Possum Point 3804 2 0 10 VA Possum Point 3804 3 2,647 10,647 6,04VA Possum Point 3804 4 6,725 18,725 12,14VA Possum Point 3804 5 4,336 4,336 2,37VA Potomac River 3788 1 2,334 2,334 1,99VA Potomac River 3788 2 2,309 2,309 2,09VA Potomac River 3788 3 2,756 3,756 3,25VA Potomac River 3788 4 3,037 4,037 3,35VA Potomac River 3788 5 2,913 3,913 3,25VA Remington Combustion Turbine 7839 1 0 25 VA Remington Combustion Turbine 7839 2 0 25 VA Remington Combustion Turbine 7839 3 0 25 VA Remington Combustion Turbine 7839 4 0 25 VA Yorktown 3809 CS0 (1, 2)VA Yorktown 3809 1 4,671 14,671 9,40VA Yorktown 3809 2 4,674 17,014 11,61VA Yorktown 3809 3 6,305 10,305 7,68VT J C Mcneil 589 1 104 104 WA Centralia 3845 BW21 19,076 43,453 41,82WA Centralia 3845 BW22 20,337 50,749 41,77WA River Road 7605 1 0 12 WA Shuffleton 3858 1 0 0 WA Shuffleton 3858 2 0 0 WA Shuffleton 3858 3 0 0 WI Alma 4140 CS1 (B1, B2, B3, B4, B5)WI Alma 4140 B1 537 872 23WI Alma 4140 B2 518 898 18WI Alma 4140 B3 455 716 22WI Alma 4140 B4 1,193 8,578 1,18WI Alma 4140 B5 1,906 18,401 1,61WI Bay Front 3982 1 1,046 761 13WI Bay Front 3982 2 529 529 14WI Bay Front 3982 3 0 0 WI Bay Front 3982 4 33 33 WI Bay Front 3982 5 281 566 51WI Blount Street 3992 3 6 6 WI Blount Street 3992 5 7 7 WI Blount Street 3992 6 7 7 WI Blount Street 3992 7 1,476 1,708 1,48WI Blount Street 3992 8 1,130 2,366 2,05WI Blount Street 3992 9 1,183 8,584 3,38WI Blount Street 3992 11 1 6 WI Columbia 8023 1 15,484 16,216 15,05

A, 62
APPENDIX A: ACID RAIN PROGRAM - YEAR 2000 SO2 ALLOWANCE HOLDINGS AND DEDUCTIONS

STATE PLANT NAME

PLANT 

CODE STACK/UNIT ID*

2000 

ALLOWANCES 

ALLOCATED

HELD IN 

ACCOUNTS AS 

OF 3/1/2001

ALLOWANCES 

DEDUCTED

WI Columbia 8023 2 8,758 15,037 13,27WI Combustion Turbine 7157 **2 0 0 WI Commerce 4036 25 4 4 WI Concord 7159 **1 126 13 WI Concord 7159 **2 126 10 WI Concord 7159 **3 126 10 WI Concord 7159 **4 126 10 WI DePere Energy Center 55029 B01 0 1 WI Edgewater 4050 3 1,237 18,025 1,80WI Edgewater 4050 4 10,396 37,370 7,15WI Edgewater 4050 5 11,459 10,664 8,74WI Genoa 4143 1 8,019 22,247 8,16WI Germantown Power Plant 6253 **5 0 10 WI J P Madgett 4271 B1 7,436 14,988 5,37WI Manitowoc 4125 CS0020 (6, 7, 8)WI Manitowoc 4125 6 672 3,172 1,81WI Manitowoc 4125 7 814 814 81WI Manitowoc 4125 8 238 238 23WI Na 1 -- 7205 7205 **1 0 0 WI Na 1 -- 7205 7205 **2 0 0 WI Na 1 -- 7205 7205 **3 0 0 WI Na3 7251 **1 0 0 WI Na4 7252 **1 0 0 WI Neenah Power Plant 55135 CT01 0 3 WI Neenah Power Plant 55135 CT02 0 7 WI Nelson Dewey 4054 CS1 (1, 2)WI Nelson Dewey 4054 1 2,524 8,177 7,48WI Nelson Dewey 4054 2 2,808 10,739 6,78WI North Oak Creek 4039 1 2,119 18 WI North Oak Creek 4039 2 2,081 18 WI North Oak Creek 4039 3 2,130 18 WI North Oak Creek 4039 4 2,482 20 WI Paris 7270 **1 124 10 WI Paris 7270 **2 124 10 WI Paris 7270 **3 124 10 WI Paris 7270 **4 124 20 WI Pleasant Prairie 6170 CS1 (1, 2)WI Pleasant Prairie 6170 1 11,802 17,566 17,12WI Pleasant Prairie 6170 2 16,680 20,121 17,13WI Port Washington 4040 CS7 (1, 2, 3)WI Port Washington 4040 1 529 4,771 4,27WI Port Washington 4040 2 1,031 4,592 4,27WI Port Washington 4040 3 858 4,756 4,27WI Port Washington 4040 4 804 4,223 3,83

A, 63
APPENDIX A: ACID RAIN PROGRAM - YEAR 2000 SO2 ALLOWANCE HOLDINGS AND DEDUCTIONS

STATE PLANT NAME

PLANT 

CODE STACK/UNIT ID*

2000 

ALLOWANCES 

ALLOCATED

HELD IN 

ACCOUNTS AS 

OF 3/1/2001

ALLOWANCES 

DEDUCTED

WI Port Washington 4040 5 1,061 9 WI Pulliam 4072 CS34 (3, 4)WI Pulliam 4072 3 140 220 20WI Pulliam 4072 4 208 470 43WI Pulliam 4072 CS56 (5, 6)WI Pulliam 4072 5 764 902 81WI Pulliam 4072 6 885 1,370 1,25WI Pulliam 4072 7 2,280 1,800 1,67WI Pulliam 4072 8 3,153 2,100 1,94WI Rock River 4057 1 1,560 18,938 WI Rock River 4057 2 1,482 14,414 1WI South Fond Du Lac 7203 **CT1 639 639 WI South Fond Du Lac 7203 **CT2 39 39 WI South Fond Du Lac 7203 **CT3 39 39 WI South Fond Du Lac 7203 **CT4 0 0 WI South Oak Creek 4041 CS3 (5, 6)WI South Oak Creek 4041 5 3,885 7,399 6,72WI South Oak Creek 4041 6 4,861 9,047 8,22WI South Oak Creek 4041 CS4 (7, 8)WI South Oak Creek 4041 7 6,504 5,661 4,96WI South Oak Creek 4041 8 6,392 5,275 4,97WI Stoneman 4146 CS12 (B1, B2)WI Stoneman 4146 B1 177 427 40WI Stoneman 4146 B2 223 456 44WI Valley (WEPCO) 4042 CS1 (1, 2)WI Valley (WEPCO) 4042 1 1,805 3,330 3,00WI Valley (WEPCO) 4042 2 1,824 3,289 3,00WI Valley (WEPCO) 4042 CS2 (3, 4)WI Valley (WEPCO) 4042 3 1,954 4,461 4,10WI Valley (WEPCO) 4042 4 1,900 4,579 4,10WI West Marinette 4076 **33 765 765 WI West Marinette 4076 **34 0 5 WI Weston 4078 1 1,396 1,300 1,22WI Weston 4078 2 3,547 2,300 2,12WI Weston 4078 3 9,704 9,550 8,35WI Whitewater 55011 01 0 5 WV Albright 3942 1 1,974 5,180 5,08WV Albright 3942 2 2,054 5,255 5,15WV Albright 3942 3 4,598 12,740 12,54WV Fort Martin 3943 1 17,935 42,603 42,10WV Fort Martin 3943 2 17,767 48,452 47,95WV Harrison 3944 XS123 (1, 2, 3)WV Harrison 3944 1 20,966 2,429 2,11WV Harrison 3944 2 19,902 2,667 2,11

A, 64
APPENDIX A: ACID RAIN PROGRAM - YEAR 2000 SO2 ALLOWANCE HOLDINGS AND DEDUCTIONS

STATE PLANT NAME

PLANT 

CODE STACK/UNIT ID*

2000 

ALLOWANCES 

ALLOCATED

HELD IN 

ACCOUNTS AS 

OF 3/1/2001

ALLOWANCES 

DEDUCTED

WV Harrison 3944 3 17,898 2,435 2,11WV John E Amos 3935 CS012 (1, 2)WV John E Amos 3935 1 22,589 31,739 30,80WV John E Amos 3935 2 25,899 25,455 24,70WV John E Amos 3935 3 41,512 39,237 35,59WV Kammer 3947 CS013 (1, 2, 3)WV Kammer 3947 1 8,082 16,393 15,91WV Kammer 3947 2 8,390 14,282 13,86WV Kammer 3947 3 7,499 13,530 13,13WV Kanawha River 3936 CS012 (1, 2)WV Kanawha River 3936 1 4,462 8,545 7,93WV Kanawha River 3936 2 4,291 7,459 6,85WV Mitchell 3948 CS012 (1, 2)WV Mitchell 3948 1 18,963 31,210 30,29WV Mitchell 3948 2 19,622 24,397 23,68WV Mountaineer (1301) 6264 1 35,223 39,513 38,35WV Mt Storm 3954 CS0 (1, 2)WV Mt Storm 3954 1 18,855 72,083 53,90WV Mt Storm 3954 2 17,688 59,979 56,05WV Mt Storm 3954 3 18,296 8,471 3,11WV North Branch Power Station 7537 CS1 (1A, 1B)WV North Branch Power Station 7537 1A 0 500 25WV North Branch Power Station 7537 1B 0 500 25WV Phil Sporn 3938 CS014 (11, 21, 31, 41)WV Phil Sporn 3938 11 3,130 8,672 8,43WV Phil Sporn 3938 21 2,965 8,084 7,87WV Phil Sporn 3938 31 3,313 8,116 7,88WV Phil Sporn 3938 41 3,053 9,428 9,17WV Phil Sporn 3938 51 10,617 21,348 20,79WV Pleasants 6004 1 17,603 23,557 23,35WV Pleasants 6004 2 20,194 17,905 17,70WV Rivesville 3945 7 1,237 1,665 1,56WV Rivesville 3945 8 2,529 4,406 4,30WV Willow Island 3946 1 1,496 5,627 5,52WV Willow Island 3946 2 4,684 13,016 12,81WY Dave Johnston 4158 BW41 4,706 3,749 3,72WY Dave Johnston 4158 BW42 4,572 3,718 3,69WY Dave Johnston 4158 BW43 8,830 6,484 6,28WY Dave Johnston 4158 BW44 6,804 5,710 5,68WY Jim Bridger 8066 BW71 20,913 6,843 6,81WY Jim Bridger 8066 BW72 20,470 5,711 5,68WY Jim Bridger 8066 BW73 19,590 5,167 4,98WY Jim Bridger 8066 BW74 4,065 3,270 3,24WY Laramie River 6204 1 5,113 4,534 3,26

A, 65
APPENDIX A: ACID RAIN PROGRAM - YEAR 2000 SO2 ALLOWANCE HOLDINGS AND DEDUCTIONS

STATE PLANT NAME

PLANT 

CODE STACK/UNIT ID*

2000 

ALLOWANCES 

ALLOCATED

HELD IN 

ACCOUNTS AS 

OF 3/1/2001

ALLOWANCES 

DEDUCTED

WY Laramie River 6204 2 4,303 4,303 3,75WY Laramie River 6204 3 3,823 4,402 4,40WY Naughton 4162 1 5,203 7,295 7,27WY Naughton 4162 2 6,743 9,321 9,29WY Naughton 4162 3 5,216 4,992 4,96WY Neil Simpson II 7504 001 0 750 66WY Neil Simpson II 7504 CT1 0 4 WY Wyodak 6101 BW91 18,317 6,618 6,56* CS stands for Common Stack, which includes emissions from more than one unit. XS stands for Complex Stack, which includes emissions from one or more Common Stacks and/or Multiple Stacks (MS).

A, 66
B-1, 1

Appendix B-1: Compliance Results for All NOX Affected Units in 2000

2000

ST Plant Name Operating Utility

ORISCode Boiler

ComplianceApproach

Standard

Emission

Limit

Actual

Emission

Rate

Avg. Pla

AEL, o

Early

Election 

Limit

AL Barry Alabama Power Co. 3 1 Averaging Plan 0.40 0.53 0.46 AL Barry Alabama Power Co. 3 2 Averaging Plan 0.40 0.53 0.46 AL Barry Alabama Power Co. 3 3 Averaging Plan 0.40 0.53 0.46 AL Barry Alabama Power Co. 3 4 Averaging Plan 0.40 0.35 0.46 AL Barry Alabama Power Co. 3 5 Averaging Plan 0.40 0.35 0.46 AL Charles R Lowman Alabama Electric Coop. 56 1 Standard Limitation 0.46 0.38 AL Charles R Lowman Alabama Electric Coop. 56 2 Early Election 0.46 0.48 0.50 AL Charles R Lowman Alabama Electric Coop. 56 3 Early Election 0.46 0.47 0.50 AL Colbert Tennessee Valley Authority 47 1 Averaging Plan 0.50 0.41 0.57 AL Colbert Tennessee Valley Authority 47 2 Averaging Plan 0.50 0.41 0.57 AL Colbert Tennessee Valley Authority 47 3 Averaging Plan 0.50 0.41 0.57 AL Colbert Tennessee Valley Authority 47 4 Averaging Plan 0.50 0.41 0.57 AL Colbert Tennessee Valley Authority 47 5 Averaging Plan 0.50 0.42 0.57 AL E C Gaston Alabama Power Co. 26 1 Averaging Plan 0.50 0.46 0.46 AL E C Gaston Alabama Power Co. 26 2 Averaging Plan 0.50 0.46 0.46 AL E C Gaston Alabama Power Co. 26 3 Averaging Plan 0.50 0.45 0.46 AL E C Gaston Alabama Power Co. 26 4 Averaging Plan 0.50 0.45 0.46 AL E C Gaston Alabama Power Co. 26 5 Averaging Plan 0.45 0.41 0.46 AL Gadsden Alabama Power Co. 7 1 Averaging Plan 0.45 0.58 0.46 AL Gadsden Alabama Power Co. 7 2 Averaging Plan 0.45 0.63 0.46 AL Gorgas Alabama Power Co. 8 6 Averaging Plan 0.46 0.83 0.46 AL Gorgas Alabama Power Co. 8 7 Averaging Plan 0.46 0.83 0.46 AL Gorgas Alabama Power Co. 8 8 Averaging Plan 0.40 0.58 0.46 
Appendix B-1: Compliance Results for All NOX Affected Units in 2000

2000

ST Plant Name Operating Utility

ORISCode Boiler

ComplianceApproach

Standard

Emission

Limit

Actual

Emission

Rate

Avg. Pla

AEL, o

Early

Election 

Limit

B-1, 2

AL Gorgas Alabama Power Co. 8 9 Averaging Plan 0.40 0.36 0.46 AL Gorgas Alabama Power Co. 8 10 Averaging Plan 0.40 0.43 0.46 AL Greene County Alabama Power Co. 10 1 Averaging Plan 0.68 0.59 0.46 AL Greene County Alabama Power Co. 10 2 Averaging Plan 0.46 0.41 0.46 AL James H Miller Jr Alabama Power Co. 6002 1 Averaging Plan 0.46 0.25 0.46 AL James H Miller Jr Alabama Power Co. 6002 2 Averaging Plan 0.46 0.26 0.46 AL James H Miller Jr Alabama Power Co. 6002 3 Averaging Plan 0.46 0.32 0.46 AL James H Miller Jr Alabama Power Co. 6002 4 Averaging Plan 0.46 0.34 0.46 AL Widows Creek Tennessee Valley Authority 50 1 Averaging Plan 0.46 0.72 0.57 AL Widows Creek Tennessee Valley Authority 50 2 Averaging Plan 0.46 0.72 0.57 AL Widows Creek Tennessee Valley Authority 50 3 Averaging Plan 0.46 0.72 0.57 AL Widows Creek Tennessee Valley Authority 50 4 Averaging Plan 0.46 0.72 0.57 AL Widows Creek Tennessee Valley Authority 50 5 Averaging Plan 0.46 0.72 0.57 AL Widows Creek Tennessee Valley Authority 50 6 Averaging Plan 0.46 0.72 0.57 AL Widows Creek Tennessee Valley Authority 50 7 Averaging Plan 0.40 0.38 0.57 AL Widows Creek Tennessee Valley Authority 50 8 Averaging Plan 0.40 0.42 0.57 AR Flint Creek American Electric Power Service 6138 1 Early Election 0.46 0.28 0.50 AR Independence Entergy Arkansas, Inc. 6641 1 Early Election 0.40 0.25 0.45 AR Independence Entergy Arkansas, Inc. 6641 2 Early Election 0.40 0.26 0.45 AR White Bluff Entergy Arkansas, Inc. 6009 1 Early Election 0.40 0.43 0.45 AR White Bluff Entergy Arkansas, Inc. 6009 2 Early Election 0.40 0.33 0.45 AZ Apache Station Arizona Electric Power Coop., Inc. 160 2 Early Election 0.46 0.48 0.50 AZ Apache Station Arizona Electric Power Coop., Inc. 160 3 Early Election 0.46 0.43 0.50 AZ Cholla Arizona Public Service Co. 113 1 Early Election 0.40 0.40 0.45 
Appendix B-1: Compliance Results for All NOX Affected Units in 2000

2000

ST Plant Name Operating Utility

ORISCode Boiler

ComplianceApproach

Standard

Emission

Limit

Actual

Emission

Rate

Avg. Pla

AEL, o

Early

Election 

Limit

B-1, 3

AZ Cholla Arizona Public Service Co. 113 2 Early Election 0.40 0.37 0.45 AZ Cholla Arizona Public Service Co. 113 3 Early Election 0.40 0.32 0.45 AZ Cholla Arizona Public Service Co. 113 4 Early Election 0.40 0.28 0.45 AZ Coronado Salt River Proj. Ag. I & P Dis 6177 U1B Early Election 0.46 0.42 0.50 AZ Coronado Salt River Proj. Ag. I & P Dis 6177 U2B Early Election 0.46 0.40 0.50 AZ Irvington Tucson Electric Power Co. 126 4 Standard Limitation 0.46 0.42 AZ Navajo Salt River Proj. Ag. I & P Dis 4941 1 Early Election 0.40 0.41 0.45 AZ Navajo Salt River Proj. Ag. I & P Dis 4941 2 Early Election 0.40 0.35 0.45 AZ Navajo Salt River Proj. Ag. I & P Dis 4941 3 Early Election 0.40 0.37 0.45 AZ Springerville Tucson Electric Power Co. 8223 1 Early Election 0.40 0.39 0.45 AZ Springerville Tucson Electric Power Co. 8223 2 Early Election 0.40 0.38 0.45 CO Arapahoe Public Service Company of CO 465 1 Averaging Plan 0.80 0.71 0.80 CO Arapahoe Public Service Company of CO 465 2 Averaging Plan 0.80 0.71 0.80 CO Arapahoe Public Service Company of CO 465 3 Averaging Plan 0.80 0.66 0.80 CO Arapahoe Public Service Company of CO 465 4 Averaging Plan 0.80 0.26 0.80 CO Cameo Public Service Company of CO 468 2 Standard Limitation 0.46 0.41 CO Cherokee Public Service Company of CO 469 1 Averaging Plan 0.80 0.34 0.80 CO Cherokee Public Service Company of CO 469 2 Averaging Plan 0.80 0.80 0.80 CO Cherokee Public Service Company of Colorado 469 3 Early Election 0.46 0.38 0.50 CO Cherokee Public Service Company of Colorado 469 4 Early Election 0.40 0.34 0.45 CO Comanche Public Service Company of Colorado 470 1 Early Election 0.40 0.24 0.45 CO Comanche Public Service Company of Colorado 470 2 Early Election 0.46 0.32 0.50 CO Craig Tri-State G&T Association, Inc. 6021 C1 Early Election 0.46 0.36 0.50 CO Craig Tri-State G&T Association, Inc. 6021 C2 Early Election 0.46 0.42 0.50 
Appendix B-1: Compliance Results for All NOX Affected Units in 2000

2000

ST Plant Name Operating Utility

ORISCode Boiler

ComplianceApproach

Standard

Emission

Limit

Actual

Emission

Rate

Avg. Pla

AEL, o

Early

Election 

Limit

B-1, 4

CO Craig Tri-State G&T Association, Inc. 6021 C3 Early Election 0.46 0.36 0.50 CO Hayden Public Service Company of CO 525 H1 Standard Limitation 0.46 0.40 CO Hayden Public Service Company of CO 525 H2 Standard Limitation 0.40 0.36 CO Martin Drake Colorado Springs Utilities 492 5 Averaging Plan 0.46 0.42 0.46 CO Martin Drake Colorado Springs Utilities 492 6 Averaging Plan 0.46 0.39 0.46 CO Martin Drake Colorado Springs Utilities 492 7 Averaging Plan 0.46 0.39 0.46 CO Pawnee Public Service Company of Colorado 6248 1 Early Election 0.46 0.21 0.50 CO Rawhide Platte River Power Authority 6761 101 Early Election 0.40 0.29 0.45 CO Ray D Nixon Colorado Springs Utilities 8219 1 Early Election 0.46 0.39 0.50 CO Valmont Public Service Company of Colorado 477 5 Early Election 0.40 0.26 0.45 CT Bridgeport Harbor The United Illuminating Co. 568 BHB3 Early Election 0.40 0.25 0.45 DE Edge Moor Conectiv Delmarva Generation, Inc. 593 3 Standard Limitation 0.40 0.39 DE Edge Moor Conectiv Delmarva Generation, Inc. 593 4 Standard Limitation 0.40 0.22 DE Indian River Delmarva Power & Light Co. 594 1 Standard Limitation 0.46 0.40 DE Indian River Delmarva Power & Light Co. 594 2 Standard Limitation 0.46 0.36 DE Indian River Delmarva Power & Light Co. 594 3 Standard Limitation 0.46 0.31 DE Indian River Delmarva Power & Light Co. 594 4 Standard Limitation 0.46 0.32 FL Big Bend Tampa Electric Co. 645 BB01 Averaging Plan 0.84 0.74 0.75 FL Big Bend Tampa Electric Co. 645 BB02 Averaging Plan 0.84 0.74 0.75 FL Big Bend Tampa Electric Co. 645 BB03 Averaging Plan 0.84 0.61 0.75 FL Big Bend Tampa Electric Co. 645 BB04 Averaging Plan 0.45 0.44 0.75 FL C D McIntosh Jr City of Lakeland, Dept. of Ele 676 3 Early Election 0.46 0.48 0.50 FL Crist Gulf Power Co. 641 4 Averaging Plan 0.45 0.39 0.46 FL Crist Gulf Power Co. 641 5 Averaging Plan 0.45 0.39 0.46 
Appendix B-1: Compliance Results for All NOX Affected Units in 2000

2000

ST Plant Name Operating Utility

ORISCode Boiler

ComplianceApproach

Standard

Emission

Limit

Actual

Emission

Rate

Avg. Pla

AEL, o

Early

Election 

Limit

B-1, 5

FL Crist Gulf Power Co. 641 6 Averaging Plan 0.50 0.47 0.46 FL Crist Gulf Power Co. 641 7 Averaging Plan 0.50 0.47 0.46 FL Crystal River Florida Power Corp. 628 1 Standard Limitation 0.40 0.37 FL Crystal River Florida Power Corp. 628 2 Early Election 0.40 0.44 0.45 FL Crystal River Florida Power Corp. 628 4 Early Election 0.46 0.48 0.50 FL Crystal River Florida Power Corp. 628 5 Early Election 0.46 0.48 0.50 FL Deerhaven Gainesville Regional Utilities 663 B2 Early Election 0.46 0.48 0.50 FL F J Gannon Tampa Electric Co. 646 GB03 Averaging Plan 0.86 0.78 0.75 FL F J Gannon Tampa Electric Co. 646 GB04 Averaging Plan 0.86 0.76 0.75 FL F J Gannon Tampa Electric Co. 646 GB05 Averaging Plan 0.84 0.66 0.75 FL F J Gannon Tampa Electric Co. 646 GB06 Averaging Plan 0.84 0.79 0.75 FL Lansing Smith Gulf Power Co. 643 1 Averaging Plan 0.40 0.51 0.46 FL Lansing Smith Gulf Power Co. 643 2 Averaging Plan 0.40 0.38 0.46 FL Scholz Gulf Power Co. 642 1 Averaging Plan 0.50 0.59 0.46 FL Scholz Gulf Power Co. 642 2 Averaging Plan 0.50 0.63 0.46 FL Seminole Seminole Electric Coop. 136 1 Early Election 0.46 0.45 0.50 FL Seminole Seminole Electric Coop. 136 2 Early Election 0.46 0.39 0.50 FL St Johns River Power Jacksonville Electric Authority 207 1 Early Election 0.46 0.47 0.50 FL St Johns River Power Jacksonville Electric Authority 207 2 Early Election 0.46 0.47 0.50 FL Stanton Energy Orlando Utilities Comm. 564 1 Standard Limitation 0.46 0.43 GA Arkwright Georgia Power Co. 699 1 Averaging Plan 0.45 0.76 0.46 GA Arkwright Georgia Power Co. 699 2 Averaging Plan 0.45 0.76 0.46 GA Arkwright Georgia Power Co. 699 3 Averaging Plan 0.50 0.76 0.46 GA Arkwright Georgia Power Co. 699 4 Averaging Plan 0.50 0.76 0.46 
Appendix B-1: Compliance Results for All NOX Affected Units in 2000

2000

ST Plant Name Operating Utility

ORISCode Boiler

ComplianceApproach

Standard

Emission

Limit

Actual

Emission

Rate

Avg. Pla

AEL, o

Early

Election 

Limit

B-1, 6

GA Bowen Georgia Power Co. 703 1BLR Averaging Plan 0.45 0.41 0.46 GA Bowen Georgia Power Co. 703 2BLR Averaging Plan 0.45 0.41 0.46 GA Bowen Georgia Power Co. 703 3BLR Averaging Plan 0.45 0.42 0.46 GA Bowen Georgia Power Co. 703 4BLR Averaging Plan 0.45 0.42 0.46 GA Hammond Georgia Power Co. 708 1 Averaging Plan 0.50 0.87 0.46 GA Hammond Georgia Power Co. 708 2 Averaging Plan 0.50 0.87 0.46 GA Hammond Georgia Power Co. 708 3 Averaging Plan 0.50 0.87 0.46 GA Hammond Georgia Power Co. 708 4 Averaging Plan 0.50 0.45 0.46 GA Harllee Branch Georgia Power Co. 709 1 Averaging Plan 0.68 0.86 0.46 GA Harllee Branch Georgia Power Co. 709 2 Averaging Plan 0.50 0.77 0.46 GA Harllee Branch Georgia Power Co. 709 3 Averaging Plan 0.68 0.89 0.46 GA Harllee Branch Georgia Power Co. 709 4 Averaging Plan 0.68 0.89 0.46 GA Jack McDonough Georgia Power Co. 710 MB1 Averaging Plan 0.45 0.33 0.46 GA Jack McDonough Georgia Power Co. 710 MB2 Averaging Plan 0.45 0.33 0.46 GA Kraft Savannah Electric & Power Co. 733 1 Averaging Plan 0.45 0.48 0.46 GA Kraft Savannah Electric & Power Co. 733 2 Averaging Plan 0.45 0.48 0.46 GA Kraft Savannah Electric & Power Co. 733 3 Averaging Plan 0.45 0.48 0.46 GA McIntosh Savannah Electric & Power Co. 6124 1 Averaging Plan 0.50 0.72 0.46 GA Mitchell Georgia Power Co. 727 3 Averaging Plan 0.45 0.60 0.46 GA Scherer Georgia Power Co. 6257 1 Averaging Plan 0.40 0.41 0.46 GA Scherer Georgia Power Co. 6257 2 Averaging Plan 0.40 0.38 0.46 GA Scherer Georgia Power Co. 6257 3 Averaging Plan 0.45 0.25 0.46 GA Scherer Georgia Power Co. 6257 4 Averaging Plan/EE 0.40 0.27 0.46 / 0.4GA Wansley Oglethorpe Power Co. 6052 1 Averaging Plan 0.45 0.39 0.46 
Appendix B-1: Compliance Results for All NOX Affected Units in 2000

2000

ST Plant Name Operating Utility

ORISCode Boiler

ComplianceApproach

Standard

Emission

Limit

Actual

Emission

Rate

Avg. Pla

AEL, o

Early

Election 

Limit

B-1, 7

GA Wansley Georgia Power Co. 6052 2 Averaging Plan 0.45 0.40 0.46 GA Yates Georgia Power Co. 728 Y1BR Averaging Plan 0.45 0.42 0.46 GA Yates Georgia Power Co. 728 Y2BR Averaging Plan 0.45 0.42 0.46 GA Yates Georgia Power Co. 728 Y3BR Averaging Plan 0.45 0.42 0.46 GA Yates Georgia Power Co. 728 Y4BR Averaging Plan 0.45 0.36 0.46 GA Yates Georgia Power Co. 728 Y5BR Averaging Plan 0.45 0.36 0.46 GA Yates Georgia Power Co. 728 Y6BR Averaging Plan 0.45 0.28 0.46 GA Yates Georgia Power Co. 728 Y7BR Averaging Plan 0.45 0.28 0.46 IA Ames City of Ames 1122 7 Early Election 0.40 0.38 0.45 IA Ames City of Ames 1122 8 Early Election 0.46 0.43 0.50 IA Burlington IES Utilities, Inc. 1104 1 Averaging Plan 0.45 0.19 0.46 IA Council Bluffs MidAmerican Energy Co. 1082 1 Early Election 0.46 0.45 0.50 IA Council Bluffs MidAmerican Energy Co. 1082 2 Early Election 0.40 0.38 0.45 IA Council Bluffs Atlantic Municipal Utilities 1082 3 Early Election 0.46 0.45 0.50 IA Dubuque Interstate Power Co. 1046 1 Averaging Plan 0.46 0.68 0.46 IA Dubuque Interstate Power Co. 1046 5 Averaging Plan 0.46 0.98 0.46 IA Earl F Wisdom Corn Belt Power Coop. 1217 1 AEL Final 0.46 0.56 0.59 IA Fair Station Eastern Iowa Light and Power C 1218 2 Standard Limitation 0.46 0.39 IA George Neal North MidAmerican Energy Co. 1091 2 Early Election 0.46 0.38 0.50 IA George Neal North MidAmerican Energy Co. 1091 3 Early Election 0.46 0.46 0.50 IA George Neal South MidAmerican Energy Co. 7343 4 Early Election 0.46 0.34 0.50 IA Lansing Interstate Power Co. 1047 1 Averaging Plan 0.46 0.62 0.46 IA Lansing Interstate Power Co. 1047 2 Averaging Plan 0.46 0.62 0.46 IA Lansing Interstate Power Co. 1047 3 Averaging Plan 0.46 0.85 0.46 
Appendix B-1: Compliance Results for All NOX Affected Units in 2000

2000

ST Plant Name Operating Utility

ORISCode Boiler

ComplianceApproach

Standard

Emission

Limit

Actual

Emission

Rate

Avg. Pla

AEL, o

Early

Election 

Limit

B-1, 8

IA Lansing Interstate Power Co. 1047 4 Early Election 0.46 0.41 0.50 IA Louisa MidAmerican Energy Co. 6664 101 Early Election 0.46 0.28 0.50 IA Milton L Kapp Interstate Power Co. 1048 2 Averaging Plan 0.45 0.19 0.46 IA Muscatine City of Muscatine 1167 9 Standard Limitation 0.40 0.27 IA Ottumwa IES Utilities, Inc. 6254 1 Early Election 0.40 0.33 0.45 IA Prairie Creek IES Utilities, Inc. 1073 3 Averaging Plan 0.46 0.40 0.46 IA Prairie Creek IES Utilities, Inc. 1073 4 Averaging Plan 0.50 0.32 0.46 IA Riverside MidAmerican Energy Co. 1081 9 Standard Limitation 0.45 0.34 IA Sixth Street IES Utilities, Inc. 1058 2 Averaging Plan 0.46 0.33 0.46 IA Sixth Street IES Utilities, Inc. 1058 3 Averaging Plan 0.46 0.38 0.46 IA Sixth Street IES Utilities, Inc. 1058 4 Averaging Plan 0.46 0.45 0.46 IA Sixth Street IES Utilities, Inc. 1058 5 Averaging Plan 0.46 0.75 0.46 IA Sutherland IES Utilities, Inc. 1077 1 Averaging Plan 0.46 0.72 0.46 IA Sutherland IES Utilities, Inc. 1077 2 Averaging Plan 0.46 0.56 0.46 IL Baldwin Dynegy Midwest Generation, Inc. 889 1 Averaging Plan 0.86 0.66 0.59 IL Baldwin Dynegy Midwest Generation, Inc. 889 2 Averaging Plan 0.86 0.70 0.59 IL Baldwin Dynegy Midwest Generation, Inc. 889 3 Averaging Plan 0.45 0.21 0.59 IL Coffeen Ameren Energy Generating Co. 861 01 Averaging Plan 0.86 1.05 0.59 IL Coffeen Ameren Energy Generating Co. 861 02 Averaging Plan 0.86 1.05 0.59 IL Crawford Midwest Generation EME, LLC 867 7 Averaging Plan/EE 0.40 0.30 0.59 / 0.4IL Crawford Midwest Generation EME, LLC 867 8 Averaging Plan/EE 0.40 0.38 0.59 / 0.4IL Dallman City of Springfield, Illinois 963 33 Early Election 0.40 0.40 0.45 IL Duck Creek Central Illinois Light Co. 6016 1 AEL Final 0.46 0.54 0.58 IL E D Edwards Central Illinois Light Co. 856 1 Standard Limitation 0.46 0.46 
Appendix B-1: Compliance Results for All NOX Affected Units in 2000

2000

ST Plant Name Operating Utility

ORISCode Boiler

ComplianceApproach

Standard

Emission

Limit

Actual

Emission

Rate

Avg. Pla

AEL, o

Early

Election 

Limit

B-1, 9

IL E D Edwards Central Illinois Light Co. 856 2 AEL Final 0.46 0.44 IL E D Edwards Central Illinois Light Co. 856 3 AEL Final 0.46 0.51 0.53 IL Fisk Midwest Generation EME, LLC 886 19 Averaging Plan/EE 0.40 0.37 0.59 / 0.4IL Grand Tower Ameren Energy Generating Co. 862 07 Averaging Plan 0.50 0.75 0.59 IL Grand Tower Ameren Energy Generating Co. 862 08 Averaging Plan 0.50 0.75 0.59 IL Grand Tower Ameren Energy Generating Co. 862 09 Averaging Plan 0.50 0.71 0.59 IL Havana Dynegy Midwest Generation, Inc. 891 9 Averaging Plan 0.46 0.43 0.59 IL Hennepin Dynegy Midwest Generation, Inc. 892 1 Averaging Plan 0.40 0.37 0.59 IL Hennepin Dynegy Midwest Generation, Inc. 892 2 Averaging Plan 0.45 0.37 0.59 IL Hutsonville Ameren Energy Generating Co. 863 05 Averaging Plan 0.45 0.55 0.59 IL Hutsonville Ameren Energy Generating Co. 863 06 Averaging Plan 0.45 0.52 0.59 IL Joliet 29 Midwest Generation EME, LLC 384 71 Averaging Plan 0.40 0.18 0.59 IL Joliet 29 Midwest Generation EME, LLC 384 72 Averaging Plan 0.40 0.18 0.59 IL Joliet 29 Midwest Generation EME, LLC 384 81 Averaging Plan 0.40 0.38 0.59 IL Joliet 29 Midwest Generation EME, LLC 384 82 Averaging Plan 0.40 0.38 0.59 IL Joliet 9 Midwest Generation EME, LLC 874 5 Averaging Plan 0.86 0.68 0.59 IL Joppa Steam Electric Energy Inc. 887 1 Standard Limitation 0.45 0.20 IL Joppa Steam Electric Energy Inc. 887 2 Standard Limitation 0.45 0.20 IL Joppa Steam Electric Energy Inc. 887 3 Standard Limitation 0.45 0.19 IL Joppa Steam Electric Energy Inc. 887 4 Standard Limitation 0.45 0.19 IL Joppa Steam Electric Energy Inc. 887 5 Standard Limitation 0.45 0.19 IL Joppa Steam Electric Energy Inc. 887 6 Standard Limitation 0.45 0.19 IL Kincaid Dominion Energy Services Co. 876 1 Standard Limitation 0.86 0.75 IL Kincaid Dominion Energy Services Co. 876 2 Standard Limitation 0.86 0.75 
Appendix B-1: Compliance Results for All NOX Affected Units in 2000

2000

ST Plant Name Operating Utility

ORISCode Boiler

ComplianceApproach

Standard

Emission

Limit

Actual

Emission

Rate

Avg. Pla

AEL, o

Early

Election 

Limit

B-1, 10

IL Marion Southern Illinois Power Coop. 976 4 Standard Limitation 0.86 0.85 IL Meredosia Ameren Energy Generating Co. 864 01 Averaging Plan 0.45 0.50 0.59 IL Meredosia Ameren Energy Generating Co. 864 02 Averaging Plan 0.45 0.50 0.59 IL Meredosia Ameren Energy Generating Co. 864 03 Averaging Plan 0.45 0.50 0.59 IL Meredosia Ameren Energy Generating Co. 864 04 Averaging Plan 0.45 0.50 0.59 IL Meredosia Ameren Energy Generating Co. 864 05 Averaging Plan 0.45 0.52 0.59 IL Newton Ameren Energy Generating Co. 6017 1 Averaging Plan 0.45 0.17 0.59 IL Newton Ameren Energy Generating Co. 6017 2 Averaging Plan 0.45 0.22 0.59 IL Powerton Midwest Generation EME, LLC 879 51 Averaging Plan 0.86 0.77 0.59 IL Powerton Midwest Generation EME, LLC 879 52 Averaging Plan 0.86 0.77 0.59 IL Powerton Midwest Generation EME, LLC 879 61 Averaging Plan 0.86 0.77 0.59 IL Powerton Midwest Generation EME, LLC 879 62 Averaging Plan 0.86 0.77 0.59 IL Vermilion Dynegy Midwest Generation, Inc. 897 1 Averaging Plan 0.45 0.46 0.59 IL Vermilion Dynegy Midwest Generation, Inc. 897 2 Averaging Plan 0.45 0.46 0.59 IL Waukegan Midwest Generation EME, LLC 883 7 Averaging Plan/EE 0.40 0.26 0.59 / 0.4IL Waukegan Midwest Generation EME, LLC 883 8 Averaging Plan/EE 0.40 0.15 0.59 / 0.4IL Will County Midwest Generation EME, LLC 884 1 Averaging Plan 0.86 0.84 0.59 IL Will County Midwest Generation EME, LLC 884 2 Averaging Plan 0.86 0.85 0.59 IL Will County Midwest Generation EME, LLC 884 3 Averaging Plan/EE 0.40 0.33 0.59 / 0.4IL Will County Midwest Generation EME, LLC 884 4 Early Election 0.40 0.18 0.45 IL Wood River Dynegy Midwest Generation, Inc. 898 4 Averaging Plan 0.40 0.70 0.59 IL Wood River Dynegy Midwest Generation, Inc. 898 5 Averaging Plan 0.40 0.55 0.59 IN A B Brown Southern Indiana Gas & Electric Co. 6137 1 Early Election 0.46 0.40 0.50 IN A B Brown Southern Indiana Gas & Electric Co. 6137 2 Early Election 0.46 0.45 0.50 
Appendix B-1: Compliance Results for All NOX Affected Units in 2000

2000

ST Plant Name Operating Utility

ORISCode Boiler

ComplianceApproach

Standard

Emission

Limit

Actual

Emission

Rate

Avg. Pla

AEL, o

Early

Election 

Limit

B-1, 11

IN Bailly Northern Indiana Public Service Co. 995 7 Averaging Plan 0.86 1.29 0.75 IN Bailly Northern Indiana Public Service Co. 995 8 Averaging Plan 0.86 1.29 0.75 IN Cayuga PSI Energy, Inc. 1001 1 Averaging Plan 0.45 0.32 0.49 IN Cayuga PSI Energy, Inc. 1001 2 Averaging Plan 0.45 0.30 0.49 IN Clifty Creek Indiana-Kentucky Electric Corp. 983 1 Averaging Plan 0.84 0.75 0.84 IN Clifty Creek Indiana-Kentucky Electric Corp. 983 2 Averaging Plan 0.84 0.75 0.84 IN Clifty Creek Indiana-Kentucky Electric Corp. 983 3 Averaging Plan 0.84 0.75 0.84 IN Clifty Creek Indiana-Kentucky Electric Corp. 983 4 Averaging Plan 0.84 0.73 0.84 IN Clifty Creek Indiana-Kentucky Electric Corp. 983 5 Averaging Plan 0.84 0.73 0.84 IN Clifty Creek Indiana-Kentucky Electric Corp. 983 6 Averaging Plan 0.84 0.73 0.84 IN Dean H Mitchell Northern Indiana Public Service Co. 996 4 Early Election 0.40 0.29 0.45 IN Dean H Mitchell Northern Indiana Public Service Co. 996 5 Early Election 0.40 0.29 0.45 IN Dean H Mitchell Northern Indiana Public Service Co. 996 6 Early Election 0.40 0.26 0.45 IN Dean H Mitchell Northern Indiana Public Service Co. 996 11 Early Election 0.46 0.26 0.50 IN Edwardsport PSI Energy, Inc. 1004 7-1 Averaging Plan 0.46 0.72 0.49 IN Edwardsport PSI Energy, Inc. 1004 7-2 Averaging Plan 0.46 0.67 0.49 IN Edwardsport PSI Energy, Inc. 1004 8-1 Averaging Plan 0.46 0.67 0.49 IN Elmer W Stout Indianapolis Power & Light Co. 990 50 Averaging Plan 0.45 0.37 0.45 IN Elmer W Stout Indianapolis Power & Light Co. 990 60 Averaging Plan 0.45 0.36 0.45 IN Elmer W Stout Indianapolis Power & Light Co. 990 70 Averaging Plan 0.45 0.32 0.45 IN F B Culley Southern Indiana Gas & Elec Co. 1012 1 Averaging Plan 0.46 0.72 0.50 IN F B Culley Southern Indiana Gas & Elec Co. 1012 2 Averaging Plan 0.50 0.46 0.50 IN F B Culley Southern Indiana Gas & Elec Co. 1012 3 Averaging Plan 0.50 0.46 0.50 IN Frank E Ratts Hoosier Energy R E C Inc. 1043 1SG1 Averaging Plan 0.50 0.50 0.47 
Appendix B-1: Compliance Results for All NOX Affected Units in 2000

2000

ST Plant Name Operating Utility

ORISCode Boiler

ComplianceApproach

Standard

Emission

Limit

Actual

Emission

Rate

Avg. Pla

AEL, o

Early

Election 

Limit

B-1, 12

IN Frank E Ratts Hoosier Energy R E C Inc. 1043 2SG1 Averaging Plan 0.50 0.47 0.47 IN Gibson PSI Energy, Inc. 6113 1 Averaging Plan 0.50 0.45 0.49 IN Gibson PSI Energy, Inc. 6113 2 Averaging Plan 0.50 0.45 0.49 IN Gibson PSI Energy, Inc. 6113 3 Averaging Plan 0.50 0.46 0.49 IN Gibson PSI Energy, Inc. 6113 4 Averaging Plan 0.50 0.43 0.49 IN Gibson PSI Energy, Inc. 6113 5 Averaging Plan 0.46 0.42 0.49 IN H T Pritchard Indianapolis Power & Light Co. 991 3 Averaging Plan 0.45 0.68 0.45 IN H T Pritchard Indianapolis Power & Light Co. 991 4 Averaging Plan 0.45 0.68 0.45 IN H T Pritchard Indianapolis Power & Light Co. 991 5 Averaging Plan 0.45 0.41 0.45 IN H T Pritchard Indianapolis Power & Light Co. 991 6 Averaging Plan 0.45 0.41 0.45 IN Merom Hoosier Energy R E C Inc. 6213 1SG1 Averaging Plan/EE 0.46 0.39 0.47 / 0.5IN Merom Hoosier Energy R E C Inc. 6213 2SG1 Averaging Plan/EE 0.46 0.36 0.47 / 0.5IN Michigan City Northern Indiana Public Service Co. 997 12 Averaging Plan 0.86 0.51 0.75 IN Noblesville PSI Energy, Inc. 1007 1 Averaging Plan 0.46 0.93 0.49 IN Noblesville PSI Energy, Inc. 1007 2 Averaging Plan 0.46 0.89 0.49 IN Noblesville PSI Energy, Inc. 1007 3 Averaging Plan 0.46 0.93 0.49 IN Petersburg Indianapolis Power & Light Co. 994 1 Averaging Plan 0.45 0.29 0.45 IN Petersburg Indianapolis Power & Light Co. 994 2 Averaging Plan 0.45 0.32 0.45 IN Petersburg Indianapolis Power & Light Co. 994 3 Averaging Plan 0.45 0.36 0.45 IN Petersburg Indianapolis Power & Light Co. 994 4 Averaging Plan 0.45 0.32 0.45 IN R Gallagher PSI Energy, Inc. 1008 1 Averaging Plan 0.50 0.44 0.49 IN R Gallagher PSI Energy, Inc. 1008 2 Averaging Plan 0.50 0.44 0.49 IN R Gallagher PSI Energy, Inc. 1008 3 Averaging Plan 0.50 0.41 0.49 IN R Gallagher PSI Energy, Inc. 1008 4 Averaging Plan 0.50 0.41 0.49 
Appendix B-1: Compliance Results for All NOX Affected Units in 2000

2000

ST Plant Name Operating Utility

ORISCode Boiler

ComplianceApproach

Standard

Emission

Limit

Actual

Emission

Rate

Avg. Pla

AEL, o

Early

Election 

Limit

B-1, 13

IN R M Schahfer Northern Indiana Public Service Co. 6085 14 Averaging Plan 0.86 0.57 0.75 IN R M Schahfer Northern Indiana Public Service Co. 6085 15 Averaging Plan/EE 0.46 0.26 0.75 / 0.5IN R M Schahfer Northern Indiana Public Service Co. 6085 17 Early Election 0.40 0.36 0.45 IN R M Schahfer Northern Indiana Public Service Co. 6085 18 Early Election 0.40 0.35 0.45 IN Rockport American Electric Power Genera 6166 MB1 Averaging Plan/EE 0.46 0.40 0.61 / 0.5IN Rockport Passive Lessors 6166 MB2 Averaging Plan/EE 0.46 0.40 0.61 / 0.5IN State Line Mirant State Line Energy, LLC 981 3 Averaging Plan/EE 0.40 0.21 0.68 / 0.4IN State Line Mirant State Line Energy, LLC 981 4 Averaging Plan 0.86 0.83 0.68 IN Tanners Creek Indiana Michigan Power Co. 988 U1 Averaging Plan 0.80 0.70 0.61 IN Tanners Creek Indiana Michigan Power Co. 988 U2 Averaging Plan 0.80 0.70 0.61 IN Tanners Creek Indiana Michigan Power Co. 988 U3 Averaging Plan 0.80 0.70 0.61 IN Tanners Creek Indiana Michigan Power Co. 988 U4 Averaging Plan 0.86 1.50 0.61 IN Wabash River PSI Energy, Inc. 1010 1 Averaging Plan 0.50 0.14 0.49 IN Wabash River PSI Energy, Inc. 1010 2 Averaging Plan 0.50 0.51 0.49 IN Wabash River PSI Energy, Inc. 1010 3 Averaging Plan 0.50 0.64 0.49 IN Wabash River PSI Energy, Inc. 1010 4 Averaging Plan 0.46 0.61 0.49 IN Wabash River PSI Energy, Inc. 1010 5 Averaging Plan 0.50 0.63 0.49 IN Wabash River PSI Energy, Inc. 1010 6 Averaging Plan 0.45 0.36 0.49 IN Warrick AGC Div of Alcoa Pwr Gen, Inc. 6705 4 Standard Limitation 0.68 0.45 IN Whitewater Valley City of Richmond, Indiana 1040 1 Early Election 0.46 0.44 0.50 IN Whitewater Valley City of Richmond, Indiana 1040 2 Early Election 0.40 0.44 0.45 KS Holcomb Sunflower Electric Power Corp. 108 SGU1 Standard Limitation 0.46 0.27 KS Jeffrey Energy Centre Western Resources, Inc. 6068 1 Averaging Plan 0.40 0.39 0.40 KS Jeffrey Energy Centre Western Resources, Inc. 6068 2 Averaging Plan 0.40 0.36 0.40 
Appendix B-1: Compliance Results for All NOX Affected Units in 2000

2000

ST Plant Name Operating Utility

ORISCode Boiler

ComplianceApproach

Standard

Emission

Limit

Actual

Emission

Rate

Avg. Pla

AEL, o

Early

Election 

Limit

B-1, 14

KS Jeffrey Energy Centre Western Resources, Inc. 6068 3 Averaging Plan 0.40 0.31 0.40 KS La Cygne Kansas City Power & Light Co. 1241 1 Averaging Plan 0.86 0.97 0.66 KS La Cygne Kansas City Power & Light Co. 1241 2 Averaging Plan 0.50 0.31 0.66 KS Lawrence Western Resources, Inc. 1250 3 Averaging Plan 0.40 0.33 0.40 KS Lawrence Western Resources, Inc. 1250 4 Averaging Plan 0.40 0.44 0.40 KS Lawrence Western Resources, Inc. 1250 5 Averaging Plan 0.40 0.36 0.40 KS Nearman Creek Board of Public Utilities, Kansas 6064 N1 Early Election 0.46 0.42 0.50 KS Quindaro K.C. Board of Public Utilities 1295 1 Standard Limitation 0.86 0.81 KS Quindaro K.C. Board of Public Utilities 1295 2 Standard Limitation 0.50 0.27 KS Riverton Empire District Electric Co. 1239 39 Early Election 0.46 0.47 0.50 KS Riverton Empire District Electric Co. 1239 40 Early Election 0.40 0.42 0.45 KS Tecumseh Western Resources, Inc. 1252 9 Averaging Plan 0.40 0.40 0.40 KS Tecumseh Western Resources, Inc. 1252 10 Averaging Plan 0.40 0.41 0.40 KY Big Sandy Kentucky Power Co. 1353 BSU1 Averaging Plan 0.46 0.54 0.61 KY Big Sandy Kentucky Power Co. 1353 BSU2 AEL Final 0.46 0.55 0.57 KY Cane Run Louisville Gas and Electric Co. 1363 4 Early Election 0.46 0.44 0.50 KY Cane Run Louisville Gas and Electric Co. 1363 5 Early Election 0.46 0.45 0.50 KY Cane Run Louisville Gas and Electric Co. 1363 6 Early Election 0.40 0.32 0.45 KY Coleman Big Rivers Electric Corp. 1381 C1 Averaging Plan 0.50 0.42 0.49 KY Coleman Big Rivers Electric Corp. 1381 C2 Averaging Plan 0.50 0.44 0.49 KY Coleman Big Rivers Electric Corp. 1381 C3 Averaging Plan 0.50 0.43 0.49 KY Cooper East Kentucky Power Coop. Inc. 1384 1 Standard Limitation 0.50 0.42 KY Cooper East Kentucky Power Coop. Inc. 1384 2 Standard Limitation 0.50 0.42 KY D B Wilson Big Rivers Electric Corp. 6823 W1 Averaging Plan 0.46 0.43 0.49 / 0.5
Appendix B-1: Compliance Results for All NOX Affected Units in 2000

2000

ST Plant Name Operating Utility

ORISCode Boiler

ComplianceApproach

Standard

Emission

Limit

Actual

Emission

Rate

Avg. Pla

AEL, o

Early

Election 

Limit

B-1, 15

KY Dale East Kentucky Power Coop., Inc. 1385 3 Early Election 0.46 0.36 0.50 KY Dale East Kentucky Power Coop., Inc. 1385 4 Early Election 0.46 0.36 0.50 KY E W Brown Kentucky Utilities Co. 1355 1 Averaging Plan 0.50 0.51 0.45 KY E W Brown Kentucky Utilities Co. 1355 2 Averaging Plan 0.45 0.38 0.45 KY E W Brown Kentucky Utilities Co. 1355 3 Averaging Plan 0.45 0.38 0.45 KY East Bend Cincinnati Gas & Electric Co. 6018 2 Averaging Plan 0.50 0.37 0.49 KY Elmer Smith City of Owensboro 1374 2 Standard Limitation 0.45 0.39 KY Ghent Kentucky Utilities Co. 1356 1 Averaging Plan 0.45 0.42 0.45 KY Ghent Kentucky Utilities Co. 1356 2 Averaging Plan 0.40 0.35 0.45 KY Ghent Kentucky Utilities Co. 1356 3 Averaging Plan 0.46 0.33 0.45 KY Ghent Kentucky Utilities Co. 1356 4 Averaging Plan 0.46 0.33 0.45 KY Green River Kentucky Utilities Co. 1357 1 Averaging Plan 0.46 0.69 0.45 KY Green River Kentucky Utilities Co. 1357 2 Averaging Plan 0.46 0.69 0.45 KY Green River Kentucky Utilities Co. 1357 3 Averaging Plan 0.46 0.69 0.45 KY Green River Kentucky Utilities Co. 1357 4 Averaging Plan 0.46 0.75 0.45 KY Green River Kentucky Utilities Co. 1357 5 Averaging Plan 0.50 0.39 0.45 KY H L Spurlock East Kentucky Power Coop. Inc. 6041 1 Standard Limitation 0.50 0.42 KY H L Spurlock East Kentucky Power Coop., Inc. 6041 2 Early Election 0.40 0.40 0.45 KY HMP&L Station 2 City of Henderson 1382 H1 Averaging Plan 0.50 0.46 0.49 KY HMP&L Station 2 City of Henderson 1382 H2 Averaging Plan 0.50 0.48 0.49 KY Mill Creek Louisville Gas and Electric Co. 1364 1 Early Election 0.40 0.30 0.45 KY Mill Creek Louisville Gas and Electric Co. 1364 2 Early Election 0.40 0.34 0.45 KY Mill Creek Louisville Gas and Electric Co. 1364 3 Early Election 0.46 0.40 0.50 KY Mill Creek Louisville Gas and Electric Co. 1364 4 Early Election 0.46 0.43 0.50 
Appendix B-1: Compliance Results for All NOX Affected Units in 2000

2000

ST Plant Name Operating Utility

ORISCode Boiler

ComplianceApproach

Standard

Emission

Limit

Actual

Emission

Rate

Avg. Pla

AEL, o

Early

Election 

Limit

B-1, 16

KY Paradise Tennessee Valley Authority 1378 1 Averaging Plan 0.86 0.66 0.57 KY Paradise Tennessee Valley Authority 1378 2 Averaging Plan 0.86 0.72 0.57 KY Paradise Tennessee Valley Authority 1378 3 Averaging Plan 0.86 1.16 0.57 KY Pineville Kentucky Utilities Co. 1360 3 Averaging Plan 0.46 0.61 0.45 KY R D Green Big Rivers Electric Corp. 6639 G1 Averaging Plan 0.50 0.41 0.49 KY R D Green Big Rivers Electric Corp. 6639 G2 Averaging Plan 0.50 0.42 0.49 KY Robert Reid Big Rivers Electric Corp. 1383 R1 Averaging Plan 0.46 0.81 0.49 KY Shawnee Tennessee Valley Authority 1379 1 Averaging Plan 0.46 0.39 0.57 KY Shawnee Tennessee Valley Authority 1379 2 Averaging Plan 0.46 0.39 0.57 KY Shawnee Tennessee Valley Authority 1379 3 Averaging Plan 0.46 0.39 0.57 KY Shawnee Tennessee Valley Authority 1379 4 Averaging Plan 0.46 0.39 0.57 KY Shawnee Tennessee Valley Authority 1379 5 Averaging Plan 0.46 0.39 0.57 KY Shawnee Tennessee Valley Authority 1379 6 Averaging Plan 0.46 0.37 0.57 KY Shawnee Tennessee Valley Authority 1379 7 Averaging Plan 0.46 0.37 0.57 KY Shawnee Tennessee Valley Authority 1379 8 Averaging Plan 0.46 0.37 0.57 KY Shawnee Tennessee Valley Authority 1379 9 Averaging Plan 0.46 0.37 0.57 KY Trimble County Louisville Gas and Electric Co. 6071 1 Early Election 0.40 0.39 0.45 KY Tyrone Kentucky Utilities Co. 1361 5 Averaging Plan 0.46 0.64 0.45 LA Big Cajun 2 Louisiana Generating, LLC 6055 2B1 Early Election 0.46 0.31 0.50 LA Big Cajun 2 Louisiana Generating, LLC 6055 2B2 Early Election 0.46 0.33 0.50 LA Big Cajun 2 Louisiana Generating, LLC 6055 2B3 Early Election 0.46 0.29 0.50 LA Dolet Hills CLECO Power, LLC 51 1 Early Election 0.46 0.45 0.50 LA R S Nelson Entergy Gulf States, Inc. 1393 6 Early Election 0.40 0.33 0.45 LA Rodemacher CLECO Power, LLC 6190 2 Early Election 0.46 0.43 0.50 
Appendix B-1: Compliance Results for All NOX Affected Units in 2000

2000

ST Plant Name Operating Utility

ORISCode Boiler

ComplianceApproach

Standard

Emission

Limit

Actual

Emission

Rate

Avg. Pla

AEL, o

Early

Election 

Limit

B-1, 17

MA Brayton Point USGen New England, Inc. 1619 1 Standard Limitation 0.40 0.30 MA Brayton Point USGen New England, Inc. 1619 2 Standard Limitation 0.40 0.29 MA Brayton Point USGen New England, Inc. 1619 3 Standard Limitation 0.46 0.41 MA Mount Tom Holyoke Water Power Co. 1606 1 Standard Limitation 0.46 0.36 MA Salem Harbor USGen New England, Inc. 1626 1 Standard Limitation 0.46 0.31 MA Salem Harbor USGen New England, Inc. 1626 2 Standard Limitation 0.46 0.31 MA Salem Harbor USGen New England, Inc. 1626 3 Standard Limitation 0.46 0.31 MA Somerset Somerset Operations Inc. 1613 7 Standard Limitation 0.40 Not Oper. MA Somerset Somerset Operations Inc. 1613 8 Standard Limitation 0.40 0.31 MD Brandon Shores Constellation Pwr Source Gen 602 1 Averaging Plan 0.46 0.41 0.56 MD Brandon Shores Constellation Pwr Source Gen 602 2 Averaging Plan 0.46 0.42 0.56 MD C P Crane Constellation Pwr Source Gen 1552 1 Averaging Plan 0.86 1.06 0.56 MD C P Crane Constellation Pwr Source Gen 1552 2 Averaging Plan 0.86 0.92 0.56 MD Chalk Point Southern Energy Mid Atlantic 1571 1 AEL Final 0.50 0.63 0.86 MD Chalk Point Southern Energy Mid Atlantic 1571 2 AEL Final 0.50 0.60 1.20 MD Dickerson Southern Energy Mid Atlantic 1572 1 AEL Final 0.40 0.45 0.48 MD Dickerson Southern Energy Mid Atlantic 1572 2 AEL Final 0.40 0.49 0.51 MD Dickerson Southern Energy Mid Atlantic 1572 3 AEL Final 0.40 0.44 0.47 MD Herbert A Wagner Constellation Pwr Source Gen 1554 2 Averaging Plan 0.46 0.60 0.56 MD Herbert A Wagner Constellation Pwr Source Gen 1554 3 Averaging Plan 0.68 0.35 0.56 MD Morgantown Southern Energy Mid Atlantic 1573 1 AEL Final 0.45 0.51 0.70 MD Morgantown Southern Energy Mid Atlantic 1573 2 AEL Final 0.45 0.48 0.70 MD R P Smith Allegheny Energy Supply Co., LL 1570 9 Averaging Plan 0.50 0.70 0.56 MD R P Smith Allegheny Energy Supply Co., LL 1570 11 Averaging Plan 0.45 0.41 0.56 
Appendix B-1: Compliance Results for All NOX Affected Units in 2000

2000

ST Plant Name Operating Utility

ORISCode Boiler

ComplianceApproach

Standard

Emission

Limit

Actual

Emission

Rate

Avg. Pla

AEL, o

Early

Election 

Limit

B-1, 18

MI B C Cobb Consumers Energy Co. 1695 1 Standard Limitation 0.40 0.09 MI B C Cobb Consumers Energy Co. 1695 2 Standard Limitation 0.40 0.05 MI B C Cobb Consumers Energy Co. 1695 3 Standard Limitation 0.40 0.09 MI B C Cobb Consumers Energy Co. 1695 4 Averaging Plan/EE 0.40 0.34 0.46/0.4MI B C Cobb Consumers Energy Co. 1695 5 Averaging Plan/EE 0.40 0.37 0.46/0.4MI Belle River Detroit Edison Co. 6034 1 Averaging Plan 0.46 0.27 0.53 MI Belle River Detroit Edison Co. 6034 2 Averaging Plan 0.46 0.26 0.53 MI Dan E Karn Consumers Energy Co. 1702 1 Averaging Plan 0.40 0.45 0.46 MI Dan E Karn Consumers Energy Co. 1702 2 Averaging Plan 0.46 0.26 0.46 MI Eckert Station Lansing Board of Water & Light 1831 1 Averaging Plan 0.46 0.49 0.45 MI Eckert Station Lansing Board of Water & Light 1831 2 Averaging Plan 0.40 0.35 0.45 MI Eckert Station Lansing Board of Water & Light 1831 3 Averaging Plan 0.40 0.39 0.45 MI Eckert Station Lansing Board of Water & Light 1831 4 Averaging Plan 0.46 0.39 0.45 MI Eckert Station Lansing Board of Water & Light 1831 5 Averaging Plan 0.46 0.32 0.45 MI Eckert Station Lansing Board of Water & Light 1831 6 Averaging Plan 0.46 0.36 0.45 MI Endicott Generating Village of Clinton, Michigan 4259 1 Standard Limitation 0.46 0.40 MI Erickson Lansing Board of Water & Light 1832 1 Averaging Plan 0.46 0.42 0.45 MI Harbor Beach Detroit Edison Co. 1731 1 Averaging Plan 0.46 0.88 0.53 MI J B Sims City of Grand Haven 1825 3 Early Election 0.46 0.38 0.50 MI J C Weadock Consumers Energy Co. 1720 7 Averaging Plan/EE 0.40 0.30 0.46 / 0.4MI J C Weadock Consumers Energy Co. 1720 8 Averaging Plan/EE 0.40 0.31 0.46 / 0.4MI J H Campbell Consumers Energy Co. 1710 1 AEL Final 0.45 0.43 0.55 MI J H Campbell Consumers Energy Co. 1710 2 Averaging Plan 0.68 0.88 0.46 MI J H Campbell Bay City Electric Light and Power 1710 3 Averaging Plan 0.46 0.33 0.46 
Appendix B-1: Compliance Results for All NOX Affected Units in 2000

2000

ST Plant Name Operating Utility

ORISCode Boiler

ComplianceApproach

Standard

Emission

Limit

Actual

Emission

Rate

Avg. Pla

AEL, o

Early

Election 

Limit

B-1, 19

MI J R Whiting Consumers Energy Co. 1723 1 Averaging Plan/EE 0.46 0.27 0.46 / 0.5MI J R Whiting Consumers Energy Co. 1723 2 Averaging Plan 0.46 0.34 0.46 MI J R Whiting Consumers Energy Co. 1723 3 Averaging Plan/EE 0.46 0.32 0.46 / 0.5MI James De Young City of Holland 1830 5 Standard Limitation 0.46 0.42 MI Marysville Detroit Edison Co. 1732 9 Averaging Plan 0.40 0.34 0.53 MI Marysville Detroit Edison Co. 1732 10 Averaging Plan 0.40 0.34 0.53 MI Marysville Detroit Edison Co. 1732 11 Averaging Plan 0.40 0.35 0.53 MI Marysville Detroit Edison Co. 1732 12 Averaging Plan 0.40 0.35 0.53 MI Monroe Detroit Edison Co. 1733 1 Averaging Plan 0.68 0.53 0.53 MI Monroe Detroit Edison Co. 1733 2 Averaging Plan 0.68 0.53 0.53 MI Monroe Detroit Edison Co. 1733 3 Averaging Plan 0.68 0.53 0.53 MI Monroe Detroit Edison Co. 1733 4 Averaging Plan 0.68 0.53 0.53 MI Presque Isle Wisconsin Electric Power Co. 1769 2 Averaging Plan 0.40 0.64 0.47 MI Presque Isle Wisconsin Electric Power Co. 1769 3 Averaging Plan 0.40 0.64 0.47 MI Presque Isle Wisconsin Electric Power Co. 1769 4 Averaging Plan 0.40 0.64 0.47 MI Presque Isle Wisconsin Electric Power Co. 1769 5 Averaging Plan 0.46 0.82 0.47 MI Presque Isle Wisconsin Electric Power Co. 1769 6 Averaging Plan 0.46 0.86 0.47 MI Presque Isle Wisconsin Electric Power Co. 1769 7 Early Election 0.46 0.48 0.50 MI Presque Isle Wisconsin Electric Power Co. 1769 8 Early Election 0.46 0.49 0.50 MI Presque Isle Wisconsin Electric Power Co. 1769 9 Early Election 0.46 0.48 0.50 MI River Rouge Detroit Edison Co. 1740 2 Averaging Plan 0.40 0.39 0.53 MI River Rouge Detroit Edison Co. 1740 3 Averaging Plan 0.46 0.42 0.53 MI Shiras Marquette Board of Light & Power 1843 3 Standard Limitation 0.40 0.18 MI St Clair Detroit Edison Co. 1743 1 Averaging Plan 0.46 0.68 0.53 
Appendix B-1: Compliance Results for All NOX Affected Units in 2000

2000

ST Plant Name Operating Utility

ORISCode Boiler

ComplianceApproach

Standard

Emission

Limit

Actual

Emission

Rate

Avg. Pla

AEL, o

Early

Election 

Limit

B-1, 20

MI St Clair Detroit Edison Co. 1743 2 Averaging Plan 0.46 0.31 0.53 MI St Clair Detroit Edison Co. 1743 3 Averaging Plan 0.46 0.68 0.53 MI St Clair Detroit Edison Co. 1743 4 Averaging Plan 0.46 0.71 0.53 MI St Clair Detroit Edison Co. 1743 6 Averaging Plan 0.40 0.22 0.53 MI St Clair Detroit Edison Co. 1743 7 Averaging Plan 0.40 0.42 0.53 MI Trenton Channel Detroit Edison Co. 1745 9A Averaging Plan 0.40 0.32 0.53 MI Trenton Channel Detroit Edison Co. 1745 16 Averaging Plan 0.40 0.42 0.53 MI Trenton Channel Detroit Edison Co. 1745 17 Averaging Plan 0.40 0.42 0.53 MI Trenton Channel Detroit Edison Co. 1745 18 Averaging Plan 0.40 0.42 0.53 MI Trenton Channel Detroit Edison Co. 1745 19 Averaging Plan 0.40 0.42 0.53 MI Wyandotte Wyandotte Municipal Service Co. 1866 7 Standard Limitation 0.46 0.50 MN Allen S King NSP (d/b/a Xcel Energy) 1915 1 Averaging Plan 0.86 0.71 0.54 MN Black Dog NSP (d/b/a Xcel Energy) 1904 1 Averaging Plan 0.40 0.76 0.54 MN Black Dog NSP (d/b/a Xcel Energy) 1904 3 Averaging Plan 0.46 0.76 0.54 MN Black Dog NSP (d/b/a Xcel Energy) 1904 4 Averaging Plan 0.46 0.76 0.54 MN Clay Boswell Minnesota Power and Light Co. 1893 1 Averaging Plan 0.46 0.43 0.41 MN Clay Boswell Minnesota Power and Light Co. 1893 2 Averaging Plan 0.46 0.43 0.41 MN Clay Boswell Minnesota Power and Light Co. 1893 3 Early Election 0.40 0.38 0.45 MN Clay Boswell Minnesota Power and Light Co. 1893 4 Averaging Plan 0.46 0.28 0.41 MN High Bridge NSP (d/b/a Xcel Energy) 1912 3 Averaging Plan 0.50 0.58 0.54 MN High Bridge NSP (d/b/a Xcel Energy) 1912 4 Averaging Plan 0.50 0.58 0.54 MN High Bridge NSP (d/b/a Xcel Energy) 1912 5 Averaging Plan 0.50 0.58 0.54 MN High Bridge NSP (d/b/a Xcel Energy) 1912 6 Averaging Plan 0.50 0.58 0.54 MN Hoot Lake Otter Tail Power Co. 1943 2 Early Election 0.40 0.44 0.45 
Appendix B-1: Compliance Results for All NOX Affected Units in 2000

2000

ST Plant Name Operating Utility

ORISCode Boiler

ComplianceApproach

Standard

Emission

Limit

Actual

Emission

Rate

Avg. Pla

AEL, o

Early

Election 

Limit

B-1, 21

MN Hoot Lake Otter Tail Power Co. 1943 3 Standard Limitation 0.46 0.29 MN Minnesota Valley NSP (d/b/a Xcel Energy) 1918 4 Averaging Plan 0.46 0.14 0.54 MN Northeast Station City of Austin Utilities 1961 NEPP Standard Limitation 0.46 0.44 MN Riverside NSP (d/b/a Xcel Energy) 1927 6 Averaging Plan 0.46 0.89 0.54 MN Riverside NSP (d/b/a Xcel Energy) 1927 7 Averaging Plan 0.46 0.89 0.54 MN Riverside NSP (d/b/a Xcel Energy) 1927 8 Averaging Plan 0.86 0.98 0.54 MN Sherburne County NSP (d/b/a Xcel Energy) 6090 1 Averaging Plan 0.45 0.30 0.54 MN Sherburne County NSP (d/b/a Xcel Energy) 6090 2 Averaging Plan 0.45 0.30 0.54 MN Sherburne County NSP (d/b/a Xcel Energy) 6090 3 Averaging Plan 0.46 0.34 0.54 MN Silver Lake Rochester Public Utilities 2008 4 Standard Limitation 0.46 0.36 MN Syl Laskin Minnesota Power and Light Co. 1891 1 Averaging Plan 0.40 0.47 0.41 MN Syl Laskin Minnesota Power and Light Co. 1891 2 Averaging Plan 0.40 0.47 0.41 MO Asbury Empire District Electric Co. 2076 1 Standard Limitation 0.86 0.85 MO Blue Valley City of Independence 2132 3 Standard Limitation 0.40 0.34 MO Hawthorn Kansas City Power & Light Co. 2079 5 Standard Limitation 0.45 Not Oper. MO Iatan Empire District Electric Co. 6065 1 Standard Limitation 0.50 0.29 MO James River City of Springfield (MO) 2161 3 Averaging Plan 0.50 0.53 0.50 MO James River City of Springfield (MO) 2161 4 Averaging Plan 0.50 0.54 0.50 MO James River City of Springfield (MO) 2161 5 Averaging Plan 0.50 0.62 0.50 MO Labadie Union Electric Co. 2103 1 Averaging Plan 0.45 0.11 0.52 MO Labadie Union Electric Co. 2103 2 Averaging Plan 0.45 0.12 0.52 MO Labadie Union Electric Co. 2103 3 Averaging Plan 0.45 0.12 0.52 MO Labadie Union Electric Co. 2103 4 Averaging Plan 0.45 0.12 0.52 MO Meramec Union Electric Co. 2104 1 Averaging Plan 0.45 0.38 0.52 
Appendix B-1: Compliance Results for All NOX Affected Units in 2000

2000

ST Plant Name Operating Utility

ORISCode Boiler

ComplianceApproach

Standard

Emission

Limit

Actual

Emission

Rate

Avg. Pla

AEL, o

Early

Election 

Limit

B-1, 22

MO Meramec Union Electric Co. 2104 2 Averaging Plan 0.45 0.29 0.52 MO Meramec Union Electric Co. 2104 3 Averaging Plan 0.50 0.75 0.52 MO Meramec Union Electric Co. 2104 4 Averaging Plan 0.50 0.30 0.52 MO Montrose Kansas City Power & Light Co. 2080 1 Standard Limitation 0.45 0.30 MO Montrose Kansas City Power & Light Co. 2080 2 Standard Limitation 0.45 0.36 MO Montrose Kansas City Power & Light Co. 2080 3 Standard Limitation 0.45 0.36 MO New Madrid City of New Madrid, Missouri 2167 1 Averaging Plan 0.86 1.23 0.74 MO New Madrid Associated Electric Coop. Inc. 2167 2 Averaging Plan 0.86 0.52 0.74 MO Rush Island Union Electric Co. 6155 1 Averaging Plan 0.45 0.14 0.52 MO Rush Island Union Electric Co. 6155 2 Averaging Plan 0.45 0.13 0.52 MO Sibley Utilicorp United Inc. 2094 3 Standard Limitation 0.86 0.74 MO Sikeston City of Columbia, MO 6768 1 Early Election 0.46 0.23 0.50 MO Sioux Union Electric Co. 2107 1 Averaging Plan 0.86 1.33 0.52 MO Sioux Union Electric Co. 2107 2 Averaging Plan 0.86 0.47 0.52 MO Southwest City of Springfield (MO) 6195 1 Averaging Plan 0.50 0.31 0.50 MO Thomas Hill Associated Electric Coop. Inc. 2168 MB1 Averaging Plan 0.86 0.99 0.74 MO Thomas Hill Associated Electric Coop. Inc. 2168 MB2 Averaging Plan 0.86 1.01 0.74 MO Thomas Hill Associated Electric Coop. Inc. 2168 MB3 Averaging Plan 0.50 0.33 0.74 MS Jack Watson Mississippi Power Co. 2049 4 Averaging Plan 0.50 0.53 0.46 MS Jack Watson Mississippi Power Co. 2049 5 Averaging Plan 0.50 0.71 0.46 MS R D Morrow South Mississippi Electric Power A 6061 1 Averaging Plan 0.50 0.45 0.50 MS R D Morrow South Mississippi Electric Power A 6061 2 Averaging Plan 0.50 0.47 0.50 MS Victor J Daniel Jr Mississippi Power Co. 6073 1 Averaging Plan 0.45 0.31 0.46 MS Victor J Daniel Jr Mississippi Power Co. 6073 2 Averaging Plan 0.45 0.29 0.46 
Appendix B-1: Compliance Results for All NOX Affected Units in 2000

2000

ST Plant Name Operating Utility

ORISCode Boiler

ComplianceApproach

Standard

Emission

Limit

Actual

Emission

Rate

Avg. Pla

AEL, o

Early

Election 

Limit

B-1, 23

MT Colstrip P P & L Montana, LLC 6076 1 Early Election 0.40 0.35 0.45 MT Colstrip P P & L Montana, LLC 6076 2 Early Election 0.40 0.42 0.45 MT Colstrip P P & L Montana, LLC 6076 3 Early Election 0.40 0.40 0.45 MT Colstrip Puget Sound Power & Light Co. 6076 4 Early Election 0.40 0.41 0.45 MT J E Corette P P & L Montana, LLC 2187 2 Standard Limitation 0.40 0.24 MT Lewis & Clark Montana-Dakota Utilities Co. 6089 B1 Early Election 0.40 0.40 0.45 NC Asheville Carolina Power & Light Co. 2706 1 Averaging Plan 0.46 0.46 0.44 NC Asheville Carolina Power & Light Co. 2706 2 Averaging Plan 0.46 0.36 0.44 NC Belews Creek Duke Energy Corp. 8042 1 Standard Limitation 0.68 0.60 NC Belews Creek Duke Energy Corp. 8042 2 Standard Limitation 0.68 0.55 NC Buck Duke Energy Corp. 2720 5 Early Election 0.40 0.41 0.45 NC Buck Duke Energy Corp. 2720 6 Early Election 0.40 0.42 0.45 NC Buck Duke Energy Corp. 2720 7 Early Election 0.40 0.44 0.45 NC Buck Duke Energy Corp. 2720 8 Early Election 0.40 0.43 0.45 NC Buck Duke Energy Corp. 2720 9 Early Election 0.40 0.44 0.45 NC Cape Fear Carolina Power & Light Co. 2708 5 Averaging Plan 0.40 0.46 0.44 NC Cape Fear Carolina Power & Light Co. 2708 6 Averaging Plan 0.40 0.59 0.44 NC Cliffside Duke Energy Corp. 2721 1 Early Election 0.40 0.38 0.45 NC Cliffside Duke Energy Corp. 2721 2 Early Election 0.40 0.40 0.45 NC Cliffside Duke Energy Corp. 2721 3 Early Election 0.40 0.39 0.45 NC Cliffside Duke Energy Corp. 2721 4 Early Election 0.40 0.42 0.45 NC Cliffside Duke Energy Corp. 2721 5 Early Election 0.40 0.44 0.45 NC Dan River Duke Energy Corp. 2723 1 Early Election 0.40 0.41 0.45 NC Dan River Duke Energy Corp. 2723 2 Early Election 0.40 0.43 0.45 
Appendix B-1: Compliance Results for All NOX Affected Units in 2000

2000

ST Plant Name Operating Utility

ORISCode Boiler

ComplianceApproach

Standard

Emission

Limit

Actual

Emission

Rate

Avg. Pla

AEL, o

Early

Election 

Limit

B-1, 24

NC Dan River Duke Energy Corp. 2723 3 Early Election 0.40 0.44 0.45 NC G G Allen Duke Energy Corp. 2718 1 Early Election 0.40 0.45 0.45 NC G G Allen Duke Energy Corp. 2718 2 Early Election 0.40 0.45 0.45 NC G G Allen Duke Energy Corp. 2718 3 Early Election 0.40 0.44 0.45 NC G G Allen Duke Energy Corp. 2718 4 Early Election 0.40 0.44 0.45 NC G G Allen Duke Energy Corp. 2718 5 Early Election 0.40 0.45 0.45 NC L V Sutton Carolina Power & Light Co. 2713 1 Averaging Plan 0.40 0.58 0.44 NC L V Sutton Carolina Power & Light Co. 2713 2 Averaging Plan 0.46 0.58 0.44 NC L V Sutton Carolina Power & Light Co. 2713 3 Averaging Plan 0.46 0.37 0.44 NC Lee Carolina Power & Light Co. 2709 1 Averaging Plan 0.40 0.60 0.44 NC Lee Carolina Power & Light Co. 2709 2 Averaging Plan 0.46 0.70 0.44 NC Lee Carolina Power & Light Co. 2709 3 Averaging Plan 0.46 0.36 0.44 NC Marshall Duke Energy Corp. 2727 1 Early Election 0.40 0.44 0.45 NC Marshall Duke Energy Corp. 2727 2 Early Election 0.40 0.44 0.45 NC Marshall Duke Energy Corp. 2727 3 Early Election 0.40 0.34 0.45 NC Marshall Duke Energy Corp. 2727 4 Early Election 0.40 0.45 0.45 NC Mayo Carolina Power & Light Co. 6250 1A Averaging Plan 0.46 0.35 0.44 NC Mayo Carolina Power & Light Co. 6250 1B Averaging Plan 0.46 0.35 0.44 NC Riverbend Duke Energy Corp. 2732 7 Early Election 0.40 0.42 0.45 NC Riverbend Duke Energy Corp. 2732 8 Early Election 0.40 0.39 0.45 NC Riverbend Duke Energy Corp. 2732 9 Early Election 0.40 0.42 0.45 NC Riverbend Duke Energy Corp. 2732 10 Early Election 0.40 0.41 0.45 NC Roxboro Carolina Power & Light Co. 2712 1 Averaging Plan 0.46 0.46 0.44 NC Roxboro Carolina Power & Light Co. 2712 2 Averaging Plan 0.40 0.29 0.44 
Appendix B-1: Compliance Results for All NOX Affected Units in 2000

2000

ST Plant Name Operating Utility

ORISCode Boiler

ComplianceApproach

Standard

Emission

Limit

Actual

Emission

Rate

Avg. Pla

AEL, o

Early

Election 

Limit

B-1, 25

NC Roxboro Carolina Power & Light Co. 2712 3A Averaging Plan 0.46 0.38 0.44 NC Roxboro Carolina Power & Light Co. 2712 3B Averaging Plan 0.46 0.38 0.44 NC Roxboro Carolina Power & Light Co. 2712 4A Averaging Plan 0.46 0.39 0.44 NC Roxboro Carolina Power & Light Co. 2712 4B Averaging Plan 0.46 0.39 0.44 NC W H Weatherspoon Carolina Power & Light Co. 2716 1 Averaging Plan 0.46 0.70 0.44 NC W H Weatherspoon Carolina Power & Light Co. 2716 2 Averaging Plan 0.46 0.70 0.44 NC W H Weatherspoon Carolina Power & Light Co. 2716 3 Averaging Plan 0.40 0.42 0.44 ND Antelope Valley Basin Electric Power Coop. 6469 B1 Early Election 0.40 0.38 0.45 ND Antelope Valley Basin Electric Power Coop. 6469 B2 Early Election 0.40 0.33 0.45 ND Coal Creek Great River Energy 6030 1 Standard Limitation 0.40 0.21 ND Coal Creek Great River Energy 6030 2 Standard Limitation 0.40 0.22 ND Coyote Montana-Dakota Utilities Co. 8222 B1 Standard Limitation 0.86 0.74 ND Leland Olds Basin Electric Power Coop. 2817 1 Early Election 0.46 0.25 0.50 ND Leland Olds Basin Electric Power Coop. 2817 2 Standard Limitation 0.86 0.60 ND Milton R Young Minnkota Power Coop., Inc. 2823 B1 Standard Limitation 0.86 0.80 ND Milton R Young Minnkota Power Coop., Inc. 2823 B2 Standard Limitation 0.86 0.84 ND Stanton Great River Energy 2824 1 Standard Limitation 0.46 0.41 ND Stanton Great River Energy 2824 10 Early Election 0.40 0.37 0.45 NE Gerald Whelan Energy City of Hastings 60 1 Early Election 0.40 0.29 0.45 NE Gerald Gentleman Station Nebraska Public Power District 6077 1 Early Election 0.46 0.43 0.50 NE Gerald Gentleman Station Nebraska Public Power District 6077 2 Early Election 0.46 0.32 0.50 NE Lon Wright City of Fremont 2240 8 Standard Limitation 0.46 0.18 NE Nebraska City Omaha Public Power District 6096 1 Early Election 0.46 0.41 0.50 NE North Omaha Omaha Public Power District 2291 1 Standard Limitation 0.40 0.29 
Appendix B-1: Compliance Results for All NOX Affected Units in 2000

2000

ST Plant Name Operating Utility

ORISCode Boiler

ComplianceApproach

Standard

Emission

Limit

Actual

Emission

Rate

Avg. Pla

AEL, o

Early

Election 

Limit

B-1, 26

NE North Omaha Omaha Public Power District 2291 2 Standard Limitation 0.40 0.29 NE North Omaha Omaha Public Power District 2291 3 Standard Limitation 0.40 0.29 NE North Omaha Omaha Public Power District 2291 4 Early Election 0.40 0.32 0.45 NE North Omaha Omaha Public Power District 2291 5 Standard Limitation 0.46 0.32 NE Platte City of Grand Island 59 1 Early Election 0.40 0.41 0.45 NH Merrimack Vermont Electric Power 2364 2 Standard Limitation 0.86 0.38 NH Schiller Public Service Co. of NH 2367 4 Standard Limitation 0.46 0.34 NH Schiller Public Service Co. of NH 2367 5 Standard Limitation 0.46 0.37 NH Schiller Public Service Co. of NH 2367 6 Standard Limitation 0.46 0.32 NJ B L England Atlantic City Electric Co. 2378 2 Standard Limitation 0.86 0.50 NJ Deepwater Atlantic City Electric Co. 2384 8 Standard Limitation 0.46 0.38 NJ Hudson PSEG Fossil LLC 2403 2 Averaging Plan 0.46 0.46 0.64 NJ Mercer PSEG Fossil LLC 2408 1 Averaging Plan 0.84 0.69 0.64 NJ Mercer PSEG Fossil LLC 2408 2 Averaging Plan 0.84 0.74 0.64 NM Escalante Tri-State G&T Association, Inc. 87 1 Early Election 0.40 0.41 0.45 NM Four Corners Arizona Public Service Co. 2442 1 Averaging Plan 0.46 0.76 0.61 NM Four Corners Arizona Public Service Co. 2442 2 Averaging Plan 0.46 0.49 0.61 NM Four Corners Arizona Public Service Co. 2442 3 Averaging Plan 0.46 0.56 0.61 NM Four Corners Arizona Public Service Co. 2442 4 Averaging Plan 0.68 0.55 0.61 NM Four Corners Arizona Public Service Co. 2442 5 Averaging Plan 0.68 0.52 0.61 NM San Juan Public Service Co. of NM 2451 1 Averaging Plan 0.46 0.45 0.46 NM San Juan Public Service Co. of NM 2451 2 Averaging Plan 0.46 0.49 0.46 NM San Juan Public Service Co. of NM 2451 3 Averaging Plan 0.46 0.41 0.46 NM San Juan Public Service Co. of NM 2451 4 Averaging Plan 0.46 0.42 0.46 
Appendix B-1: Compliance Results for All NOX Affected Units in 2000

2000

ST Plant Name Operating Utility

ORISCode Boiler

ComplianceApproach

Standard

Emission

Limit

Actual

Emission

Rate

Avg. Pla

AEL, o

Early

Election 

Limit

B-1, 27

NV Mohave Nevada Power Co. 2341 1 Early Election 0.40 0.42 0.45 NV Mohave Southern California Edison Co. 2341 2 Early Election 0.40 0.40 0.45 NV North Valmy Idaho Power Co. 8224 1 Early Election 0.46 0.35 0.50 NV North Valmy Sierra Pacific Power Co. 8224 2 Early Election 0.46 0.38 0.50 NV Reid Gardner Nevada Power Co. 2324 1 Standard Limitation 0.46 0.41 NV Reid Gardner Nevada Power Co. 2324 2 Standard Limitation 0.46 0.43 NV Reid Gardner Nevada Power Co. 2324 3 Standard Limitation 0.46 0.43 NV Reid Gardner Nevada Power Co. 2324 4 Early Election 0.46 0.28 0.50 NY AES Westover NGE Generation, Inc. 2526 11 Averaging Plan 0.46 0.59 0.45 NY AES Westover NGE Generation, Inc. 2526 12 Averaging Plan 0.46 0.59 0.45 NY AES Westover NGE Generation, Inc. 2526 13 Averaging Plan 0.40 0.44 0.45 NY C R Huntley Huntley Power Operations, Inc. 2549 63 Standard Limitation 0.84 0.74 NY C R Huntley Huntley Power Operations, Inc. 2549 64 Standard Limitation 0.84 0.74 NY C R Huntley Huntley Power Operations, Inc. 2549 65 Standard Limitation 0.84 0.74 NY C R Huntley Huntley Power Operations, Inc. 2549 66 Standard Limitation 0.84 0.74 NY C R Huntley Huntley Power Operatons, Inc. 2549 67 Early Election 0.40 0.37 0.45 NY C R Huntley Huntley Power Operatons, Inc. 2549 68 Early Election 0.40 0.37 0.45 NY Danskammer Dynegy Northeast Generation 2480 3 Averaging Plan 0.40 0.43 0.40 NY Danskammer Dynegy Northeast Generation 2480 4 Averaging Plan 0.40 0.38 0.40 NY Dunkirk Niagara Mohawk Power Corp. 2554 1 Early Election 0.40 0.36 0.45 NY Dunkirk Niagara Mohawk Power Corp. 2554 2 Early Election 0.40 0.35 0.45 NY Dunkirk Niagara Mohawk Power Corp. 2554 3 Standard Limitation 0.45 0.35 NY Dunkirk Niagara Mohawk Power Corp. 2554 4 Standard Limitation 0.45 0.35 NY Greenidge AES Greenidge, LLC 2527 4 Averaging Plan 0.46 0.70 0.45 
Appendix B-1: Compliance Results for All NOX Affected Units in 2000

2000

ST Plant Name Operating Utility

ORISCode Boiler

ComplianceApproach

Standard

Emission

Limit

Actual

Emission

Rate

Avg. Pla

AEL, o

Early

Election 

Limit

B-1, 28

NY Greenidge AES Greenidge, LLC 2527 5 Averaging Plan 0.46 0.70 0.45 NY Greenidge AES Greenidge, LLC 2527 6 Averaging Plan 0.45 0.35 0.45 NY Kintigh NGE Generation, Inc. 6082 1 Averaging Plan/EE 0.46 0.31 0.45 / 0.5NY Lovett Southern Energy Lovett, LLC 2629 4 Standard Limitation 0.46 0.35 NY Lovett Southern Energy Lovett, LLC 2629 5 Standard Limitation 0.46 0.36 NY Milliken NGE Generation, Inc. 2535 1 Averaging Plan 0.45 0.31 0.45 NY Milliken NGE Generation, Inc. 2535 2 Averaging Plan 0.45 0.31 0.45 NY Rochester 3 Rochester Gas & Electric Corp. 2640 12 Standard Limitation 0.40 Not Oper. NY Rochester 7 Rochester Gas & Electric Corp. 2642 1 Averaging Plan 0.40 0.40 0.40 NY Rochester 7 Rochester Gas & Electric Corp. 2642 2 Averaging Plan 0.40 0.40 0.40 NY Rochester 7 Rochester Gas & Electric Corp. 2642 3 Averaging Plan 0.40 0.35 0.40 NY Rochester 7 Rochester Gas & Electric Corp. 2642 4 Averaging Plan 0.40 0.35 0.40 NY S A Carlson City of Jamestown 2682 9 Early Election 0.46 0.41 0.50 NY S A Carlson City of Jamestown 2682 10 Early Election 0.46 0.45 0.50 NY S A Carlson City of Jamestown 2682 11 Early Election 0.46 0.45 0.50 NY S A Carlson City of Jamestown 2682 12 Early Election 0.46 0.41 0.50 OH Acme Toledo Edison Co. 2877 14 Standard Limitation 0.80 Not Oper. OH Acme Toledo Edison Co. 2877 15 Standard Limitation 0.80 Not Oper. OH Acme Toledo Edison Co. 2877 16 Standard Limitation 0.80 Not Oper. OH Acme Toledo Edison Co. 2877 91 Standard Limitation 0.80 Not Oper. OH Acme Toledo Edison Co. 2877 92 Standard Limitation 0.80 Not Oper. OH Ashtabula Cleveland Electric Illum Co. 2835 7 Averaging Plan 0.45 0.36 0.51 OH Ashtabula Cleveland Electric Illum Co. 2835 8 Averaging Plan 0.46 0.52 0.51 OH Ashtabula Cleveland Electric Illum Co. 2835 9 Standard Limitation 0.46 Not Oper. 
Appendix B-1: Compliance Results for All NOX Affected Units in 2000

2000

ST Plant Name Operating Utility

ORISCode Boiler

ComplianceApproach

Standard

Emission

Limit

Actual

Emission

Rate

Avg. Pla

AEL, o

Early

Election 

Limit

B-1, 29

OH Ashtabula Cleveland Electric Illum Co. 2835 10 Averaging Plan 0.46 0.52 0.51 OH Ashtabula Cleveland Electric Illum Co. 2835 11 Averaging Plan 0.46 0.52 0.51 OH Avon Lake Orion Power Midwest, LP 2836 9 Standard Limitation 0.40 Not Oper. OH Avon Lake Orion Power Midwest, LP 2836 10 Averaging Plan 0.40 0.39 0.55 OH Avon Lake Orion Power Midwest, LP 2836 12 Averaging Plan 0.68 0.80 0.55 OH Bay Shore Toledo Edison Co. 2878 1 Averaging Plan 0.80 Not Oper. 0.51 OH Bay Shore Toledo Edison Co. 2878 2 Averaging Plan 0.80 0.73 0.51 OH Bay Shore Toledo Edison Co. 2878 3 Averaging Plan 0.46 0.73 0.51 OH Bay Shore Toledo Edison Co. 2878 4 Averaging Plan 0.46 0.73 0.51 OH Cardinal/Tidd Ohio Power Co. 2828 1 Averaging Plan 0.68 0.57 0.61 OH Cardinal/Tidd Buckeye Power, Inc. 2828 2 Averaging Plan 0.68 0.54 0.61 OH Cardinal/Tidd Buckeye Power, Inc. 2828 3 Averaging Plan 0.46 0.56 0.61 OH Conesville Columbus Southern Power Co. 2840 3 Averaging Plan 0.50 0.46 0.61 OH Conesville Dayton Power & Light Co. 2840 4 Averaging Plan 0.45 0.47 0.61 OH Conesville Columbus Southern Power Co. 2840 5 Early Election 0.40 0.42 0.45 OH Conesville Columbus Southern Power Co. 2840 6 Early Election 0.40 0.42 0.45 OH Eastlake Cleveland Electric Illum Co. 2837 1 Averaging Plan 0.45 0.37 0.51 OH Eastlake Cleveland Electric Illum Co. 2837 2 Averaging Plan 0.45 0.41 0.51 OH Eastlake Cleveland Electric Illum Co. 2837 3 Averaging Plan 0.45 0.36 0.51 OH Eastlake Cleveland Electric Illum Co. 2837 4 Averaging Plan 0.45 0.35 0.51 OH Eastlake Cleveland Electric Illum Co. 2837 5 Averaging Plan 0.68 0.77 0.51 OH Edgewater Ohio Edison Co. 2857 11 Averaging Plan 0.80 Not Oper. 0.51 OH Edgewater Ohio Edison Co. 2857 12 Averaging Plan 0.80 Not Oper. 0.51 OH Edgewater Ohio Edison Co. 2857 13 Averaging Plan 0.50 0.18 0.51 
Appendix B-1: Compliance Results for All NOX Affected Units in 2000

2000

ST Plant Name Operating Utility

ORISCode Boiler

ComplianceApproach

Standard

Emission

Limit

Actual

Emission

Rate

Avg. Pla

AEL, o

Early

Election 

Limit

B-1, 30

OH Gen J M Gavin Ohio Power Co. 8102 1 Averaging Plan 0.68 0.45 0.61 OH Gen J M Gavin Ohio Power Co. 8102 2 Averaging Plan 0.68 0.49 0.61 OH Gorge Ohio Edison Co. 2858 25 Averaging Plan 0.50 Not Oper. 0.51 OH Gorge Ohio Edison Co. 2858 26 Averaging Plan 0.50 Not Oper. 0.51 OH Hamilton City of Hamilton 2917 9 Standard Limitation 0.40 0.38 OH J M Stuart Dayton Power & Light Co. 2850 1 Averaging Plan 0.68 0.59 0.62 OH J M Stuart Dayton Power & Light Co. 2850 2 Averaging Plan 0.68 0.58 0.62 OH J M Stuart Cinergy 2850 3 Averaging Plan 0.68 0.60 0.62 OH J M Stuart Dayton Power & Light Co. 2850 4 Averaging Plan 0.68 0.54 0.62 OH Killen Station Cincinnati Gas & Electric Co. 6031 2 Averaging Plan 0.46 0.45 0.62 OH Kyger Creek Ohio Valley Electric Corp. 2876 1 Averaging Plan 0.84 0.78 0.84 OH Kyger Creek Ohio Valley Electric Corp. 2876 2 Averaging Plan 0.84 0.78 0.84 OH Kyger Creek Ohio Valley Electric Corp. 2876 3 Averaging Plan 0.84 0.78 0.84 OH Kyger Creek Ohio Valley Electric Corp. 2876 4 Averaging Plan 0.84 0.78 0.84 OH Kyger Creek Ohio Valley Electric Corp. 2876 5 Averaging Plan 0.84 0.78 0.84 OH Lake Shore Cleveland Electric Illum Co. 2838 18 Averaging Plan 0.40 0.39 0.51 OH Miami Fort Cincinnati Gas & Electric Co. 2832 5-1 Averaging Plan 0.80 1.00 0.49 OH Miami Fort Cincinnati Gas & Electric Co. 2832 5-2 Averaging Plan 0.80 1.00 0.49 OH Miami Fort Cincinnati Gas & Electric Co. 2832 6 Averaging Plan 0.45 0.47 0.49 OH Miami Fort Cincinnati Gas & Electric Co. 2832 7 Averaging Plan 0.68 0.52 0.49 OH Miami Fort Cincinnati Gas & Electric Co. 2832 8 Averaging Plan 0.46 0.56 0.49 OH Muskingum River Ohio Power Co. 2872 1 Averaging Plan 0.84 0.74 0.61 OH Muskingum River Ohio Power Co. 2872 2 Averaging Plan 0.84 0.74 0.61 OH Muskingum River Ohio Power Co. 2872 3 Averaging Plan 0.86 0.74 0.61 
Appendix B-1: Compliance Results for All NOX Affected Units in 2000

2000

ST Plant Name Operating Utility

ORISCode Boiler

ComplianceApproach

Standard

Emission

Limit

Actual

Emission

Rate

Avg. Pla

AEL, o

Early

Election 

Limit

B-1, 31

OH Muskingum River Ohio Power Co. 2872 4 Averaging Plan 0.86 0.74 0.61 OH Muskingum River Ohio Power Co. 2872 5 Averaging Plan 0.68 0.65 0.61 OH O H Hutchings Dayton Power & Light Co. 2848 H-1 Averaging Plan 0.40 0.56 0.62 OH O H Hutchings Dayton Power & Light Co. 2848 H-2 Averaging Plan 0.40 0.56 0.62 OH O H Hutchings Dayton Power & Light Co. 2848 H-3 Averaging Plan 0.40 0.58 0.62 OH O H Hutchings Dayton Power & Light Co. 2848 H-4 Averaging Plan 0.40 0.58 0.62 OH O H Hutchings Dayton Power & Light Co. 2848 H-5 Averaging Plan 0.40 0.58 0.62 OH O H Hutchings Dayton Power & Light Co. 2848 H-6 Averaging Plan 0.40 0.58 0.62 OH Picway Columbus Southern Power Co. 2843 9 Averaging Plan 0.50 0.43 0.61 OH R E Burger Ohio Edison Co. 2864 1 Averaging Plan 0.84 Not Oper. 0.51 OH R E Burger Ohio Edison Co. 2864 2 Averaging Plan 0.84 Not Oper. 0.51 OH R E Burger Ohio Edison Co. 2864 3 Averaging Plan 0.84 Not Oper. 0.51 OH R E Burger Ohio Edison Co. 2864 4 Averaging Plan 0.84 Not Oper. 0.51 OH R E Burger Ohio Edison Co. 2864 5 Averaging Plan 0.84 0.89 0.51 OH R E Burger Ohio Edison Co. 2864 6 Averaging Plan 0.84 0.87 0.51 OH R E Burger Ohio Edison Co. 2864 7 Averaging Plan 0.50 0.67 0.51 OH R E Burger Ohio Edison Co. 2864 8 Averaging Plan 0.50 0.64 0.51 OH Richard Gorsuch American Municipal Power - OH 7253 1 Standard Limitation 0.46 0.38 OH Richard Gorsuch American Municipal Power - OH 7253 2 Standard Limitation 0.46 0.38 OH Richard Gorsuch American Municipal Power - OH 7253 3 Standard Limitation 0.46 0.38 OH Richard Gorsuch American Municipal Power - OH 7253 4 Standard Limitation 0.46 0.38 OH Toronto Ohio Edison Co. 2867 9 Averaging Plan 0.84 Not Oper. 0.51 OH Toronto Ohio Edison Co. 2867 10 Averaging Plan 0.50 Not Oper. 0.51 OH Toronto Ohio Edison Co. 2867 11 Averaging Plan 0.50 Not Oper. 0.51 
Appendix B-1: Compliance Results for All NOX Affected Units in 2000

2000

ST Plant Name Operating Utility

ORISCode Boiler

ComplianceApproach

Standard

Emission

Limit

Actual

Emission

Rate

Avg. Pla

AEL, o

Early

Election 

Limit

B-1, 32

OH W H Sammis Ohio Edison Co. 2866 1 Averaging Plan 0.46 0.44 0.51 OH W H Sammis Ohio Edison Co. 2866 2 Averaging Plan 0.46 0.45 0.51 OH W H Sammis Ohio Edison Co. 2866 3 Averaging Plan 0.46 1.03 0.51 OH W H Sammis Ohio Edison Co. 2866 4 Averaging Plan 0.46 0.62 0.51 OH W H Sammis Ohio Edison Co. 2866 5 Averaging Plan 0.50 0.47 0.51 OH W H Sammis Ohio Edison Co. 2866 6 Averaging Plan 0.50 0.40 0.51 OH W H Sammis Ohio Edison Co. 2866 7 Averaging Plan 0.68 0.36 0.51 OH W H Zimmer Cincinnati Gas & Electric Co. 6019 1 Early Election 0.46 0.46 0.50 OH Walter C Beckjord Cincinnati Gas & Electric Co. 2830 1 Averaging Plan 0.40 0.67 0.49 OH Walter C Beckjord Cincinnati Gas & Electric Co. 2830 2 Averaging Plan 0.40 0.65 0.49 OH Walter C Beckjord Cincinnati Gas & Electric Co. 2830 3 Averaging Plan 0.46 1.00 0.49 OH Walter C Beckjord Cincinnati Gas & Electric Co. 2830 4 Averaging Plan 0.40 0.63 0.49 OH Walter C Beckjord Cincinnati Gas & Electric Co. 2830 5 Averaging Plan 0.45 0.44 0.49 OH Walter C Beckjord Cincinnati Gas & Electric Co. 2830 6 Averaging Plan 0.45 0.33 0.49 OK GRDA Grand River Dam Authority 165 1 Averaging Plan 0.46 0.43 0.46 OK GRDA Grand River Dam Authority 165 2 Averaging Plan 0.46 0.27 0.46 OK Hugo Western Farmers Electric Coop. 6772 1 Standard Limitation 0.46 0.22 OK Muskogee Oklahoma Gas & Electric Co. 2952 4 Early Election 0.40 0.38 0.45 OK Muskogee Oklahoma Gas & Electric Co. 2952 5 Early Election 0.40 0.32 0.45 OK Muskogee Oklahoma Gas & Electric Co. 2952 6 Early Election 0.40 0.42 0.45 OK Northeastern American Electric Power Service 2963 3313 Early Election 0.40 0.36 0.45 OK Northeastern American Electric Power Service 2963 3314 Early Election 0.40 0.36 0.45 OK Sooner Oklahoma Gas & Electric Co. 6095 1 Early Election 0.40 0.37 0.45 OK Sooner Oklahoma Gas & Electric Co. 6095 2 Early Election 0.40 0.35 0.45 
Appendix B-1: Compliance Results for All NOX Affected Units in 2000

2000

ST Plant Name Operating Utility

ORISCode Boiler

ComplianceApproach

Standard

Emission

Limit

Actual

Emission

Rate

Avg. Pla

AEL, o

Early

Election 

Limit

B-1, 33

OR Boardman Portland General Electric Co. 6106 1SG Early Election 0.46 0.41 0.50 PA Armstrong Allegheny Energy Supply Co., LL 3178 1 Averaging Plan 0.50 0.37 0.56 PA Armstrong Allegheny Energy Supply Co., LL 3178 2 Averaging Plan 0.50 0.37 0.56 PA Bruce Mansfield Pennsylvania Power Co. 6094 1 Averaging Plan 0.50 0.36 0.51 PA Bruce Mansfield Pennsylvania Power Co. 6094 2 Averaging Plan 0.50 0.34 0.51 PA Bruce Mansfield Pennsylvania Power Co. 6094 3 Averaging Plan/EE 0.46 0.38 0.51 / 0.5PA Brunner Island PPL Brunner Island, LLC 3140 1 Standard Limitation 0.45 0.38 PA Brunner Island PPL Brunner Island, LLC 3140 2 Standard Limitation 0.45 0.38 PA Brunner Island PPL Brunner Island, LLC 3140 3 Standard Limitation 0.45 0.36 PA Cheswick Orion Power Midwest, LP 8226 1 Averaging Plan 0.45 0.36 0.55 PA Conemaugh Reliant Energy NE Management C 3118 1 Standard Limitation 0.45 0.34 PA Conemaugh Reliant Energy NE Management C 3118 2 Standard Limitation 0.45 0.34 PA Cromby Exelon Generation Co. 3159 1 Early Election 0.46 0.36 0.50 PA Eddystone Exelon Generation Co. 3161 1 Early Election 0.40 0.29 0.45 PA Eddystone Exelon Generation Co. 3161 2 Early Election 0.40 0.27 0.45 PA Elrama Orion Power Midwest, LP 3098 1 Averaging Plan 0.80 0.48 0.55 PA Elrama Orion Power Midwest, LP 3098 2 Averaging Plan 0.80 0.48 0.55 PA Elrama Orion Power Midwest, LP 3098 3 Averaging Plan 0.80 0.48 0.55 PA Elrama Orion Power Midwest, LP 3098 4 Averaging Plan 0.46 0.48 0.55 PA F R Phillips Orion Power Midwest, LP 3099 1 Standard Limitation 0.80 Not Oper. PA F R Phillips Orion Power Midwest, LP 3099 2 Standard Limitation 0.80 Not Oper. PA F R Phillips Orion Power Midwest, LP 3099 3 Standard Limitation 0.80 Not Oper. PA F R Phillips Orion Power Midwest, LP 3099 4 Standard Limitation 0.80 Not Oper. PA F R Phillips Orion Power Midwest, LP 3099 5 Standard Limitation 0.80 Not Oper. 
Appendix B-1: Compliance Results for All NOX Affected Units in 2000

2000

ST Plant Name Operating Utility

ORISCode Boiler

ComplianceApproach

Standard

Emission

Limit

Actual

Emission

Rate

Avg. Pla

AEL, o

Early

Election 

Limit

B-1, 34

PA F R Phillips Orion Power Midwest, LP 3099 6 Standard Limitation 0.80 Not Oper. PA Hatfield's Ferry Allegheny Energy Supply Co., LL 3179 1 Averaging Plan 0.68 0.46 0.56 PA Hatfield's Ferry Allegheny Energy Supply Co., LL 3179 2 Averaging Plan 0.68 0.46 0.56 PA Hatfield's Ferry Allegheny Energy Supply Co., LL 3179 3 Averaging Plan 0.68 0.46 0.56 PA Homer City EME Homer City Generation, LP 3122 1 Early Election 0.46 0.41 0.50 PA Homer City EME Homer City Generation, LP 3122 2 Early Election 0.46 0.44 0.50 PA Homer City EME Homer City Generation, LP 3122 3 Early Election 0.46 0.44 0.50 PA Keystone Reliant Energy NE Management C 3136 1 Early Election 0.40 0.32 0.45 PA Keystone Reliant Energy NE Management C 3136 2 Early Election 0.40 0.33 0.45 PA Martins Creek PPL Martins Creek, LLC 3148 1 Standard Limitation 0.50 0.44 PA Martins Creek PPL Martins Creek, LLC 3148 2 Standard Limitation 0.50 0.44 PA Mitchell Allegheny Energy Supply Co., LL 3181 33 Averaging Plan 0.45 0.37 0.56 PA Montour PPL Montour, LLC 3149 1 Early Election 0.40 0.42 0.45 PA Montour PPL Montour, LLC 3149 2 Early Election 0.40 0.32 0.45 PA New Castle Orion Power Midwest, LP 3138 1 Standard Limitation 0.50 Not Oper. PA New Castle Orion Power Midwest, LP 3138 2 Standard Limitation 0.50 Not Oper. PA New Castle Orion Power Midwest, LP 3138 3 Averaging Plan/EE 0.46 0.33 0.55 / 0.5PA New Castle Orion Power Midwest, LP 3138 4 Averaging Plan/EE 0.46 0.36 0.55 / 0.5PA New Castle Orion Power Midwest, LP 3138 5 Averaging Plan/EE 0.46 0.39 0.55 / 0.5PA Portland Reliant Energy Mid-Atl Pwr Hol 3113 1 Averaging Plan 0.45 0.25 0.44 PA Portland Reliant Energy Mid-Atl Pwr Hol 3113 2 Averaging Plan 0.45 0.30 0.44 PA Seward Reliant Energy Mid-Atl Pwr Hol 3130 12 Averaging Plan 0.46 0.45 0.44 PA Seward Reliant Energy Mid-Atl Pwr Hol 3130 14 Averaging Plan 0.46 0.45 0.44 PA Seward Reliant Energy Mid-Atl Pwr Hol 3130 15 Averaging Plan 0.40 0.45 0.44 
Appendix B-1: Compliance Results for All NOX Affected Units in 2000

2000

ST Plant Name Operating Utility

ORISCode Boiler

ComplianceApproach

Standard

Emission

Limit

Actual

Emission

Rate

Avg. Pla

AEL, o

Early

Election 

Limit

B-1, 35

PA Shawville Reliant Energy Mid-Atl Pwr Hol 3131 1 Standard Limitation 0.50 0.45 PA Shawville Reliant Energy Mid-Atl Pwr Hol 3131 2 Standard Limitation 0.50 0.45 PA Shawville Reliant Energy Mid-Atl Pwr Hol 3131 3 Standard Limitation 0.45 0.39 PA Shawville Reliant Energy Mid-Atl Pwr Hol 3131 4 Standard Limitation 0.45 0.39 PA Sunbury Sunbury Generation, LLC 3152 3 Standard Limitation 0.50 0.38 PA Sunbury Sunbury Generation, LLC 3152 4 Standard Limitation 0.50 0.38 PA Titus Reliant Energy Mid-Atlantic Pwr Holdings 3115 1 Early Election 0.40 0.32 0.45 PA Titus Reliant Energy Mid-Atlantic Pwr Holdings 3115 2 Early Election 0.40 0.32 0.45 PA Titus Reliant Energy Mid-Atlantic Pwr Holdings 3115 3 Early Election 0.40 0.33 0.45 PA Warren Reliant Energy Mid-Atl Pwr Holdings 3132 1 Averaging Plan 0.46 0.52 0.44 PA Warren Reliant Energy Mid-Atl Pwr Holdings 3132 2 Averaging Plan 0.46 0.52 0.44 PA Warren Reliant Energy Mid-Atl Pwr Holdings 3132 3 Averaging Plan 0.46 0.52 0.44 PA Warren Reliant Energy Mid-Atl Pwr Holdings 3132 4 Averaging Plan 0.46 0.52 0.44 SC Canadys Steam South Carolina Electric & Gas 3280 CAN1 Averaging Plan 0.40 0.40 0.41 SC Canadys Steam South Carolina Electric & Gas 3280 CAN2 Averaging Plan 0.40 0.41 0.41 SC Canadys Steam South Carolina Electric & Gas 3280 CAN3 Averaging Plan 0.46 0.38 0.41 SC Cope Station South Carolina Electric & Gas 7210 COP1 Averaging Plan 0.40 0.26 0.41 SC Cross South Carolina Public Serv. Authority 130 1 Averaging Plan/EE 0.46 0.31 0.46 / 0.5SC Cross South Carolina Public Service Authority 130 2 Early Election 0.40 0.39 0.45 SC Dolphus M Grainger South Carolina Public Serv. Authority 3317 1 Averaging Plan 0.46 0.48 0.46 SC Dolphus M Grainger South Carolina Public Serv. Authority 3317 2 Averaging Plan 0.46 0.90 0.46 SC H B Robinson Carolina Power & Light Co. 3251 1 Averaging Plan 0.40 0.76 0.44 SC Jefferies South Carolina Public Serv. Authority 3319 3 Averaging Plan 0.46 0.41 0.46 SC Jefferies South Carolina Public Serv. Authority 3319 4 Averaging Plan 0.46 0.44 0.46 
Appendix B-1: Compliance Results for All NOX Affected Units in 2000

2000

ST Plant Name Operating Utility

ORISCode Boiler

ComplianceApproach

Standard

Emission

Limit

Actual

Emission

Rate

Avg. Pla

AEL, o

Early

Election 

Limit

B-1, 36

SC McMeekin South Carolina Electric & Gas 3287 MCM1 Averaging Plan 0.40 0.39 0.41 SC McMeekin South Carolina Electric & Gas 3287 MCM2 Averaging Plan 0.40 0.38 0.41 SC Urquhart South Carolina Electric & Gas 3295 URQ1 Averaging Plan 0.40 0.47 0.41 SC Urquhart South Carolina Electric & Gas 3295 URQ2 Averaging Plan 0.40 0.51 0.41 SC Urquhart South Carolina Electric & Gas 3295 URQ3 Averaging Plan 0.40 0.35 0.41 SC W S Lee Duke Energy Corp. 3264 1 Early Election 0.40 0.43 0.45 SC W S Lee Duke Energy Corp. 3264 2 Early Election 0.40 0.43 0.45 SC W S Lee Duke Energy Corp. 3264 3 Early Election 0.40 0.43 0.45 SC Wateree South Carolina Electric & Gas 3297 WAT1 AEL Final 0.46 0.46 0.59 SC Wateree South Carolina Electric & Gas 3297 WAT2 AEL Final 0.46 0.41 0.59 SC Williams South Carolina Electric & Gas 3298 WIL1 AEL Final 0.40 0.47 0.48 SC Winyah South Carolina Public Serv. Au 6249 1 Averaging Plan/AEL 0.46 0.44 0.46 / 0.6SC Winyah South Carolina Public Serv. Au 6249 2 AEL Final 0.46 0.52 0.61 SC Winyah South Carolina Public Serv. Au 6249 3 AEL Final 0.46 0.59 0.60 SC Winyah South Carolina Public Serv. Au 6249 4 AEL Final 0.46 0.54 0.60 SD Big Stone Northwestern Public Service Co. 6098 1 Standard Limitation 0.86 0.84 TN Allen Tennessee Valley Authority 3393 1 Averaging Plan 0.86 0.75 0.57 TN Allen Tennessee Valley Authority 3393 2 Averaging Plan 0.86 0.73 0.57 TN Allen Tennessee Valley Authority 3393 3 Averaging Plan 0.86 0.76 0.57 TN Bull Run Tennessee Valley Authority 3396 1 Averaging Plan 0.40 0.63 0.57 TN Cumberland Tennessee Valley Authority 3399 1 Averaging Plan 0.68 0.47 0.57 TN Cumberland Tennessee Valley Authority 3399 2 Averaging Plan 0.68 0.52 0.57 TN Gallatin Tennessee Valley Authority 3403 1 Averaging Plan 0.45 0.29 0.57 TN Gallatin Tennessee Valley Authority 3403 2 Averaging Plan 0.45 0.29 0.57 
Appendix B-1: Compliance Results for All NOX Affected Units in 2000

2000

ST Plant Name Operating Utility

ORISCode Boiler

ComplianceApproach

Standard

Emission

Limit

Actual

Emission

Rate

Avg. Pla

AEL, o

Early

Election 

Limit

B-1, 37

TN Gallatin Tennessee Valley Authority 3403 3 Averaging Plan 0.45 0.30 0.57 TN Gallatin Tennessee Valley Authority 3403 4 Averaging Plan 0.45 0.30 0.57 TN John Sevier Tennessee Valley Authority 3405 1 Early Election 0.40 0.40 0.45 TN John Sevier Tennessee Valley Authority 3405 2 Early Election 0.40 0.40 0.45 TN John Sevier Tennessee Valley Authority 3405 3 Early Election 0.40 0.41 0.45 TN John Sevier Tennessee Valley Authority 3405 4 Early Election 0.40 0.41 0.45 TN Johnsonville Tennessee Valley Authority 3406 1 Averaging Plan 0.45 0.48 0.57 TN Johnsonville Tennessee Valley Authority 3406 2 Averaging Plan 0.45 0.48 0.57 TN Johnsonville Tennessee Valley Authority 3406 3 Averaging Plan 0.45 0.48 0.57 TN Johnsonville Tennessee Valley Authority 3406 4 Averaging Plan 0.45 0.48 0.57 TN Johnsonville Tennessee Valley Authority 3406 5 Averaging Plan 0.45 0.48 0.57 TN Johnsonville Tennessee Valley Authority 3406 6 Averaging Plan 0.45 0.48 0.57 TN Johnsonville Tennessee Valley Authority 3406 7 Averaging Plan 0.50 0.48 0.57 TN Johnsonville Tennessee Valley Authority 3406 8 Averaging Plan 0.50 0.48 0.57 TN Johnsonville Tennessee Valley Authority 3406 9 Averaging Plan 0.50 0.48 0.57 TN Johnsonville Tennessee Valley Authority 3406 10 Averaging Plan 0.50 0.48 0.57 TN Kingston Tennessee Valley Authority 3407 1 Averaging Plan 0.40 0.55 0.57 TN Kingston Tennessee Valley Authority 3407 2 Averaging Plan 0.40 0.55 0.57 TN Kingston Tennessee Valley Authority 3407 3 Averaging Plan 0.40 0.55 0.57 TN Kingston Tennessee Valley Authority 3407 4 Averaging Plan 0.40 0.55 0.57 TN Kingston Tennessee Valley Authority 3407 5 Averaging Plan 0.40 0.55 0.57 TN Kingston Tennessee Valley Authority 3407 6 Averaging Plan 0.40 0.43 0.57 TN Kingston Tennessee Valley Authority 3407 7 Averaging Plan 0.40 0.43 0.57 TN Kingston Tennessee Valley Authority 3407 8 Averaging Plan 0.40 0.43 0.57 
Appendix B-1: Compliance Results for All NOX Affected Units in 2000

2000

ST Plant Name Operating Utility

ORISCode Boiler

ComplianceApproach

Standard

Emission

Limit

Actual

Emission

Rate

Avg. Pla

AEL, o

Early

Election 

Limit

B-1, 38

TN Kingston Tennessee Valley Authority 3407 9 Averaging Plan 0.40 0.43 0.57 TX Big Brown TXU Electric Co. 3497 1 Early Election 0.40 0.38 0.45 TX Big Brown TXU Electric Co. 3497 2 Early Election 0.40 0.36 0.45 TX Coleto Creek American Electric Power Service 6178 1 Early Election 0.40 0.24 0.45 TX Gibbons Creek Texas Municipal Power Agency 6136 1 Early Election 0.40 0.29 0.45 TX Harrington Station Southwestern Public Service Co. 6193 061B Early Election 0.40 0.28 0.45 TX Harrington Station Southwestern Public Service Co. 6193 062B Early Election 0.40 0.30 0.45 TX Harrington Station Southwestern Public Service Co. 6193 063B Early Election 0.40 0.25 0.45 TX J T Deely City of San Antonio 6181 1 Early Election 0.40 0.26 0.45 TX J T Deely City of San Antonio 6181 2 Early Election 0.40 0.26 0.45 TX J K Spruce City of San Antonio 7097 **1 Early Election 0.40 0.18 0.45 TX Limestone Houston Lighting & Power Co. 298 LIM1 Early Election 0.40 0.40 0.45 TX Limestone Houston Lighting & Power Co. 298 LIM2 Early Election 0.40 0.28 0.45 TX Martin Lake TXU Electric Co. 6146 1 Early Election 0.40 0.28 0.45 TX Martin Lake TXU Electric Co. 6146 2 Early Election 0.40 0.29 0.45 TX Martin Lake TXU Electric Co. 6146 3 Early Election 0.40 0.31 0.45 TX Monticello TXU Electric Co. 6147 1 Early Election 0.40 0.30 0.45 TX Monticello TXU Electric Co. 6147 2 Early Election 0.40 0.30 0.45 TX Monticello TXU Electric Co. 6147 3 Early Election 0.46 0.24 0.50 TX Oklaunion American Electric Power Service 127 1 Early Election 0.46 0.29 0.50 TX Pirkey American Electric Power Service 7902 1 Early Election 0.46 0.36 0.50 TX Sam Seymour City of Austin, Texas 6179 1 Early Election 0.40 0.33 0.45 TX Sam Seymour City of Austin, Texas 6179 2 Early Election 0.40 0.31 0.45 TX Sam Seymour Lower Colorado River Authority 6179 3 Early Election 0.40 0.33 0.45 
Appendix B-1: Compliance Results for All NOX Affected Units in 2000

2000

ST Plant Name Operating Utility

ORISCode Boiler

ComplianceApproach

Standard

Emission

Limit

Actual

Emission

Rate

Avg. Pla

AEL, o

Early

Election 

Limit

B-1, 39

TX San Miguel San Miguel Electric Coop. 6183 SM-1 Early Election 0.46 0.40 0.50 TX Sandow TXU Electric Co. 6648 4 Early Election 0.40 0.33 0.45 TX Tolk Station Southwestern Public Service Co. 6194 171B Early Election 0.40 0.30 0.45 TX Tolk Station Southwestern Public Service Co. 6194 172B Early Election 0.40 0.30 0.45 TX W A Parish Houston Lighting & Power Co. 3470 WAP5 Early Election 0.46 0.34 0.50 TX W A Parish Houston Lighting & Power Co. 3470 WAP6 Early Election 0.46 0.20 0.50 TX W A Parish Houston Lighting & Power Co. 3470 WAP7 Early Election 0.40 0.14 0.45 TX W A Parish Houston Lighting & Power Co. 3470 WAP8 Early Election 0.40 0.30 0.45 TX Welsh American Electric Power Service 6139 1 Early Election 0.46 0.29 0.50 TX Welsh American Electric Power Service 6139 2 Early Election 0.46 0.33 0.50 TX Welsh American Electric Power Service 6139 3 Early Election 0.46 0.36 0.50 UT Bonanza Deseret Generation & Transmission 7790 1-1 Early Election 0.46 0.34 0.50 UT Carbon PacifiCorp 3644 1 Early Election 0.40 0.42 0.45 UT Carbon PacifiCorp 3644 2 Early Election 0.40 0.44 0.45 UT Hunter (Emery) PacifiCorp 6165 1 Early Election 0.40 0.44 0.45 UT Hunter (Emery) PacifiCorp 6165 2 Early Election 0.40 0.42 0.45 UT Hunter (Emery) PacifiCorp 6165 3 Averaging Plan 0.46 0.41 0.45 UT Huntington PacifiCorp 8069 1 Early Election 0.40 0.43 0.45 UT Huntington PacifiCorp 8069 2 Averaging Plan 0.40 0.42 0.45 UT Intermountain Intermountain Power Service Co. 6481 1SGA Early Election 0.46 0.42 0.50 UT Intermountain Intermountain Power Service Co. 6481 2SGA Early Election 0.46 0.41 0.50 VA Bremo Bluff Dominion Generation 3796 3 Averaging Plan 0.46 0.75 0.41 VA Bremo Bluff Dominion Generation 3796 4 Averaging Plan 0.46 0.41 0.41 VA Chesapeake Virginia Electric & Power Co. 3803 1 Early Election 0.40 0.41 0.45 
Appendix B-1: Compliance Results for All NOX Affected Units in 2000

2000

ST Plant Name Operating Utility

ORISCode Boiler

ComplianceApproach

Standard

Emission

Limit

Actual

Emission

Rate

Avg. Pla

AEL, o

Early

Election 

Limit

B-1, 40

VA Chesapeake Virginia Electric & Power Co. 3803 2 Early Election 0.40 0.41 0.45 VA Chesapeake Virginia Electric & Power Co. 3803 3 Averaging Plan 0.46 0.42 0.41 VA Chesapeake Virginia Electric & Power Co. 3803 4 Early Election 0.40 0.43 0.45 VA Chesterfield Virginia Electric & Power Co. 3797 3 Early Election 0.40 0.42 0.45 VA Chesterfield Virginia Electric & Power Co. 3797 4 Early Election 0.40 0.42 0.45 VA Chesterfield Virginia Electric & Power Co. 3797 5 Averaging Plan 0.40 0.36 0.41 VA Chesterfield Virginia Electric & Power Co. 3797 6 Averaging Plan 0.40 0.37 0.41 VA Clinch River Appalachian Power Co. 3775 1 Averaging Plan 0.80 0.64 0.61 VA Clinch River Appalachian Power Co. 3775 2 Averaging Plan 0.80 0.64 0.61 VA Clinch River Appalachian Power Co. 3775 3 Averaging Plan 0.80 0.59 0.61 VA Clover Virginia Electric & Power Co. 7213 1 Averaging Plan 0.40 0.29 0.41 VA Clover Virginia Electric & Power Co. 7213 2 Averaging Plan 0.40 0.30 0.41 VA Glen Lyn Appalachian Power Co. 3776 6 Averaging Plan 0.46 0.62 0.61 VA Glen Lyn Appalachian Power Co. 3776 51 Averaging Plan/EE 0.40 0.40 0.61 / 0.4VA Glen Lyn Appalachian Power Co. 3776 52 Averaging Plan/EE 0.40 0.43 0.61 / 0.4VA Possum Point Virginia Electric & Power Co. 3804 3 Early Election 0.40 0.43 0.45 VA Possum Point Virginia Electric & Power Co. 3804 4 Averaging Plan 0.40 0.36 0.41 VA Potomac River Southern Energy Mid Atlantic 3788 1 Early Election 0.40 0.43 0.45 VA Potomac River Southern Energy Mid Atlantic 3788 2 Early Election 0.40 0.42 0.45 VA Potomac River Southern Energy Mid Atlantic 3788 3 Early Election 0.40 0.41 0.45 VA Potomac River Southern Energy Mid Atlantic 3788 4 Early Election 0.40 0.44 0.45 VA Potomac River Southern Energy Mid Atlantic 3788 5 Early Election 0.40 0.42 0.45 VA Yorktown Virginia Electric & Power Co. 3809 1 Early Election 0.40 0.45 0.45 VA Yorktown Virginia Electric & Power Co. 3809 2 Early Election 0.40 0.40 0.45 
Appendix B-1: Compliance Results for All NOX Affected Units in 2000

2000

ST Plant Name Operating Utility

ORISCode Boiler

ComplianceApproach

Standard

Emission

Limit

Actual

Emission

Rate

Avg. Pla

AEL, o

Early

Election 

Limit

B-1, 41

WA Centralia Transalta Centralia Generation 3845 BW21 Early Election 0.40 0.40 0.45 WA Centralia Transalta Centralia Generation 3845 BW22 Early Election 0.40 0.40 0.45 WI Alma Dairyland Power Coop. 4140 B4 Averaging Plan 0.50 0.63 0.48 WI Alma Dairyland Power Coop. 4140 B5 Averaging Plan 0.50 0.63 0.48 WI Blount Street Madison Gas & Electric Co. 3992 7 Standard Limitation 0.68 0.62 WI Blount Street Madison Gas & Electric Co. 3992 8 Early Election 0.46 0.37 0.50 WI Blount Street Madison Gas & Electric Co. 3992 9 Early Election 0.46 0.41 0.50 WI Columbia Wisconsin Power & Light Co. 8023 1 Early Election 0.40 0.37 0.45 WI Columbia Wisconsin Power & Light Co. 8023 2 Early Election 0.40 0.34 0.45 WI Edgewater Wisconsin Power & Light Co. 4050 4 Averaging Plan 0.86 1.06 0.62 WI Edgewater Wisconsin Power & Light Co. 4050 5 Averaging Plan/EE 0.46 0.21 0.62 / 0.5WI Genoa Dairyland Power Coop. 4143 1 Averaging Plan 0.45 0.37 0.48 WI J P Madgett Dairyland Power Coop. 4271 B1 Averaging Plan 0.50 0.39 0.48 WI Pleasant Prairie Wisconsin Electric Power Co. 6170 1 Averaging Plan 0.46 0.42 0.47 WI Pleasant Prairie Wisconsin Electric Power Co. 6170 2 Averaging Plan 0.46 0.42 0.47 WI Port Washington Wisconsin Electric Power Co. 4040 1 Averaging Plan 0.50 0.31 0.47 WI Port Washington Wisconsin Electric Power Co. 4040 2 Averaging Plan 0.50 0.31 0.47 WI Port Washington Wisconsin Electric Power Co. 4040 3 Averaging Plan 0.50 0.31 0.47 WI Port Washington Wisconsin Electric Power Co. 4040 4 Averaging Plan 0.50 0.30 0.47 WI Port Washington Wisconsin Electric Power Co. 4040 5 Standard Limitation 0.50 Not Oper. WI Pulliam Wisconsin Public Service Corp. 4072 3 Averaging Plan 0.46 0.72 0.47 WI Pulliam Wisconsin Public Service Corp. 4072 4 Averaging Plan 0.46 0.72 0.47 WI Pulliam Wisconsin Public Service Corp. 4072 5 Averaging Plan 0.46 0.78 0.47 WI Pulliam Wisconsin Public Service Corp. 4072 6 Averaging Plan 0.46 0.78 0.47 
Appendix B-1: Compliance Results for All NOX Affected Units in 2000

2000

ST Plant Name Operating Utility

ORISCode Boiler

ComplianceApproach

Standard

Emission

Limit

Actual

Emission

Rate

Avg. Pla

AEL, o

Early

Election 

Limit

B-1, 42

WI Pulliam Wisconsin Public Service Corp. 4072 7 Averaging Plan 0.50 0.45 0.47 WI Pulliam Wisconsin Public Service Corp. 4072 8 Averaging Plan 0.50 0.32 0.47 WI South Oak Creek Wisconsin Electric Power Co. 4041 5 Averaging Plan 0.50 0.23 0.47 WI South Oak Creek Wisconsin Electric Power Co. 4041 6 Averaging Plan 0.50 0.23 0.47 WI South Oak Creek Wisconsin Electric Power Co. 4041 7 Averaging Plan 0.45 0.39 0.47 WI South Oak Creek Wisconsin Electric Power Co. 4041 8 Averaging Plan 0.45 0.39 0.47 WI Stoneman Mid-American Power, LLC 4146 B1 Averaging Plan 0.46 0.39 0.47 WI Stoneman Mid-American Power, LLC 4146 B2 Averaging Plan 0.46 0.39 0.47 WI Valley Wisconsin Electric Power Co. 4042 1 Averaging Plan 0.50 0.46 0.47 WI Valley Wisconsin Electric Power Co. 4042 2 Averaging Plan 0.50 0.46 0.47 WI Valley Wisconsin Electric Power Co. 4042 3 Averaging Plan 0.50 0.47 0.47 WI Valley Wisconsin Electric Power Co. 4042 4 Averaging Plan 0.50 0.47 0.47 WI Weston Wisconsin Public Service Corp. 4078 1 Averaging Plan 0.50 0.83 0.47 WI Weston Wisconsin Public Service Corp. 4078 2 Averaging Plan 0.50 0.38 0.47 WI Weston Wisconsin Public Service Corp. 4078 3 Averaging Plan 0.45 0.22 0.47 WV Albright Monongahela Power Co. 3942 1 Averaging Plan 0.50 0.66 0.56 WV Albright Monongahela Power Co. 3942 2 Averaging Plan 0.50 0.66 0.56 WV Albright Monongahela Power Co. 3942 3 Averaging Plan 0.45 0.38 0.56 WV Fort Martin Monongahela Power Co. 3943 1 Averaging Plan 0.45 0.40 0.56 WV Fort Martin Monongahela Power Co. 3943 2 Averaging Plan 0.68 0.98 0.56 WV Harrison Monongahela Power Co. 3944 1 Averaging Plan/AEL 0.50 0.46 0.56 / 0.7WV Harrison Monongahela Power Co. 3944 2 Averaging Plan 0.50 0.46 0.56 WV Harrison Monongahela Power Co. 3944 3 Averaging Plan 0.50 0.46 0.56 WV John E Amos Appalachian Power Co. 3935 1 AEL Final 0.46 0.55 0.59 
Appendix B-1: Compliance Results for All NOX Affected Units in 2000

2000

ST Plant Name Operating Utility

ORISCode Boiler

ComplianceApproach

Standard

Emission

Limit

Actual

Emission

Rate

Avg. Pla

AEL, o

Early

Election 

Limit

B-1, 43

WV John E Amos Appalachian Power Co. 3935 2 AEL Final 0.46 0.49 0.52 WV John E Amos Ohio Power Co. 3935 3 Standard Limitation 0.68 0.64 WV Kammer Ohio Power Co. 3947 1 Averaging Plan 0.86 0.76 0.61 WV Kammer Ohio Power Co. 3947 2 Averaging Plan 0.86 0.76 0.61 WV Kammer Ohio Power Co. 3947 3 Averaging Plan 0.86 0.76 0.61 WV Kanawha River Appalachian Power Co. 3936 1 Averaging Plan 0.80 0.60 0.61 WV Kanawha River Appalachian Power Co. 3936 2 Averaging Plan 0.80 0.60 0.61 WV Mitchell Ohio Power Co. 3948 1 Averaging Plan/AEL 0.50 0.56 0.61 / 0.5WV Mitchell Ohio Power Co. 3948 2 Averaging Plan/AEL 0.50 0.53 0.61 / 0.5WV Mountaineer (1301) Appalachian Power Co. 6264 1 Averaging Plan/EE 0.46 0.49 0.61 / 0.5WV Mt Storm Virginia Electric & Power Co. 3954 1 AEL Final 0.45 0.67 0.76 WV Mt Storm Virginia Electric & Power Co. 3954 2 AEL Final 0.45 0.63 0.69 WV Mt Storm Virginia Electric & Power Co. 3954 3 AEL Final 0.45 0.61 0.74 WV Phil Sporn Central Operating Co. 3938 11 Averaging Plan 0.80 0.71 0.61 WV Phil Sporn Central Operating Co. 3938 21 Averaging Plan 0.80 0.71 0.61 WV Phil Sporn Central Operating Co. 3938 31 Averaging Plan 0.80 0.71 0.61 WV Phil Sporn Central Operating Co. 3938 41 Averaging Plan 0.80 0.71 0.61 WV Phil Sporn Central Operating Co. 3938 51 Averaging Plan 0.46 0.47 0.61 WV Pleasants Monongahela Power Co. 6004 1 Averaging Plan 0.50 0.35 0.56 WV Pleasants Monongahela Power Co. 6004 2 Averaging Plan 0.50 0.35 0.56 WV Rivesville Monongahela Power Co. 3945 7 Averaging Plan 0.80 0.93 0.56 WV Rivesville Monongahela Power Co. 3945 8 Averaging Plan 0.80 0.69 0.56 WV Willow Island Monongahela Power Co. 3946 1 Averaging Plan 0.80 0.70 0.56 WV Willow Island Monongahela Power Co. 3946 2 Averaging Plan 0.86 1.20 0.56 
Appendix B-1: Compliance Results for All NOX Affected Units in 2000

2000

ST Plant Name Operating Utility

ORISCode Boiler

ComplianceApproach

Standard

Emission

Limit

Actual

Emission

Rate

Avg. Pla

AEL, o

Early

Election 

Limit

B-1, 44

WY Dave Johnston PacifiCorp 4158 BW41 Early Election 0.46 0.43 0.50 WY Dave Johnston PacifiCorp 4158 BW42 Early Election 0.46 0.42 0.50 WY Dave Johnston PacifiCorp 4158 BW43 Averaging Plan 0.68 0.56 0.45 WY Dave Johnston PacifiCorp 4158 BW44 Averaging Plan 0.40 0.41 0.45 WY Jim Bridger PacifiCorp 8066 BW71 Averaging Plan 0.45 0.40 0.45 WY Jim Bridger PacifiCorp 8066 BW72 Averaging Plan 0.45 0.39 0.45 WY Jim Bridger PacifiCorp 8066 BW73 Averaging Plan 0.45 0.37 0.45 WY Jim Bridger PacifiCorp 8066 BW74 Early Election 0.40 0.38 0.45 WY Laramie River Basin Electric Power Coop. 6204 1 Early Election 0.46 0.25 0.50 WY Laramie River Basin Electric Power Coop. 6204 2 Early Election 0.46 0.27 0.50 WY Laramie River Basin Electric Power Coop. 6204 3 Early Election 0.46 0.25 0.50 WY Naughton PacifiCorp 4162 1 Averaging Plan 0.40 0.51 0.45 WY Naughton PacifiCorp 4162 2 Averaging Plan 0.40 0.48 0.45 WY Naughton PacifiCorp 4162 3 Averaging Plan 0.40 0.35 0.45 WY Wyodak PacifiCorp 6101 BW91 Averaging Plan 0.50 0.29 0.45 
B-2, 1

Appendix B-2: List of Averaging Plans and Results in 2000

Company ORIS Code Plant Name, State and Units Plan Limit 

AES Westover, LLC

2526 AES Westover NY Units 11 - 13

0.45 

2527 Greenidge NY Units 4 - 66082 Kintigh NY Unit 12535 Milliken NY Units 1, 2

Allegheny Energy Supply Co., LLC 3942 Albright WV Units 1 - 3 0.56 

3178 Armstrong PA Units 1, 23943 Fort Martin WV Units 1, 23944 Harrison WV Units 1 - 33179 Hatfield's Ferry PA Units 1 - 33181 Mitchell PA Unit 336004 Pleasants WV Units 1, 21570 R P Smith MD Units 9, 113945 Rivesville WV Units 7, 83946 Willow Island WV Units 1, 2

Ameren Services 861 Coffeen IL Units 01, 02 0.59 

862 Grand Tower IL Units 07 - 09863 Hutsonville IL Units 05, 06864 Meredosia IL Units 01 - 056017 Newton IL Units 1, 2

Ameren Services 2103 Labadie MO Units 1 - 4 0.52 

2104 Meramec MO Units 1 - 46155 Rush Island MO Units 1, 22107 Sioux MO Units 1, 2
Appendix B-2: List of Averaging Plans and Results in 2000

Company ORIS Code Plant Name, State and Units Plan Limit 

B-2, 2

American Electric Power Service 1353 Big Sandy KY Unit BSU1 0.61 

2828 Cardinal/Tidd OH Units 1 - 33775 Clinch River VA Units 1 - 32840 Conesville OH Units 3, 48102 Gen J M Gavin OH Units 1, 23776 Glen Lyn VA Units 6, 51, 523947 Kammer WV Units 1 - 33936 Kanawha River WV Units 1, 23948 Mitchell WV Units 1, 26264 Mountaineer (1301) WV Unit 12872 Muskingum River OH Units 1 - 53938 Phil Sporn WV Units 11, 21, 31, 41, 512843 Picway OH Unit 96166 Rockport IN Units MB1, MB2988 Tanners Creek IN Units U1 - U4

Arizona Public Service Company 2442 Four Corners NM Units 1 - 5 0.61 Associated Electric Cooperative 2167 New Madrid MO Units 1, 2 0.74 

2168 Thomas Hill MO Units MB1 - MB3

Boswell Energy Center 1893 Clay Boswell MN Units 1, 2, 4 0.41 

1891 Syl Laskin MN Units 1, 2
Appendix B-2: List of Averaging Plans and Results in 2000

Company ORIS Code Plant Name, State and Units Plan Limit 

B-2, 3

Carolina Power and Light Company 2706 Asheville NC Units 1, 2 0.44 

2708 Cape Fear NC Units 5, 63251 H B Robinson SC Unit 12713 L V Sutton NC Units 1 - 32709 Lee NC Units 1 - 36250 Mayo NC Units 1A, 1B2712 Roxboro NC Units 1, 2, 3A, 3B, 4A, 4B2716 W H Weatherspoon NC Units 1 - 3

Cinergy Corp. 1001 Cayuga IN Units 1, 2 0.49 

6018 East Bend KY Unit 21004 Edwardsport IN Units 7-1, 7-2, 8-16113 Gibson IN Units 1 - 52832 Miami Fort OH Units 5-1, 5-2, 6 - 81007 Noblesville IN Units 1 - 31008 R Gallagher IN Units 1 - 41010 Wabash River IN Units 1 - 62830 Walter C Beckjord OH Units 1 - 6

City Utilities of Springfield 2161 James River MO Units 3 - 5 0.50 

6195 Southwest MO Unit 1

Colorado Springs Utilities 492 Martin Drake CO Units 5 - 7 0.46 
Appendix B-2: List of Averaging Plans and Results in 2000

Company ORIS Code Plant Name, State and Units Plan Limit 

B-2, 4

Constellation Power Source Gen.,Inc.

602 Brandon Shores MD Units 1, 2 0.56 1552 C P Crane MD Units 1, 21554 Herbert A Wagner MD Units 2, 3

Consumers Energy Company 1695 B C Cobb MI Units 4, 5 0.46 

1702 Dan E Karn MI Units 1, 21720 J C Weadock MI Units 7, 81710 J H Campbell MI Units 2, 31723 J R Whiting MI Units 1 - 3

Dairyland Power Cooperative 4140 Alma WI Units B4, B5 0.48 

4143 Genoa WI Unit 14271 J P Madgett WI Unit B1

Dayton Power & Light Company 2850 J M Stuart OH Units 1 - 4 0.62 

6031 Killen Station OH Unit 22848 O H Hutchings OH Units H-1 - H-6

Detroit Edison Company 6034 Belle River MI Units 1, 2 0.53 

1731 Harbor Beach MI Unit 11732 Marysville MI Units 9, 10, 11, 121733 Monroe MI Units 1 - 41740 River Rouge MI Units 2, 31743 St Clair MI Units 1 - 4, 6, 71745 Trenton Channel MI Units 9A, 16 - 19
Appendix B-2: List of Averaging Plans and Results in 2000

Company ORIS Code Plant Name, State and Units Plan Limit 

B-2, 5

Dominion Generation 3796 Bremo Bluff VA Units 3, 4 0.41 

3803 Chesapeake VA Unit 3 3797 Chesterfield VA Units 5, 67213 Clover VA Units 1, 23804 Possum Point VA Unit 4 

Dynegy Midwest Generation, Inc. 889 Baldwin IL Units 1 - 3 0.59 

891 Havana IL Unit 9892 Hennepin IL Units 1, 2897 Vermilion IL Units 1, 2898 Wood River IL Units 4, 5

Dynegy Northeast Generation 2480 Danskammer NY Units 3, 4 0.40 FirstEnergy Corporation 2835 Ashtabula OH Units 7, 8, 10, 11 0.51 

2878 Bay Shore OH Units 1 - 46094 Bruce Mansfield PA Units 1 - 32837 Eastlake OH Units 1 - 52857 Edgewater OH Units 11 - 13 2858 Gorge OH Units 25, 262838 Lake Shore OH Unit 182864 R E Burger OH Units 1 - 82867 Toronto OH Units 9 - 112866 W H Sammis OH Units 1 - 7
Appendix B-2: List of Averaging Plans and Results in 2000

Company ORIS Code Plant Name, State and Units Plan Limit 

B-2, 6

Grand River Dam Authority 165 GRDA OK Units 1, 2 0.46 Hoosier Energy, REC, Inc. 1043 Frank E Ratts IN Units 1SG1, 2SG1 0.47 

6213 Merom IN Units 1SG1, 2SG1

IES Utilities, Inc. 1104 Burlington IA Unit 1 0.46 

1046 Dubuque IA Units 1, 51047 Lansing IA Units 1 - 31048 Milton L Kapp IA Unit 21073 Prairie Creek IA Units 3, 41058 Sixth Street IA Units 2 - 51077 Sutherland IA Units 1, 2

Indianapolis Power & Light Co. 990 Elmer W Stout IN Units 50, 60, 70 0.45 

991 H T Pritchard IN Units 3 - 6994 Petersburg IN Units 1 - 4

Kansas City Power & Light Co. 1241 La Cygne KS Units 1, 2 0.66 Lansing Board of Water and Light 1831 Eckert Station MI Units 1 - 6 0.45 

1832 Erickson MI Unit 1
Appendix B-2: List of Averaging Plans and Results in 2000

Company ORIS Code Plant Name, State and Units Plan Limit 

B-2, 7

Louisville Gas and Electric Co. 1355 E W Brown KY Units 1 - 3 0.45 

1356 Ghent KY Units 1 - 41357 Green River KY Units 1 - 51360 Pineville KY Unit 31361 Tyrone KY Unit 5

Midwest Generation EME, LLC 867 Crawford IL Units 7, 8 0.59 

886 Fisk IL Unit 19384 Joliet 29 IL Units 71, 72, 81, 82874 Joliet 9 IL Unit 5879 Powerton IL Units 51, 52, 61, 62883 Waukegan IL Units 7, 8 884 Will County IL Units 1 - 3

Mirant State Line Energy, LLC 981 State Line IN Units 3, 4 0.68 Northern Indiana Public Service Co. 995 Bailly IN Units 7, 8 0.75 

997 Michigan City IN Unit 126085 R M Schahfer IN Units 14, 15 

NSP (dba Xcel Energy) 1915 Allen S King MN Unit 1 0.54 

1904 Black Dog MN Units 1, 3, 41912 High Bridge MN Units 3 - 61918 Minnesota Valley MN Unit 41927 Riverside MN Units 6 - 86090 Sherburne County MN Units 1 - 3
Appendix B-2: List of Averaging Plans and Results in 2000

Company ORIS Code Plant Name, State and Units Plan Limit 

B-2, 8

Ohio Valley Electric Corporation 983 Clifty Creek IN Units 1 - 6 0.84 

2876 Kyger Creek OH Units 1 - 5

Orion Power Holdings, Inc. 2836 Avon Lake OH Units 10, 12 0.55 

8226 Cheswick PA Unit 13098 Elrama PA Units 1 - 43138 New Castle PA Units 3 - 5

Pacificorp 4158 Dave Johnston WY Units BW43, BW44 0.45 

6165 Hunter (Emery) UT Unit 38069 Huntington UT Unit 28066 Jim Bridger WY Units BW71 - BW734162 Naughton WY Units 1 - 36101 Wyodak WY Unit BW91

Public Service Co. of New Mexico 2451 San Juan NM Units 1 - 4 0.46 Public Service Company of Colorado 465 Arapahoe CO Units 1 - 4 0.80 Public Service Company of Colorado 469 Cherokee CO Units 1, 2 0.80 Public Service Electric & Gas Co. 2403 Hudson NJ Unit 2 0.64 

2408 Mercer NJ Units 1, 2
Appendix B-2: List of Averaging Plans and Results in 2000

Company ORIS Code Plant Name, State and Units Plan Limit 

B-2, 9

Reliant Energy Mid-Atlantic Power 3113 Portland PA Units 1, 2 0.44 

3130 Seward PA Units 12, 14, 153132 Warren PA Units 1 - 4

Rochester Gas & Electric Corp. 2642 Rochester 7 NY Units 1 - 4 0.40 Santee Cooper

130 Cross SC Unit 1

0.46 

3317 Dolphus M Grainger SC Units 1, 23319 Jefferies SC Units 3, 46249 Winyah SC Unit 1

South Carolina Electric & Gas Co. 3280 Canadys Steam SC Units CAN1 - CAN3 0.41 

7210 Cope Station SC Unit COP13287 McMeekin SC Units MCM1, MCM23295 Urquhart SC Units URQ1 - URQ3

South Mississippi Electric PowerAssociation 6061 R D Morrow MS Units 1, 2 0.50 
Appendix B-2: List of Averaging Plans and Results in 2000

Company ORIS Code Plant Name, State and Units Plan Limit 

B-2, 10

Southern Company 699 Arkwright GA Units 1 - 4 0.46 

3 Barry AL Units 1 - 5703 Bowen GA Units 1BLR - 4BLR641 Crist FL Units 4 - 726 E C Gaston AL Units 1 - 57 Gadsden AL Units 1, 28 Gorgas AL Units 6 - 1010 Greene County AL Units 1, 2708 Hammond GA Units 1 - 4709 Harllee Branch GA Units 1 - 4710 Jack McDonough GA Units MB1, MB22049 Jack Watson MS Units 4, 56002 James H Miller Jr AL Units 1 - 4733 Kraft GA Units 1 - 3643 Lansing Smith FL Units 1, 26124 McIntosh GA Unit 1727 Mitchell GA Unit 36257 Scherer GA Units 1 - 4642 Scholz FL Units 1, 26073 Victor J Daniel Jr MS Units 1, 26052 Wansley GA Units 1, 2728 Yates GA Units Y1BR - Y7BR

Southern Indiana Gas & Electric Co. 1012 F B Culley IN Units 1 - 3 0.50 
Appendix B-2: List of Averaging Plans and Results in 2000

Company ORIS Code Plant Name, State and Units Plan Limit 

B-2, 11

Tampa Electric Company 645 Big Bend FL Units BB01 - BB04 0.75 

646 F J Gannon FL Units GB03 - GB06

Tennessee Valley Authority 3393 Allen TN Units 1 - 3 0.57 

3396 Bull Run TN Unit 147 Colbert AL Units 1 - 53399 Cumberland TN Units 1, 23403 Gallatin TN Units 1 - 43406 Johnsonville TN Units 1 - 103407 Kingston TN Units 1 - 91378 Paradise KY Units 1 - 31379 Shawnee KY Units 1 - 950 Widows Creek AL Units 1 - 8

Western Kentucky Energy Co. 1381 Coleman KY Units C1 - C3 0.49 

6823 D B Wilson KY Unit W11382 HMP&L Station 2 KY Units H1, H26639 R D Green KY Units G1, G21383 Robert Reid KY Unit R1

Western Resources 6068 Jeffrey Energy Centr KS Units 1 - 3 0.40 

1250 Lawrence KS Units 3 - 51252 Tecumseh KS Units 9, 10
Appendix B-2: List of Averaging Plans and Results in 2000

Company ORIS Code Plant Name, State and Units Plan Limit 

B-2, 12

Wisconsin Electric Power Company 6170 Pleasant Prairie WI Units 1, 2 0.47 

4040 Port Washington WI Units 1 - 41769 Presque Isle MI Units 2 - 64041 South Oak Creek WI Units 5 - 84042 Valley WI Units 1 - 4

Wisconsin Power & Light Co 4050 Edgewater WI Units 4, 5 0.62 Wisconsin Public Service Corp. 4072 Pulliam WI Units 3 - 8 0.47 

4146 Stoneman WI Units B1, B24078 Weston WI Units 1 - 3
B-3, 1

Appendix B-3: Description of NOx Compliance Assessment Methodology

1. Emission Rate Evaluation for Single Unit Compliance

(a) Compliance Determination

The NOx emission limit for each unit is compared to the actual annual NOx emissions rates at the unit as

follows. If the unit has an alternative emissions limit (AEL) this limit is used instead of the base emission limit. 

(1) For units not associated with a specific stack or associated with multiple stacks only:

If unit NOx emission rate  unit NOx emission limit

Unit compliance status is Pass

else

Unit compliance status is Fail.

(2) For units associated with a single common stack: 

a. Locate the associated Stack ID for the unit in the ARCONFIG file.

b. If stack NOx emission rate  NOx emission limit

Unit compliance status is Pass

 else

Unit compliance status is Fail.

(3) For units associated with a complex stack configuration:

a. Locate all associated Stack IDs in ARCONFIG file.

b. Select highest NOx emission rate for all stacks.

c. If selected stack NOx emission rate  NOx emission limit

Unit compliance status is Pass

 else

d. Calculate NOx pounds for the unit as apportioned to the unit from each

stack

Unit/Stack NOx Pounds = Actual Stack NOx Emission Rate * Unit Heat Input Apportioned from the Stack
B-3, 2

e. Calculate the total actual NOx pounds for the unit:

 Unit NOx Pounds Emitted = Sum of Unit/Stack NOx Pounds Emitted for Each Unit/Stack

f. Calculate the allowable NOx pounds for the unit:

Unit Allowable NOx Pounds = Unit NOx Emission Limit * Actual Unit Heat Input

g. Determine compliance on a NOx pounds basis for the unit:

If Unit NOx Pounds Emitted  Unit Allowable NOx Pounds

Unit compliance status is Pass

else

Unit compliance status is Fail.

(b) Excess Emission Calculation

If the unit compliance status is fail, excess emissions are computed as follows: 

(1) Compute allowable tons from the unit:

NOx Pounds Allowable = Unit NOx Emission Limit * Actual Annual Unit Heat Input

(2) Compute actual pounds emitted from the unit:

a. For units not associated with any stack or for units associated with a single common stack or for

units with multiple stacks only: 

Unit NOx Pounds Emitted = Actual NOx Emission Rate * Actual Annual Unit Heat Input

b. For units in a complex stack configuration

Unit NOx Pounds Emitted = Sum of (Unit Apportioned Heat Input from Each Stack * 

Actual NOx Emission Rate for Each Stack)
B-3, 3

(3) Determine exceedance (tons, rounded to one decimal place):

NOx Tons Exceedance = (NOx Pounds Emitted  NOx Pounds Allowable) / 2000

2. Determining Compliance of Units in Averaging Plans

(a) Compliance Determination

For each averaging plan, a NOx emissions limit is calculated as follows. 

(1) Calculate the allowable NOx pounds for the each unit in the plan:

Unit NOx Pounds Allowable = Unit NOx Emission Limit * Actual Annual Unit Heat Input 

(2) Calculate the total allowable NOx pounds for the plan:

Total NOx Pounds Allowable for Plan = Sum of All Units NOx Pounds Allowable

(3) Calculate the total actual heat input for the plan:

Total Actual Heat Input for Plan = Sum of Annual Heat Input for All Units

(4) Calculate the allowable NOx emission rate for the plan:

Allowable NOx Emission Rate for Plan = Total NOx Pounds Allowable for Plan / Total Heat Input for Plan

(5) Calculate the actual NOx pounds for each unit:

 a. For units not associated with a common stack: 

Unit NOx Pounds Emitted = Actual NOx Emission Rate * Annual Unit Heat Input

b. For each stack associated with the plan:

Stack NOx Pounds Emitted = Actual NOx Emission Rate * Annual Stack Heat Input 
B-3, 4

(6) Calculate the actual NOx pounds for the plan:

Actual NOx Pounds Emitted for the Plan = Sum of the Unit and Stack NOx Pounds Emitted

(7) Calculate the total actual heat input for the plan:

Total Heat Input for the Plan = Sum of the Annual Heat Input for Each Unit 

or Stack with Measured Data

(8) Calculate the Annual NOx emission rate for the plan:

 Annual NOx Emissions Rate for the Plan = Actual NOx Pounds Emitted /

Annual Heat Input for the Plan 

(9) Determine NOx compliance for the plan:

If Actual NOx Pounds Emitted for the Plan  NOx Pounds Allowable for the plan

plan compliance status is Pass

else

 plan compliance status is Fail.

(b) Excess Emission Calculation

If the plan compliance status is fail, excess emissions are computed in tons to one decimal place as follows: 

NOx Tons Exceedance = (NOx Pounds Emitted  NOx Pounds Allowable) / 2000