United States

Environmental Protection

Agency

Office of Air and Radiation

Clean Air Markets Division

(6204J)

EPA-430-R-00-007

July 2000

1999 Compliance Report

 

Visit us at www.epa.gov/acidrain
BACKGROUND

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

calls for major reductions of sulfur dioxide (SO2) and nitrogen oxides (NOX), the pollutants that cause acid rain,

while establishing a new approach to environmental protection through the use of market incentives. 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 units to select their own

methods of compliance. The Program also sets NOX emission limitations (in lb/mmBtu) for electric utilities

representing about a 27 percent reduction from 1990 levels. The Acid Rain Program is implemented in two

phases: Phase I began in 1995 for SO2 and 1996 for NOX, and ended December 31, 1999; Phase II for both

pollutants began January1, 2000 and involves over 2,300 units. In 1999, there were 398 units affected by the

SO2 provisions of the Acid Rain Program, 236 of which were also affected for NOX, and an additional 303

utility units affected only by the NOX provisions.

Acid rain causes acidification of lakes and streams and contributes to the damage of trees at high elevations. In

addition, acid rain accelerates the decay of building materials, paints, and cultural artifacts, including

irreplaceable buildings, statues, and sculptures. While airborne, SO2 and NOX gases and their particulate matter

derivatives, sulfates and nitrates, contribute to visibility degradation and impact public health.

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 maintenance of the environmental goal. The Program features tradable 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 emissions starting either in Phase I or Phase II of the

Program.

The NOX component of the Acid Rain Program is more traditional, and establishes an emission rate limit for all

NOX-affected units. Flexibility is also 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,

beginning in 1997, certain Phase II units could voluntarily elect to become subject to Acid Rain NOX limits

before January 1, 2000, the date by which they would normally be subject. By complying with Phase I limits,

these early election units can delay meeting 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 the NOX portion of the Program, utilities must achieve an annual emission limitation at or below mandated

levels. 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 previous 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. In addition, in 1995-1999 (Phase I of the

Program), units must have sufficient allowances to cover certain other deductions as well. Any remaining SO2

allowances may be sold or banked for use in future years.
Table of Contents

Letter from the Director .............................................................. 1

Summary ......................................................................... 2

Affected Population in Phase I ......................................................... 4

SO2 Results

Program ....................................................................... 4

Compliance Results .............................................................. 5

Allowance Market ............................................................... 8

NOX Results

Program ...................................................................... 11

Phase I Units .................................................................. 12

Phase I Compliance Results ....................................................... 13

Phase II Early Election Units ....................................................... 15

Phase II Early Election Compliance Results ............................................ 16

Monitoring Update ................................................................. 17

Conclusion ....................................................................... 19

Appendix A: Phase I Affected And Early Election Units in 1999

Appendix B-1: Table 1 Units Designating Substitution and Compensating Units - 1999

Appendix B-2: List of Phase I Extension Units and 1999 Deductions for Exceeding 1999 Projected

Emissions Limitations

Appendix B-3: Emissions and Utilization of Phase I Units, 1998 and 1999

Appendix B-4: Emissions and Allowance Holdings of Phase I Units

Appendix C-1: List of Averaging Plans and Results in 1999

Appendix C-2: Compliance Results for the 265 Phase I NOX Affected Units in 1999

Appendix C-3: Compliance Results for the 274 Early Election Units in 1999
1999 Compliance Report Page 1

TO THE READER:

It’s hard to believe that over 5 years have passed since January 1, 1995 and the official beginning of Phase I

of the Acid Rain Program. Yet the publishing of this 1999 Compliance Report for the Acid Rain Program

brings to a close Phase I (which officially ended December 31, 1999) and marks the beginning of Phase II,

which of course officially began on January 1, 2000.

From a regulatory standpoint, the end of Phase I and the beginning of Phase II means a simpler, more

streamlined Program. Relatively complicated Phase I SO2 compliance options such as substitution and

compensating unit plans, Phase I extension plans, and reduced utilization plans disappear beginning in Phase

II. Beginning in 2000, affected units are simply required to hold allowances to account for their SO2

emissions.

Similarly, the end of Phase I also marks the end of EPA’s responsibility as the permitting authority for Phase I

affected sources. In Phase II, the State or Local title V permitting authority is the sole permitting authority for

all affected sources, including Phase I affected sources formerly permitted by EPA.

But while becoming simpler administratively, the end of Phase I and the beginning of Phase II also brings

significant new challenges. The number of affected units that must undergo annual reconciliation under the

Acid Rain Program expands notably in Phase II. For SO2 purposes, the number of affected units that must

hold allowances to account for SO2 emissions will grow more than fivefold, from 398 units in 1999 to over

2100 units for compliance year 2000. Also, units subject to an Acid Rain NOX emissions limitation will

almost double in Phase II, from 539 units in 1999 (including early election units) to about 1050 units

beginning in 2000.

New units that will be subject to the Acid Rain Program are being built as well. Currently, the Acid Rain

Program expects that about 500 new affected units will come online over the next 2 years. Affected

companies, EPA, and States will need to ensure that these units comply with all requirements of the Program,

including the requirements to monitor properly under 40 CFR part 75 (the Acid Rain Program monitoring

rule) and to hold sufficient allowances to account for SO2 emissions for each compliance year.

As we move to Phase II, I am looking forward to working with all parties involved in the implementation of

the Acid Rain Program, and in furthering the promise shown by the successful implementation of Phase I.

Brian J. McLean, Director

Clean Air Markets Division
1999 Compliance Report Page 2

SUMMARY

100 Percent Compliance with both SO2 and NOX Requirements in 1999

All 701 boilers and combustion turbines (referred to as “units”) affected by the SO2 and NOX regulations of

the Acid Rain Program in 1999 successfully met their emissions compliance obligations.

‚ All 398 units subject to SO2

 requirements in 1999 held sufficient allowances to cover their emissions. Of

the 4,948,090 allowances deducted from compliance accounts almost all (4,944,665 or 99.93 percent)

were for emissions, but other deductions were also made as required by the Acid Rain Program

regulations. 

‚ All 539 units subject to the NOX requirements in 1999 demonstrated compliance with applicable annual

emission limitations. Of these 539 units, 236 were also subject to SO2 requirements, while 303 units

were affected only for NOX (33 Phase I units and 270 Phase II “early election” units). 

1999 SO2 Emissions of Phase I Units were 29 Percent Below Allowable Level; Emission Rates 45

Percent Lower Than in 1990.

SO2 emissions in 1999 were 2.0 million tons (or 29 percent) below the 6.9 million ton allowable level as

determined by 1999 allowance allocations. Since an additional 9.6 million allowances were carried over, or

banked, from 1998, the overall number of allowances available in 1999 was 16.5 million, of which affected

units consumed only about 30 percent. Actual emissions for the 398 units participating in 1999 were 4.9

million tons, down 350,000 tons from emissions of the 408 units affected in 1998. In 1999, SO2 emission

rates of Phase I units averaged 1.86 lbs/mmBtu, down from 3.37 lbs/mmBtu in 1990 for those same units.

1999 Phase I Unit NOX Emission Rates 43 Percent Below 1990; NOX Tons 32 Percent Lower Than

in 1990

Emission rates for the 265 Phase I utility units dropped by 43 percent below 1990 levels, from an average of

0.70 pounds of NOX per million Btu of heat input (lb/mmBtu) to an average of 0.40 lbs/mmBtu; this rate is 18

percent below the compliance rate of 0.49 lbs/mmBtu for these units. NOX emission levels for these units

were 423,857 tons (or 32 percent) below 1990 levels.

1999 NOX Emission Rates of Early Election Units Even Lower Than Rates for Phase I Units

For the 274 Phase II units which elected to meet Phase I NOX rates early, emission rates dropped from an

average of 0.46 lbs/mmBtu in 1990 to 0.37 lbs/mmBtu in 1999, a 20 percent decrease and 21 percent below

the compliance rate of 0.47 lbs/mmBtu for these units. While utilization of these units increased by 28 percent

between 1990 and 1999, NOX tons increased by only 3 percent.
1999 Compliance Report Page 3

Monitoring Performance Excellent Once Again

For the fifth year of the Acid Rain Program, the continuous emission monitors used by participants continue

to provide some of the most accurate and complete data ever collected by the EPA. Statistics reflect

excellent monitor operation of all units affected by both Phase I and Phase II of the program.

Accuracy: : SO2 monitors achieved a median relative accuracy (i.e., deviation from the reference

test method) of 3.0 percent; flow monitors, 3.2 percent; and NOX monitors, 3.6

percent. Any statistically significant systematic underestimation (low bias) is

corrected to eliminate any systematic errors. 

 Availability:SO2 and flow monitors achieved a median availability of 99.5 and 99.7 percent, respectively,

while NOX monitors achieved a median availability of 99.2 percent.

SO2 Market Active; Volume of Allowances Transferred Continues to Increase in 1999

Activity in the allowance market continued to increase in 1999. The total volume of allowances transferred

increased from 13.5 million in 1998 to 18.7 million in 1999, however transfers of allowances between

unrelated parties decreased from 9.5 million in 1998 to 6.2 million in 1999.
1999 Compliance Report Page 4

1 During Phase I of the of the Acid Rain Program, a unit not originally affected until Phase II may elect to

enter the program early as a substitution unit or a compensating unit to help fulfill the compliance obligations for one

of the Table 1 units targeted by Phase I. A unit brought into Phase I as a substitution unit can assist a Table 1 unit

in meeting its emissions reductions obligations. Utilities may make cost-effective emissions reductions at the

substitution unit instead of at the Table 1 unit, achieving the same overall emissions reductions that would have

occurred without the participation of the substitution unit. A Table 1 unit may designate a Phase II unit as a

substitution unit only if both units are under the control of the same owner or operator. Additionally, Table 1 units

that reduce their utilization below their baseline may designate a compensating unit to provide compensating

generation to account for the reduced utilization of the Table 1 unit. (A unit's baseline is defined as its heat input

AFFECTED POPULATION IN PHASE I

Exhibit 1 provides a summary of the affected population of units under the Acid Rain Program from 1995

through 1999. The table illustrates that although the units listed in Table 1 of the CAAA are consistently

affected for both SO2 and NOX beginning in 1996, the total universe of affected units varies year to year

because of the flexibility offered by the program. 

Exhibit 1

Affected Units During Phase I of the Acid Rain Program

1995 1996 1997 1998 1999

SO2 Table 1 263 263 263 263 263

Substitution and

Compensating

182 161 153 135 125

Opt-in 0 7 7 10 10

TOTAL 445 431 423 408 398

NOX Table 1 NA 144 170 171 171

Substitution NA 95 95 94 94

Early-Election NA NA 272 275 274

TOTAL NA 239 537 540 539

SO2 PROGRAM

398 Units Underwent Annual Reconciliation for SO2 in 1999

There were 388 affected utility units and 10 opt-in units that underwent annual reconciliation in 1999 to

determine whether sufficient allowances were held to cover emissions. These 398 units are listed in Appendix

A and include 263 utility units specifically required to participate during Phase I, 125 utility units not initially

required to participate until Phase II, but electing to participate early as part of multi-unit compliance plans,1
1999 Compliance Report Page 5

averaged over the years 1985-1987). A Table 1 unit may designate a Phase II unit as a compensating unit if the

Phase II compensating unit is in the Table 1 unit's dispatch system or has a contractual agreement with the Table 1

unit, and the emissions rate of the compensating unit has not declined substantially since 1985. See Appendix B-1

for the relationship of these units to their Table 1 counterparts.

2

The Opt-in Program gives sources not required to participate in the Acid Rain Program the opportunity to

enter the program on a voluntary basis, install continuous emission monitoring systems (CEMS), reduce their SO2

emissions, and receive their own allowances.

and 10 other units that elected to join as part of the Opt-in Program.2 There were 10 fewer units undergoing

annual reconciliation in 1999 than in 1998. 

1999 SO2 Emissions Target was 6.99 Million Tons 

The number of allowances allocated in a particular year, the amount representing that year's allowable SO2

emissions level, is the sum of allowance allocations granted to sources under several provisions of the Act. In

1999, the emissions target established by the program for the 398 participating units was 6.99 million tons. 

However, the total allowable SO2 emission level in 1999 was actually 16.62 million tons, consisting of the

6.99 million 1999 allowances granted through the program and an additional 9.63 million allowances carried

over, or banked, from 1998.

The initial allocation and the allowances for substitution and compensating units represent the basic

allowances granted to units that authorize them to emit SO2 under the Acid Rain Program. Additional

allowances for the year 1999 were also made available through the allowance auctions, held annually since

1993. Other allowances issued in 1999 were from special provisions in the Act, which are briefly explained

in Exhibit 2 on the following page. In addition, any allowances carried over from previous years (banked

allowances) are available for compliance and included in the allowable total. 

Beginning in the year 2000 at the onset of Phase II, the volume of allowances allocated annually to the Phase

I units will be reduced and the requirement to hold allowances will be extended to smaller, cleaner plants. 

Nationwide, the cap for all utilities with an output capacity of greater than 25 megawatts will be 9.48 million

allowances from 2000-2009. In 2010, the cap will be reduced further to 8.95 million allowances, a level

approximating one half of industry-wide emissions in 1980.

SO2 COMPLIANCE RESULTS

Phase I Units Better 1999 SO2 Allowable Emissions Level by 29 Percent

The Phase I units affected in 1999 emitted at a level approximately 29 percent below 1999 allocations, as

shown in Exhibit 3. This percentage is greater than that of 1998, since SO2 emissions decreased while

allocations remained relatively constant. Appendix B-3 reports the 1999 emission and utilization levels for all

Phase I affected units, as well as a comparison to these levels in 1998.
1999 Compliance Report Page 6

Relative to 1998, the 263 Table 1 units decreased their emissions by about 310,000 tons, or more than seven

percent in 1999, while decreasing their utilization by just under one percent. The 4.35 million tons emitted by

these Table 1 units were still substantially below their 1999 allocation of 5.55 million allowable tons.

Exhibit 2

Origin of 1999 Allowable Emissions Level

Type of Allowance

Allocation

Number of

Allowances

Explanation of Allowance Allocation Type

Initial Allocation 5,550,820 Initial Allocation is the number of allowances granted to units

based on their historic utilization, emissions rates specified in the

Clean Air Act and other provisions of the Act.

Phase I Extension 171,710 Phase I Extension allowances are given to Phase I units that

reduce their emissions by 90 percent or reassign their emissions

reduction obligations to units that reduce their emissions by 90

percent.

Allowances for Substitution Units 909,455 Allowances for Substitution Units are the initial allocation

granted to Phase II units which entered Phase I as substitution

units.

Allowance Auctions 150,000 Allowance Auctions provide allowances to the market that were

set aside in a Special Allowance Reserve when the initial

allowance allocation was made.

Allowances for Compensating

Units

85,138 Allowances for Compensating Units are the initial allocation

granted to Phase II units which entered Phase I as compensating

units.

Opt-in Allowances 97,392 Opt-in Allowances are provided to units entering the program

voluntarily. 

Small Diesel Allowances 25,617 Small Diesel Allowances are allocated annually to small diesel

refineries that produce and desulfurize diesel fuel during the

previous year. These allowances can be earned through 1999.

TOTAL 1999 ALLOCATION 6,990,132

BANKED 1998 ALLOWANCES 9,627,980 Banked Allowances are those held over from 1995 through 1998

which can be used for compliance in 1999 or any future year.

TOTAL 1999 ALLOWABLE 16,618,112

Substitution and compensating units in 1999 expended a lower percentage of their annual allocation then in

1998. In 1999, these 125 units were responsible for emitting approximately 510,000 tons of SO2, about 52

percent of their 990,000 allowance allocation. In 1998, 135 substitution and compensating units emitted

approximately 550,000 tons of SO2, or 58 percent of their 950,000 allowable level.
1999 Compliance Report Page 7

0

1

2

3

4

5

6

7

8

9

10

1995 1996

95 Alloc. 95 Emiss. 96 Alloc. 96 Emiss. 97 Alloc. 97 Emiss. 98 Alloc. 98 Emiss. 99 Alloc. 99 Emiss.

Table 1 5.55 4.45 5.55 4.77 5.55 4.77 5.55 4.66 5.55 4.35

S & C 1.33 0.85 1.18 0.63 1.04 0.62 0.95 0.55 0.99 0.51

Other 1.86 0.00 1.57 0.04 0.56 0.08 0.45 0.08 0.45 0.08

TOTALS 8.74 5.30 8.30 5.44 7.15 5.47 6.95 5.29 6.99 4.94

1997 1998 1999 

Allowances

Allowances

Allowances

Allowances

Emissions Emissions Emissions Emissions

Exhibit 3

Summary of SO2 Emissions versus Allocations

(Millions of Tons)

Allowances

Emissions

No new opt-in units joined the program in 1999, so the total allocation to opt-ins of 97,000 allowances

remained almost the same as in 1998, but emissions levels rose from 80,000 tons in 1998 to 84,000 tons in

1999. The percentage of emissions to allowances allocated to opt-in units in 1999 therefore rose to 87

percent, as compared to 82 percent in 1998.

Deducting Allowances for Compliance

The total number of allowances deducted in 1999 was 4,948,090 which represents approximately 71 percent

of all 1999 allowances issued. Almost all (99.93 percent) of the deducted allowances were for emissions. 

Exhibit 4 displays these allowance deductions, as well as the remaining bank of 1995 through 1999

allowances. 

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
1999 Compliance Report Page 8

3Qualifying technology is defined at 40 CFR 72.2.

4 Beginning in 1997, each of the 19 units designated as control units was required to show it had reduced

its annual emissions by at least 90 percent using qualifying control technology. If a unit could not make this

demonstration, all or a portion of the extension allowances it received for the year under the Phase I Extension

provisions were required to be surrendered. In addition, also beginning in 1997, each of the same 19 control units

and each of the 61 other units designated as transfer units was required to meet a tonnage emission limitation

approved in its permit. A unit that exceeded its limitation was required to surrender allowances for the following

year.

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. Appendix B-4 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.

Under the Acid Rain Program, certain units applied for and received approval of Phase I Extension plans

during the Phase I permitting process. These units fell into two categories: “control units” which were

required to cut their emissions by 90 percent using qualifying technology3 by 1997, and “transfer units” which

reassigned their emissions reduction obligations to a control unit. Both kinds of units received extra SO2

emissions allowances to cover the SO2 they emitted beyond their basic Phase I allocations during 1995 and

1996. In addition, the control units were given Phase I extension allowances for 1997, 1998, and 1999. A

total of 3.5 million allowances was distributed to all Phase I extension control and transfer units.4

For 1999, all 19 control units demonstrated meeting the 90 percent reduction requirement and, therefore, did

not surrender any 1999 extension allowances. The 1999 tonnage emissions limitation, though, was exceeded

by three control units and three transfer units and resulted in a surrender of a total of 22,477 vintage 2000

allowances. The deduction amounts for each Phase I extension unit are included in Appendix B-2.

SO2 ALLOWANCE MARKET

The flexibility provided by the Acid Rain Program enabled the 398 units subject to an SO2 emissions

limitation in 1999 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 overcontrol their SO2 emissions 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 overcontrolled. 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

enabled all 398 sources to be in compliance in 1999 and significantly reduced the cost of achieving these

emissions reductions as compared to the cost of a technological mandate. 
1999 Compliance Report Page 9

Exhibit 4

 SO2 Allowance Reconciliation Summary

Total Allowances Held in Accounts as of 3/1/00 (1995 through 1999 Vintages)* 16,556,056

 Table 1 Unit Accounts 8,577,556

 Substitution & Compensating Unit Accounts 1,137,851

 Opt-in Accounts 87,482

 Other Accounts** 6,753,167

Allowances Deducted for Emissions in 1999 4,944,676

 Table 1 Unit Accounts 4,350,181

 Substitution & Compensating Unit Accounts 510,495

 Opt-in Unit Accounts 84,000

Allowances Deducted Under Special Phase I Provisions in 1999*** 3,425

 Table 1 Unit Accounts 980

 Substitution & Compensating Unit Accounts 2,311

 Opt-in Unit Accounts 134

Banked Allowances 11,607,955

 Table 1 Unit Accounts 4,226,395

 Substitution & Compensating Unit Accounts 625,045

 Opt-in Unit Accounts 3,348

 Other Accounts** 6,753,167

 * The number of allowances held in the Allowance Tracking System (ATS) accounts equals the number of 1999 allowances 

allocated (see Exhibit 2) plus the number of 1998 banked allowances. March 1, 2000 represents the Allowance Transfer

Deadline, the point in time at which the 1999 Phase I affected unit accounts are frozen and after which no transfers of 1995

through 1999 allowances will be recorded. The freeze on these accounts is removed when annual reconciliation is complete.

 ** Other accounts refers to general accounts within the ATS that can be held by any utility, individual or other

organization, and unit accounts for units not affected in Phase I.

***Allowances were deducted for both underutilization and state cap provisions in 1999 (see Appendix B-4 for a thorough

explanation).

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, but declined from over $200 in early 1999 to less than $150 by the end of 1999. 

The price was $131/ton at the 2000 allowance auction, and prices have remained in the $130 to $140 range

since January of 2000. Some market observers believe lower than expected allowance prices during the first

several years of the program were due primarily to lower than expected compliance costs and larger than

expected emission reductions, which have increased the supply of allowances and put downward pressure on

prices. Exhibit 5 displays the price trend since mid-1994, based on monthly price reports from Cantor

Fitzgerald Environmental Brokerage Services, and a market survey conducted by Fieldston Publications. 
1999 Compliance Report Page 10

SO2 Allowance Price Indices

$0

$50

$100

$150

$200

$250

Jan-94 Jan-95 Jan-96 Jan-97 Jan-98 Jan-99 Jan-00

Fieldston Publications Price Index Cantor Fitzgerald Market Price Index

Exhi

bit 5

Activity in the allowance market created under the Acid Rain Program remained strong in 1999, with 2,832

transactions moving about 18.7 million allowances in the Allowance Tracking System (ATS), the accounting

system developed to track holdings of allowances. In terms of economically significant transfers, or those

between unrelated parties, the volume of allowances declined from 9.5 million in 1998 to 6.2 million in 1999. 

Thirty three percent of annual activity consisted of allowances transferred between economically distinct

organizations, with a little less than half of that amount represented by allowances directly acquired by utilities. 

The most active market segment in 1999 in terms of allowance volume was composed of exchanges in the

reallocation category, which covered 11.4 million allowances. The next most active segment were trades

between brokers/traders and utilities, which accounted for 3.4 million allowances.

All transactions, along with data on account balances and ownership, are posted on the Acid Rain Division’s

Internet site (www.epa.gov/acidrain) on a daily basis in order to better inform trading participants. Also

available are cumulative market statistics and analysis.
1999 Compliance Report Page 11

0

5

10

15

20

1994 1995 1996 1997 1998 1999

Allowances (Millions)

Transactions Between Economically Related Entities

Transactions Between Economically Unrelated Entities

Exhibit 6

 SO2 Allowances Transferred Under the Acid Rain Program

ACID RAIN NOX PROGRAM

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

standard emission limitations for 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 in two phases.

In April 1995, EPA promulgated 40 CFR part 76, 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 or tangentially-fired boilers). Phase I dry bottom wall-fired boilers are subject

to a NOX emission limit of 0.50 lb/mmBtu; Phase I tangentially-fired boilers are subject to a NOX emission

limit of 0.45 lb/mmBtu.

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 can demonstrate compliance

with the higher Phase I limits for their boiler type from 1997 through 2007 and not meet the more stringent

Phase II limits until 2008. If the 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 revised the NOX emission limits for Phase II, Group 1 boilers (0.46 lb/mmBtu for

dry bottom wall-fired boilers and 0.40 lb/mmBtu for tangentially-fired boilers) and established emission limits
1999 Compliance Report Page 12

for cell burner, cyclone, wet bottom and vertically-fired boilers (referred to as "Group 2 boilers") effective on

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

projected to be approximately 400,000 tons per year in 1996 through 1999 (Phase I), and 2,060,000 tons

per year in 2000 and subsequent years (Phase II).

PHASE I NOX UNITS

265 Phase I Units Were Subject to Emission Limitations in 1999

In 1999, 265 coal-fired utility units were subject to the Title IV Phase I emission limitations for NOX. The 265

Phase I NOX affected units include 171 Table 1 units and 94 substitution units whose owners chose to

participate in Phase I as part of an SO2 compliance strategy. This group of units is subject to the Phase I

emission limitations throughout Phase I and Phase II. Exhibit 7 below shows the number of Phase I NOX

affected units by boiler type.

Exhibit 7

Phase I NOX Units by Boiler Type

Boiler Type Standard 

Emission Limit

Table 1 

Units

Substitution

Units All Units

Tangentially-fired Boilers 0.45 94 41 135

Dry Bottom Wall-fired Boilers 0.50 77 53 130

Phase I NOX Compliance Options

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

may qualify for one of two additional compliance options which add flexibility to the rate-based compliance

requirements: 

! 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 properly installed and operated low NOX burner technology (LNBT)

designed to meet the standard limit, but is unable to achieve that limit. EPA determines whether an

AEL is warranted based on analyses of emissions data and information about the NOX control

equipment.

Exhibit 8 summarizes the compliance options chosen by Phase I affected NOX units for 1999. As in 1996,
1999 Compliance Report Page 13

5

For a more detailed description of the 1990 baseline refer to the Acid Rain Program 1996 Compliance

Report.

1997, and 1998, averaging was the most widely chosen compliance option. For 1999, there were 22

averaging plans involving 204 Phase I NOX units. See Appendix C-1: List of Averaging Plans and Results in

1999.

Exhibit 8

Compliance Options Chosen in 1999

Compliance Option Number of Units

Compliance with Standard Emission Limitation 51

Emissions Averaging 204

Alternative Emission Limitation 10

TOTAL 265

PHASE I NOX COMPLIANCE RESULTS

For 1999, EPA has determined that all 265 Phase I NOX units met the required emission limit through

compliance with either the standard emission limitation, emissions averaging, or an alternative emission

limitation. See Appendix C-2: Compliance Results for the 265 NOX Affected Units. For a more detailed

description of EPA's methodology for determining compliance with Phase I NOX limits, see Appendix C-4 in

the Acid Rain Program 1996 Compliance Report.

NOX Emission Rate Reduction

From 19905 to 1999, the average NOX emission rate of the 265 Phase I units declined by 43 percent (from

0.70 lb/mmBtu to 0.40 lb/mmBtu). As shown in Exhibit 9, on average, both Table 1 and substitution units

were below the average Phase I emission limit of 0.49 lb/mmBtu (the heat input weighted average of the

applicable limits).
1999 Compliance Report Page 14

Exhibit 9

Average NOX Emission Rates for 265 Phase I Units

0.77

0.45 0.44 0.43 0.42

0.52

0.36 0.36 0.37 0.34

0.00

0.20

0.40

0.60

0.80

1.00

1990 1996 1997 1998 1999

NOX Rate 

(lb/mmBtu)

Table 1 Units (171) Substitution Units (94)

Weighted Average

Emissions Limitation

(0.49)

NOX Mass Emissions Reduction

Exhibit 10 illustrates the change in NOX mass emissions since 1990 for Table 1 and substitution units. For the

265 units, total NOX mass emissions in 1999 were 32 percent lower than in 1990, and 3 percent lower than in

1998. However, in 1999, total heat input was only 0.1 percent lower than in 1998. Therefore, the 2 percent

decrease in the NOX emission rate from 0.41 lb/mmBtu 1998 to 0.40 lb/mmBtu in 1999 had a greater impact

on the reduction in NOX mass emissions in 1999 than the reduction in total heat input.
1999 Compliance Report Page 15

6

 Compared with 1998, the universe of early election units was the same, except that the early election plan

for D.B. Wilson Unit W1 was terminated effective January 1, 1999.

Exhibit 10

NOX Mass Emissions for 265 Phase I Units

1,046,339

669,017 676,797 686,492 672,265

287,583

239,373 241,694 257,176 237,800

0

400,000

800,000

1,200,000

1,600,000

1990 1996 1997 1998 1999

NOX 

Tons

Table 1 Units (171) Substitution Units (94)

PHASE II EARLY ELECTION UNITS

274 Units Were Subject to Early Election Requirements in 1999

Nineteen ninety-nine was the third year in which early election utilities were required to meet the Phase I NOX

limit.6 Exhibit 11 shows the number of early election units by boiler type and their corresponding emission

limit.

Exhibit 11

Distribution of 1999 Early Election Units by Boiler Type

Boiler Type Standard 

Emission Limit

Operating Phase II,

Group 1 Units 

Early Election

Units

Percent of 

Units Electing

Tangentially-fired 0.45 300 171 57%

Dry Bottom Wall-fired 0.50 314 103 33%

Total 614 274 45%
1999 Compliance Report Page 16

PHASE II EARLY ELECTION COMPLIANCE RESULTS

For 1999, EPA determined that all 274 units complied with the Phase I, Group 1 emission limitations and have

continued eligibility for early election in 2000 through 2007. See Appendix C-3: Compliance Results for the

274 Early Election Units in 1999.

Average NOX emission rates for early election units have declined by 20 percent, from 0.46 lb/mmBtu in 1990

to 0.37 lb/mmBtu in 1999. This decline is less dramatic than the decline at Phase I NOX units because 51

percent of the early election units are newer units already subject to the 1979 New Source Performance

Standards (NSPS) NOX emission limits. The overall NOX emission rate for the early election units is

comparable to the average rate of 0.40 lb/mmBtu for all Phase I NOX units. Exhibit 12 summarizes the NOX

emission rate reductions from 1990 to 1999 by boiler type for the 264 early election units that were operating

in 1990.

Exhibit 12

Average NOX Emission Rate for 264 Early Election Units

0.45

0.37 0.37 0.36

0.47

0.38 0.38 0.38

0.00

0.20

0.40

0.60

0.80

1990 1997 1998 1999 1990 1997 1998 1999

NOX Rate 

(lb/mmBtu)

Dry-Bottom Wall-Fired Boilers 

Emissions Limit (0.50)

Tangentially-Fired Boilers

Emissions Limit (0.45)

NOX Mass Emissions Reduction

The total NOX mass emissions from the operating early election units increased by 25,708 tons (or 2 percent)

from 1990 to 1999, reflecting an increase in utilization (see Exhibit 13). However, for the 264 early election

units operating in 1990, heat input increased during the nine year period by approximately 28 percent. The

NOX mass emissions decreased by 4 percent from 1998 to 1999, due to a 1 percent decrease in heat input

and a 3 percent decrease in the overall NOX emission rate.
1999 Compliance Report Page 17

Exhibit 13

NOX Mass Emissions for 264 Early Election Units

716,480 750,872 772,054 736,161

565,084 576,567 594,394 578,383

0

400,000

800,000

1,200,000

1,600,000

1990 1997 1998 1999

NOX 

Tons

T-Fired Units (163) DB Units (101)

SO2 AND NOX MONITORING IN 1999

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

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

and complete accounting of pollutant emissions from affected boilers and turbines. To implement this

objective, concentrations of emitted SO2 and NOX from each affected unit (boiler or turbine) 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.

CEMS are used to determine SO2 mass emissions and NOX emission rates. 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. 

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 relative accuracy test audit 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
1999 Compliance Report Page 18

standard in order to be qualified to report emissions to the Acid Rain Program; 10 percent for SO2 and NOX,

and 15 percent for flow (beginning January 1, 2000, the flow standard is 10 percent). As a further incentive

for high quality maintenance, CEMS that achieve a superior accuracy result, less than or equal to 7.5 percent

for SO2 and NOX and less than or equal to 10 percent for flow (beginning January 1, 2000, the flow standard

for superior accuracy is 7.5 percent), are granted a reduced frequency annual RATA requirement in place of

the semiannual requirement. 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 is required to ensure that

emissions are not underestimated: the bias test. 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 14 highlights the

relative accuracy results achieved by Acid Rain CEMS in 1999. 

Exhibit 14

1999 Relative Accuracy Test Audit (RATA) Results

SO2 Concentration Volumetric Flow Rate NOX Rate

Mean Relative Accuracy 4.2% 3.9% 4.5%

Median Relative Accuracy 3.0% 3.2% 3.4%

Percent Meeting Relative Accuracy

Standard

96.2% 99.4% 95.7%

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 15 shows the

monitor availabilities reported in 1999 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 15

1999 CEMS Availability

Parameter Median % Availability at End of 1999

Coal-Fired Units Oil and Gas Units

SO2 99.5 98.9

Flow 99.7 99.0

NOX 99.2 98.4
1999 Compliance Report Page 19

7

 Lynch, James A., Van C. Bowersox, and Jeffrey W. Grimm. 2000. “Changes in Sulfate Deposition in

Eastern USA Following Implementation of Phase I of Title IV of the Clean Air Act Amendments of 1990.” 

Atmospheric Environment 34: 1665-1680. 

CONCLUSION

1999 proved to be another successful year for both the Acid Rain Program’s rate-based approach to NOX

reduction and cap-and-trade approach to SO2 reduction. In 1999, all Phase I affected utility units not only

met their compliance goals, but exceeded them, achieving an overall reduction of 423,857 tons of NOX from

1990 levels, and maintaining the extraordinary reductions of more than 5 million tons of SO2 from 1980 levels,

first achieved in 1995. Additionally, the 274 Phase II NOx early election units had increased emissions of two

percent since 1990, while their utilization increased by 28 percent during the same period.

Exceedance of compliance goals translates into additional environmental and health benefits. For example, the

greater and earlier reductions of SO2 have resulted in a 10 - 25 percent drop in rainfall acidity in the Northeast

in 1995 through 1997 since the beginning of Phase I.7

One factor mitigating the benefit of the overcompliance in the SO2 program, of course, is the ability to use

banked allowances in the future. The 40 percent of 1995 allowances, 35 percent of 1996 allowances, 23

percent of 1997 allowances, 24 percent of 1998 allowances, and 29 percent of 1999 allowances that were

not retired for compliance purposes can be used to cover emissions in a later year. However, receiving health

and environmental benefits earlier may be of greater value than receiving those benefits several years from

now.

The NOX program, based on the more traditional rate-based approach, offers less flexibility and displays a

lesser degree of overcompliance. It requires each unit to achieve reductions or, at a minimum, for a group of

units to achieve an average emission rate equal to or lower than their individual limits. This approach does not

allow emission reductions in one year to be used in another year, and as a result, the incentive to overcomply is

diminished. 

The pattern and certainty of emissions reductions over time will also differ between the two programs. 

Beginning in the year 2000 when both programs are in full implementation, SO2 emissions are expected to

decline steadily toward the emissions cap level of 8.95 million tons, whereas NOX emissions, in the absence of

an emissions cap, are expected to rise as existing sources are utilized more and new sources, which are not

required to offset their emissions, are built and operated.

Despite these differences, both the SO2 and NOX components of the Acid Rain Program were successful in

Phase I. Through the continued efforts of Phase I participants and with additional reductions from Phase II

units beginning in 2000, the long term goals of the Acid Rain Program -- a 10 million ton reduction of SO2

emissions and two million ton reduction of NOX emissions -- will be achieved.
A-1

APPENDIX A: PHASE I AFFECTED (T) AND EARLY ELECTION (E) UNITS IN 1999

ST Plant Name Unit ID SO2 NOx ST Plant Name Unit ID SO2 NOx

AL Charles R Lowman 2 E CO Cherokee 3 E

3 E 4 E

AL Colbert 1 T T CO Pawnee 1 E

2 T T

3 T T CO Rawhide 101 E

4 T T

5 T T CO Ray D Nixon 1 E

AL E C Gaston 1 T T CO Valmont 5 E

2 T T

3 T T CT Bridgeport Harbor BHB3 E

4 T T

5 T T FL Big Bend BB01 T

BB02 T

AL Gadsden 1 T T BB03 T

2 T T BB04 T T

AR Flint Creek 1 E FL C D McIntosh 3 E

AR Independence 1 E FL Crist 4 T T

2 E 5 T T

6 T T

AR White Bluff 1 E 7 T T

2 E

FL Crystal River 2 E

AZ Apache 2 E 4 E

3 E 5 E

AZ Cholla 1 E FL Deerhaven B2 E

2 E

3 E FL St Johns River 1 E

4 E 2 E

AZ Coronado U1B E FL Scholz 1 T T

U2B E 2 T T

AZ Navajo 1 E FL Seminole 1 E

2 E 2 E

3 E

GA Arkwright 1 T T

AZ Springerville 1 E 2 T T

2 E 3 T T

4 T T

COO Craig C1 E

C2 E GA Bowen 1BLR T T

C3 E 2BLR T T

3BLR T T

CO Comanche 1 E 4BLR T T

2 E
APPENDIX A: PHASE I AFFECTED (T) AND EARLY ELECTION (E) UNITS IN 1999

ST Plant Name Unit ID SO2 NOx ST Plant Name Unit ID SO2 NOx

A-2

GA Hammond 1 T T IA George Neal South 4 E

2 T T

3 T T IA Lansing 4 E

4 T T

IA Louisa 101 E

GA Harllee Branch 1 T

2 T T IA Milton L Kapp 2 T T

3 T

4 T IA Ottumwa 1 E

GA Jack McDonough MB1 T T IA Prairie Creek 4 T T

MB2 T T

IA Riverside 9 T T

GA Kraft 1 T T

2 T T IL Baldwin 1 T

3 T T 2 T

3 T T

GA Mcintosh 1 T T

IL Coffeen 1 T

GA Mitchell 3 T T 2 T

GA Scherer 3 T IL Crawford 7 E

4 E 8 E

GA Wansley 1 T T IL Dallman 33 E

2 T T

IL Fisk 19 E

GA Yates Y1BR T T

Y2BR T T IL Grand Tower 7 T

Y3BR T T 8 T

Y4BR T T 9 T T

Y5BR T T

Y6BR T T IL Havana 6 T

Y7BR T T

IL Hennepin 1 T

IA Ames 7 E 2 T T

8 E

IL Hutsonville 5 T T

IA Burlington 1 T T 6 T T

IA Council Bluffs 1 E IL Joppa Steam 1 T T

2 E 2 T T

3 E 3 T T

4 T T

IA Des Moines 11 T 5 T T

6 T T

IA George Neal North 1 T

2 E IL Kincaid 1 T

3 E 2 T
APPENDIX A: PHASE I AFFECTED (T) AND EARLY ELECTION (E) UNITS IN 1999

ST Plant Name Unit ID SO2 NOx ST Plant Name Unit ID SO2 NOx

A-3

IL Meredosia 1 T IN Frank E Ratts 1SG1 T T

2 T 2SG1 T T

3 T

4 T IN Gibson 1 T T

5 T T 2 T T

3 T T

IL Newton 1 T T 4 T T

2 T

IN H T Pritchard 3 T

IL Vermilion 1 T T 4 T

2 T T 5 T T

6 T T

IL Waukegan 7 E

8 E IN Merom 1SG1 E

2SG1 E

IL Will County 3 E

4 E IN Michigan City 12 T

IL Wood River 1 T IN Petersburg 1 T T

2 T T

IN A B Brown 1 E 3 T

2 E 4 T

IN Bailly 7 T IN R M Schahfer 15 E

8 T 17 E

18 E

IN Breed 1 T

IN R Gallagher 1 T T

IN Cayuga 1 T T 2 T T

2 T T 3 T T

4 T T

IN Clifty Creek 1 T

2 T IN Rockport MB1 E

3 T MB2 E

4 T

5 T IN State Line 3 E

6 T

IN Tanners Creek U4 T

IN Dean H Mitchell 4 E

5 E IN Wabash River 1 T T

6 E 2 T T

11 E 3 T T

5 T T

IN Elmer W Stout 50 T T 6 T T

60 T T

70 T T IN Warrick 1 T

2 T

IN F B Culley 2 T T 3 T

3 T T 4 T
APPENDIX A: PHASE I AFFECTED (T) AND EARLY ELECTION (E) UNITS IN 1999

ST Plant Name Unit ID SO2 NOx ST Plant Name Unit ID SO2 NOx

A-4

IN Whitewater Valley 1 E KY R D Green G1 T T

2 E G2 T T

KS La Cygne 1 T KY Shawnee 10 T

2 T

KY Trimble County 1 E

KS Nearman Creek 1 E

KY W C Dale 3 E

KS Quindaro 2 T T 4 E

KS Riverton 39 E LA Big Cajun 2 2B1 E

40 E 2B2 E

2B3 E

KY Cane Run 4 E

5 E LA Dolet Hills 1 E

6 E

LA R S Nelson 6 E

KY Coleman C1 T T

C2 T T LA Rodemacher 2 E

C3 T T

MA Brayton Point 1 T

KY Cooper 1 T T 2 T

2 T T

MA Mount Tom 1 T

KY E W Brown 1 T T

2 T T MD C P Crane 1 T

3 T T 2 T

KY East Bend 2 T T MD Chalk Point 1 T T

2 T T

KY Elmer Smith 1 T 3 T

2 T T

MD Morgantown 1 T T

KY Ghent 1 T T 2 T T

KY Green River 5 T T MD R P Smith 9 T T

11 T T

KY H L Spurlock 1 T T

2 E MI B C Cobb 4 E

5 E

KY Hmp&L Station 2 H1 T T

H2 T T MI Dan E Karn 2 T

KY l Mill Creek 1 E MI J B Sims 3 E

2 E

3 E MI J C Weadock 7 T E

4 E 8 T E

KY Paradise 3 T MI J H Campbell 1 T T

2 T
APPENDIX A: PHASE I AFFECTED (T) AND EARLY ELECTION (E) UNITS IN 1999

ST Plant Name Unit ID SO2 NOx ST Plant Name Unit ID SO2 NOx

A-5

MI J R Whiting 1 T E MO Sibley 1 T

2 T 2 T

3 T E 3 T

MI Presque Isle 7 E MO Sioux 1 T

8 E 2 T

9 E

MO Sikeston 1 E

MN Clay Boswell 3 E

MO Southwest 1 T T

MN High Bridge 3 T T

4 T T MO Thomas Hill MB1 T

5 T T MB2 T

6 T T MB3 T T

MN Hoot Lake 2 E MS Jack Watson 4 T T

5 T T

MN Sherburne County 1 T T

2 T T MS R D Morrow 1 T T

2 T T

MO Asbury 1 T

MS Victor J Daniel Jr 1 T

MO Hawthorn 5 T T 2 T

MO Iatan 1 T MT Colstrip 1 E

2 E

MO James River 3 T T 3 E

4 T T 4 E

5 T T

MT Lewis & Clark B1 E

MO Labadie 1 T T

2 T T NC Buck 5 E

3 T T 6 E

4 T T 7 E

8 E

MO Meramec 1 T T 9 E

2 T T

3 T T NC Cliffside 1 E

4 T 2 E

3 E

MO Montrose 1 T T 4 E

2 T T 5 E

3 T T

NC Dan River 1 E

MO New Madrid 1 T 2 E

2 T 3 E

MO Rush Island 1 T T

2 T T
APPENDIX A: PHASE I AFFECTED (T) AND EARLY ELECTION (E) UNITS IN 1999

ST Plant Name Unit ID SO2 NOx ST Plant Name Unit ID SO2 NOx

A-6

NC G G Allen 1 E NY C R Huntley 67 E

2 E 68 E

3 E

4 E NY Dunkirk 1 E

5 E 2 E

3 T T

NC Marshall 1 E 4 T T

2 E

3 E NY Greenidge 6 T T

4 E

NY Kintigh 1 E

NC Riverbend 7 E

8 E NY Milliken 1 T T

9 E 2 T T

10 E

NY Northport 1 T

ND Antelope Valley B1 E 2 T

B2 E 3 T

4 T

ND Leland Olds 1 E

NY Port Jefferson 3 T

ND Stanton 10 E 4 T

NE Gerald Gentleman 1 E NY S A Carlson 9 E

2 E 10 E

11 E

NE Gerald Whelan 1 E 12 E

NE Nebraska City 1 E OH Acme 13 T

14 T

NE North Omaha 4 E 15 T

16 T

NE Platte 1 E 91 T

92 T

NHE Merrimack 1 T

2 T OH Ashatabula 7 T T

8 T

NJ B L England 1 T 9 T

2 T 10 T

11 T

NM Escalante 1 E

OH Avon Lake 9 T

NV Mohave 1 E 10 T

2 E 11 T

12 T

NV North Valmy 1 E

2 E OH Bay Shore 1 T

2 T

NV Reid Gardner 4 E 3 T

4 T
APPENDIX A: PHASE I AFFECTED (T) AND EARLY ELECTION (E) UNITS IN 1999

ST Plant Name Unit ID SO2 NOx ST Plant Name Unit ID SO2 NOx

A-7

OH Cardinal 1 T OH Muskingum River 1 T

2 T 2 T

3 T

OH Conesville 1 T 4 T

2 T 5 T

3 T T

4 T T OH Niles 1 T

5 E 2 T

6 E

OH Picway 9 T T

OH Eastlake 1 T T

2 T T OH Poston 1 T

3 T T 2 T

4 T T 3 T

5 T

OH R E Burger 1 T

OH Edgewater 11 T 2 T

12 T 3 T

13 T T 4 T

5 T

OH Gen J M Gavin 1 T 6 T

2 T 7 T T

8 T T

OH Gorge 25 T T

26 T T OH Toronto 9 T

10 T T

OH J M Stuart 1 T 11 T T

2 T

3 T OH W H Sammis 5 T T

4 T 6 T T

7 T

OH Kyger Creek 1 T

2 T OH W H Zimmer 1 E

3 T

4 T OH Walter C Beckjord 5 T T

5 T 6 T T

OH Lake Shore 18 T OK Muskogee 4 E

91 T 5 E

92 T 6 E

93 T

94 T OK Northeastern 3313 E

3314 E

OH Miami Fort 5-1 T

5-2 T OK Sooner 1 E

6 T T 2 E

7 T

OR Boardman 1SG E

PA Armstrong 1 T T

2 T T
APPENDIX A: PHASE I AFFECTED (T) AND EARLY ELECTION (E) UNITS IN 1999

ST Plant Name Unit ID SO2 NOx ST Plant Name Unit ID SO2 NOx

A-8

PA Bruce Mansfield 1 T T PA Shawville 1 T T

2 T T 2 T T

3 E 3 T T

4 T T

PA Brunner Island 1 T T

2 T T PA Sunbury 3 T T

3 T T 4 T T

PA Cheswick 1 T T PA Titus 1 E

2 E

PA Conemaugh 1 T T 3 E

2 T T

SC Cross 1 E

PA Cromby 1 E 2 E

PA Eddystone 1 E SC W S Lee 1 E

2 E 2 E

3 E

PA Hatfield’s Ferry 1 T

2 T TN Allen 1 T

3 T 2 T

3 T

PA Homer City 1 E

2 E TN Cumberland 1 T

3 E 2 T

PA Keystone 1 E TN DuPont JVD1 T

2 E Johnsonville JVD2 T

JVD3 T

PA Martins Creek Cree 1 T T JVD4 T

2 T T

3 T TN Gallatin 1 T T

4 T 2 T T

3 T T

PA Mitchell 33 T T 4 T T

PA Montour 1 E TN John Sevier 1 E

2 E 2 E

3 E

PA New Castle 1 T T 4 E

2 T T

3 E

4 E

5 E

PA Portland 1 T T

2 T T
APPENDIX A: PHASE I AFFECTED (T) AND EARLY ELECTION (E) UNITS IN 1999

ST Plant Name Unit ID SO2 NOx ST Plant Name Unit ID SO2 NOx

A-9

TN Johnsonville 1 T T TX Tolk 171B E

2 T T 172B E

3 T T

4 T T TX W A Parish WAP5 E

5 T T WAP6 E

6 T T WAP7 E

7 T T WAP8 E

8 T T

9 T T TX Welsh 1 E

10 T T 2 E

3 E

TX Big Brown 1 E

2 E UT Bonanza 1-1 E

TX Coleto Creek 1 E UT Carbon 1 E

2 E

TX Gibbons Creek 1 E

UT Hunter 1 E

TX Harrington 061B E 2 E

062B E

063B E UT Huntington 1 E

TX J K Spruce XX1 E UT Intermountain 1SGA E

2SGA E

TX J T Deely 1 E

2 E VA Chesapeake 1 E

2 E

TX Limestone LIM1 E 4 E

LIM2 E

VA Chesterfield 3 E

TX Martin Lake 1 E 4 E

2 E

3 E VA Glen Lyn 51 E

52 E

TX Monticello 1 E

2 E VA Possum Point 3 E

3 E

VA Potomac River 1 E

TX Oklaunion 1 E 2 E

3 E

TX Pirkey 1 E 4 E

5 E

TX Sam Seymour 1 E

2 E VA Yorktown 1 E

3 E 2 E

TX San Miguel SM-1 E WA Centralia BW21 E

BW22 E

TX Sandow 4 E
APPENDIX A: PHASE I AFFECTED (T) AND EARLY ELECTION (E) UNITS IN 1999

ST Plant Name Unit ID SO2 NOx ST Plant Name Unit ID SO2 NOx

A-10

WI Alma B1 T WI Weston 1 T T

B2 T 2 T T

B3 T 3 T

B4 T T

B5 T T WV Albright 1 T T

2 T T

WI Blount Street 8 E 3 T T

9 E

WV Fort Martin 1 T T

WI Columbia 1 E 2 T

2 E

WV Harrison 1 T T

WI Edgewater 3 T 2 T T

4 T 3 T T

5 E

WV Kammer 1 T

WI Genoa 1 T T 2 T

3 T

WI J P Madgett B1 T T

WV Mitchell 1 T T

WI Nelson Dewey 1 T 2 T T

2 T

WV Mountaineer 1 E

WI North Oak Creek 1 T

2 T WV Mt Storm 1 T T

3 T 2 T T

4 T 3 T T

WI Port Washington 1 T WV Pleasants 1 T

2 T 2 T

3 T

4 T WV Rivesville 7 T

5 T 8 T

WI Pulliam 5 T WY Dave Johnston BW41 E

6 T BW42 E

7 T T

8 T T WY Jim Bridger BW71 T

BW72 T

WI Rock River 1 T BW73 T

2 T BW74 E

WI South Oak Creek 5 T T WY Laramie River 1 E

6 T T 2 E

7 T T 3 E

8 T T

WY Wyodak BW91 T

WI Valley 1 T

2 T

3 T

4 T
B-1, 1

APPENDIX B-1:

Table 1 Units Designating Substitution and Compensating Units for 1999

Substitution Units

Table 1 Units Substitution Units

State Plant Name Units State Plant Name Units

AL EC Gaston 5 AL Gadsden 1,2

FL Big Bend BB01, BB02, BB03 FL Big Bend BB04

FL Crist 7 FL Crist 4,5

FL Scholz 1,2

GA Bowen 1BLR GA Harllee Branch 1

GA Bowen 2BLR GA Harllee Branch 2

GA Bowen 3BLR GA Harllee Branch 3

GA Bowen 4BLR GA Harllee Branch 4

GA Hammond 1 GA Arkwright 1

GA Hammond 2 GA Arkwright 2

GA Hammond 3 GA Arkwright 3

GA Hammond 4 GA Arkwright 4

GA Jack Mcdonough MB2 GA Mitchell 3

GA Yates Y2BR GA Kraft 1

GA Yates Y3BR GA Kraft 2

GA Yates Y4BR GA Kraft 3

GA Yates Y5BR GA McIntosh 1

IL Baldwin 3 IL Havana 6

IL Wood River 1

IL Hennepin 2 IL Hennepin 1

IL Meredosia 5 IL Hutonsville 5,6

IL Newton 1,2

IL Vermilion 2 IL Vermilion 1
B-1, 2

APPENDIX B-1:

Table 1 Units Designating Substitution and Compensating Units for 1999

Substitution Units

Table 1 Units Substitution Units

State Plant Name Units State Plant Name Units

IN Petersburg 1,2 IN H T Pritchard 5

KY Coleman C1, C2 KY R D Green G1, G2

MD C P Crane 2 MS R D Morrow 1,2

MD Morgantown 1,2 MD Chalk Point 3

MI J H Campbell 1,2 MI Dan E Karn 2

MI J R Whiting 1,2,3

MI J C Weadlock 7,8

MN High Bridge 6 MN High Bridge 3,4,5

MN Sherburne County 1,2

MO James River 5 MO James River 3,4

MO Southwest 1

MO Labadie 1,2,3,4 MO Meramec 1,2,3

MO Rush Island 1,2

MO Montrose 1,2,3 MO Hawthorn 5

MO Sioux 1,2 KS La Cygne 1

MO Sibley 3 MO Sibley 1,2

MO Thomas Hill MB1, MB2 MO Thomas Hill MB3

NH Merrimack 1,2 MA Mount Tom 1
B-1, 3

APPENDIX B-1:

Table 1 Units Designating Substitution and Compensating Units for 1999

Substitution Units

Table 1 Units Substitution Units

State Plant Name Units State Plant Name Units

NY Northport 1,2,3 NY Northport 4

OH Ashtabula 7 OH Acme 13,14,15,16,91,92

OH Ashtabula 8,9,10,11

OH Lake Shore 18,91,92,93,94

OH Bay Shore 1,2,3,4

OH Avon Lake 12 OH Avon Lake 9,10

OH Conesville 4 OH J M Stuart 1,2,3,4

OH Edgewater 13 OH Edgewater 11,12

OH Niles 1,2 OH R E Burger 1,2,3,4

OH R E Burger 5,6,7,8 OH Gorge 25, 26

OH W H Sammis 5,6,7 OH Toronto 9,10,11

PA Bruce Mansfield 1,2

PA New Castle 1,2

OH Miami Fort 7 KY East Bend 2

OH Picway 9 OH Poston 1,2,3

PA Armstrong 1 WV Albright 1

PA Armstrong 2 WV Albright 2

PA Hatfield's Ferry 3 PA Mitchell 33

PA Martin's Creek 1,2 PA Martin's Creek 3,4

WI Edgewater 4 WI Edgewater 3

WI Genoa 1 WI Alma B4, B5

WI J P Madgett B1

WI Nelson Dewey 1,2 WI Rock River 1,2

WI Pulliam 8 WI Pulliam 5,6,7

WI Weston 1,2

WV Albright 3 MD R P Smith 9
B-1, 4

APPENDIX B-1:

Table 1 Units Designating Substitution and Compensating Units for 1999

Substitution Units

Table 1 Units Substitution Units

State Plant Name Units State Plant Name Units

WV Fort Martin 2 MD R P Smith 11

WV Harrison 1 WV Rivesville 7,8

Compensating Units

Table 1 Units Compensating Units

State Plant Name Units State Plant Name Units

OH Edgewater 13 MA Brayton Point 1,2
 APPENDIX B-2: 2000 DEDUCTION FOR EXCEEDING 1999 PHASE I EXTENSION

PROJECTED EMISSIONS LIMITATION

State Plant Name Unit ID

Ph I Ext 

Type

2000 Allowance 

Deduction

AL Colbert 5 TRANSFER 0

FL Crist 7 TRANSFER 0

GA Jack Mcdonough MB1 TRANSFER 0

GA Wansley 2 TRANSFER 0

GA Yates Y1BR CONTROL 0

GA Yates Y6BR TRANSFER 0

GA Yates Y7BR TRANSFER 0

IN Bailly 7 CONTROL 0

IN Bailly 8 CONTROL 0

IN Cayuga 1 TRANSFER 0

IN Cayuga 2 TRANSFER 0

IN Gibson 4 CONTROL 6734

IN Michigan City 12 TRANSFER 0

IN R Gallagher 1 TRANSFER 0

IN R Gallagher 2 TRANSFER 0

IN R Gallagher 3 TRANSFER 0

IN R Gallagher 4 TRANSFER 0

IN Wabash River 1 CONTROL 0

IN Wabash River 2 TRANSFER 642

IN Wabash River 5 TRANSFER 0

IN Wabash River 6 TRANSFER 3659

KY Coleman C1 TRANSFER 0

KY Coleman C2 TRANSFER 0

KY Coleman C3 TRANSFER 0

KY E W Brown 2 TRANSFER 0

KY E W Brown 3 TRANSFER 0

KY Ghent 1 CONTROL 0

KY Green River 5 TRANSFER 0

KY Hmp&L Station 2 H1 CONTROL 1061

KY Hmp&L Station 2 H2 CONTROL 1712

KY Paradise 3 TRANSFER 0

MD C P Crane 1 TRANSFER 0

MD Chalk Point 1 TRANSFER 0

MD Morgantown 1 TRANSFER 8669

MD Morgantown 2 TRANSFER 0

NJ B L England 1 TRANSFER 0

NJ B L England 2 CONTROL 0

OH Cardinal 1 TRANSFER 0

OH Conesville 1 TRANSFER 0

OH Conesville 3 TRANSFER 0

OH Eastlake 5 TRANSFER 0

OH Gen J M Gavin 1 CONTROL 0

OH Gen J M Gavin 2 CONTROL 0

OH Muskingum River 1 TRANSFER 0

OH Muskingum River 2 TRANSFER 0

OH Muskingum River 3 TRANSFER 0

OH Muskingum River 4 TRANSFER 0

OH Niles 1 TRANSFER 0

OH Niles 2 TRANSFER 0

OH Picway 9 TRANSFER 0

OH R E Burger 5 TRANSFER 0

OH R E Burger 6 TRANSFER 0

OH R E Burger 7 TRANSFER 0

OH R E Burger 8 TRANSFER 0

PA Armstrong 1 TRANSFER 0

PA Brunner Island 2 TRANSFER 0

PA Brunner Island 3 TRANSFER 0

PA Conemaugh 1 CONTROL 0

PA Conemaugh 2 CONTROL 0

PA Hatfield's Ferry 1 TRANSFER 0

PA Hatfield's Ferry 2 TRANSFER 0

PA Hatfield's Ferry 3 TRANSFER 0

PA Portland 1 TRANSFER 0

PA Portland 2 TRANSFER 0

PA Sunbury 3 TRANSFER 0

PA Sunbury 4 TRANSFER 0

TN Cumberland 1 CONTROL 0

TN Cumberland 2 CONTROL 0

TN Gallatin 1 TRANSFER 0

TN Gallatin 2 TRANSFER 0

B-2, 1
 APPENDIX B-2: 2000 DEDUCTION FOR EXCEEDING 1999 PHASE I EXTENSION

PROJECTED EMISSIONS LIMITATION

State Plant Name Unit ID

Ph I Ext 

Type

2000 Allowance 

Deduction

TN Gallatin 3 TRANSFER 0

TN Gallatin 4 TRANSFER 0

WV Fort Martin 1 TRANSFER 0

WV Fort Martin 2 TRANSFER 0

WV Harrison 1 CONTROL 0

WV Harrison 2 CONTROL 0

WV Harrison 3 CONTROL 0

WV Mt Storm 1 TRANSFER 0

WV Mt Storm 2 TRANSFER 0

WV Mt Storm 3 CONTROL 0

B-2, 2
APPENDIX B-3: EMISSIONS AND UTILIZATION OF PHASE I UNITS FOR 1998 AND 1999

1998 1999 Percent Change, 1998-1999

SO2 Utilization SO2 Utilization SO2 Utilization

State Plant Name Stack/Unit ID Unit Type Emissions (mmBtu) Emissions (mmBtu) Emissions (mmBtu)

AL Colbert CSCO14 (1, 2, 3, 4) 26,653 22,601 -15.20%

AL Colbert 1 Table1 13,688,471 12,943,613 -5.44%

AL Colbert 2 Table1 11,842,057 13,543,511 14.37%

AL Colbert 3 Table1 11,608,467 12,242,925 5.47%

AL Colbert 4 Table1 10,521,841 10,357,632 -1.56%

AL Colbert 5 Table1 27,619,312 47,608 26,136,552 46,972 -5.37% -1.34%

AL E C Gaston CS0CAN (1, 2) 25,864 29,118 12.58%

AL E C Gaston 1 Table1 16,687,420 19,395,339 16.23%

AL E C Gaston 2 Table1 16,356,089 15,425,345 -5.69%

AL E C Gaston CS0CBN (3, 4) 25,669 28,502 11.04%

AL E C Gaston 3 Table1 18,250,153 19,463,758 6.65%

AL E C Gaston 4 Table1 16,100,133 17,436,563 8.30%

AL E C Gaston 5 Table1 55,502,484 41,489 55,088,509 43,508 -0.75% 4.87%

AL Gadsden 1 Substitution 3,411,299 4,751 3,203,864 4,242 -6.08% -10.71%

AL Gadsden 2 Substitution 3,271,925 4,463 3,083,316 4,289 -5.76% -3.90%

FL Big Bend XS12 (BB01, BB02) 90,881 80,704 -11.20%

FL Big Bend BB01 Table1 26,361,877 24,289,751 -7.86%

FL Big Bend BB02 Table1 25,476,465 24,843,034 -2.49%

FL Big Bend XS23 (BB03, BB04) 16,544 14,910 -9.88%

FL Big Bend BB03 Table1 26,111,060 22,280,740 -14.67%

FL Big Bend BB04 Substitution 36,267,261 29,950,140 -17.42%

FL Crist 4 Substitution 4,108,663 3,255 4,655,839 3,329 13.32% 2.27%

FL Crist 5 Substitution 5,008,436 3,872 3,438,040 2,391 -31.36% -38.25%

FL Crist 6 Table1 18,656,237 14,461 18,654,562 13,233 -0.01% -8.49%

FL Crist 7 Table1 35,964,652 29,005 35,766,644 26,748 -0.55% -7.78%

FL Scholz 1 Substitution 1,583,869 1,877 2,268,731 1,557 43.24% -17.05%

FL Scholz 2 Substitution 2,415,353 2,877 2,483,103 1,733 2.80% -39.76%

GA Arkwright CS001 (1, 2, 3, 4) 4,272 4,089 -4.28%

GA Arkwright 1 Substitution 1,138,948 956,636 -16.01%

GA Arkwright 2 Substitution 1,048,245 1,093,075 4.28%

GA Arkwright 3 Substitution 1,220,110 1,340,936 9.90%

GA Arkwright 4 Substitution 797,426 1,302,409 63.33%

GA Bowen 1BLR Table1 46,331,230 34,016 40,516,647 28,631 -12.55% -15.83%

GA Bowen 2BLR Table1 37,829,783 28,130 47,588,155 34,348 25.80% 22.10%

GA Bowen 3BLR Table1 63,956,453 47,897 51,726,332 37,294 -19.12% -22.14%

GA Bowen 4BLR Table1 47,544,565 35,108 56,716,400 39,881 19.29% 13.60%

GA Hammond CS001 (1, 2, 3) 9,842 10,346 5.12%

GA Hammond 1 Table1 4,057,785 5,405,746 33.22%

GA Hammond 2 Table1 5,257,052 4,903,152 -6.73%

GA Hammond 3 Table1 4,656,394 4,332,311 -6.96%

GA Hammond 4 Table1 18,223,752 13,217 28,036,147 19,579 53.84% 48.13%

GA Harllee Branch CS001 (1, 2) 32,342 28,996 -10.35%

GA Harllee Branch 1 Substitution 13,350,533 13,400,598 0.38%

GA Harllee Branch 2 Substitution 16,451,112 13,491,886 -17.99%

GA Harllee Branch CS002 (3, 4) 56,643 48,692 -14.04%

B-3, 1
APPENDIX B-3: EMISSIONS AND UTILIZATION OF PHASE I UNITS FOR 1998 AND 1999

1998 1999 Percent Change, 1998-1999

SO2 Utilization SO2 Utilization SO2 Utilization

State Plant Name Stack/Unit ID Unit Type Emissions (mmBtu) Emissions (mmBtu) Emissions (mmBtu)

GA Harllee Branch 3 Substitution 24,716,035 22,932,668 -7.22%

GA Harllee Branch 4 Substitution 28,122,964 24,325,002 -13.50%

GA Jack Mcdonough CS001 (MB1, MB2) 28,516 24,212 -15.09%

GA Jack Mcdonough MB1 Table1 16,039,404 15,633,200 -2.53%

GA Jack Mcdonough MB2 Table1 19,355,611 14,883,963 -23.10%

GA Kraft CS001 (1, 2, 3) 5,906 6,759 14.44%

GA Kraft 1 Substitution 2,430,615 2,586,590 6.42%

GA Kraft 2 Substitution 1,960,136 2,979,207 51.99%

GA Kraft 3 Substitution 4,977,302 6,125,772 23.07%

GA Mcintosh 1 Substitution 7,791,088 6,716 7,499,008 6,182 -3.75% -7.95%

GA Mitchell 3 Substitution 4,595,267 4,621 4,621,450 4,430 0.57% -4.13%

GA Wansley 1 Table1 49,668,355 44,760 51,825,369 43,290 4.34% -3.28%

GA Wansley 2 Table1 48,149,781 42,489 45,235,063 37,418 -6.05% -11.93%

GA Yates Y1BR Table1 3,531,547 131 4,575,331 179 29.56% 36.64%

GA Yates CS001 (Y2BR, Y3BR) 6,865 7,191 4.75%

GA Yates Y2BR Table1 4,503,564 5,696,913 26.50%

GA Yates Y3BR Table1 3,787,505 4,695,297 23.97%

GA Yates CS002 (Y4BR, Y5BR) 9,136 8,588 -6.00%

GA Yates Y4BR Table1 6,401,735 5,726,354 -10.55%

GA Yates Y5BR Table1 4,344,893 6,821,224 56.99%

GA Yates Y6BR Table1 13,969,410 11,192 14,029,905 9,001 0.43% -19.58%

GA Yates Y7BR Table1 15,552,726 12,150 15,927,124 10,447 2.41% -14.02%

IA Burlington 1 Table1 11,743,015 5,847 13,326,811 6,502 13.49% 11.20%

IA Des Moines 11 Table1 0 0 0 0 0.00% 0.00%

IA George Neal North 1 Table1 9,767,070 3,974 9,089,694 3,420 -6.94% -13.94%

IA Milton L Kapp 2 Table1 12,293,176 5,282 11,001,299 4,437 -10.51% -16.00%

IA Prairie Creek 4 Table1 10,102,922 4,035 10,107,574 3,773 0.05% -6.49%

IA Riverside 9 Table1 6,283,598 1,435 5,936,674 1,879 -5.52% 30.94%

IL Baldwin 1 Table1 27,377,162 71,396 25,862,726 65,231 -5.53% -8.63%

IL Baldwin 2 Table1 35,735,840 92,968 36,155,350 91,310 1.17% -1.78%

IL Baldwin 3 Table1 46,260,316 120,253 34,819,083 88,703 -24.73% -26.24%

IL Coffeen CS0001 (1, 2) 49,413 47,611 -3.65%

IL Coffeen 1 Table1 12,847,399 17,489,341 36.13%

IL Coffeen 2 Table1 28,483,817 27,231,154 -4.40%

IL Grand Tower 9 Table1 3,949,534 9,188 3,175,149 6,813 -19.61% -25.85%

IL Havana 6 Substitution 61,257 29 84,268 28 37.56% -3.45%

IL Hennepin CS3 (1, 2) 46,809 27,532 -41.18%

IL Hennepin 1 Substitution 3,345,169 3,841,714 14.84%

IL Hennepin 2 Table1 15,865,737 12,303,540 -22.45%

IL Hutsonville 5 Substitution 2,449,651 5,238 2,384,627 5,189 -2.65% -0.94%

IL Hutsonville 6 Substitution 2,476,690 5,666 2,503,864 5,463 1.10% -3.58%

IL Joppa Steam CS1 (1, 2) 8,280 7,627 -7.89%

IL Joppa Steam 1 Table1 16,642,916 14,362,052 -13.70%

IL Joppa Steam 2 Table1 16,895,957 16,222,770 -3.98%

IL Joppa Steam CS2 (3, 4) 7,937 7,952 0.19%

B-3, 2
APPENDIX B-3: EMISSIONS AND UTILIZATION OF PHASE I UNITS FOR 1998 AND 1999

1998 1999 Percent Change, 1998-1999

SO2 Utilization SO2 Utilization SO2 Utilization

State Plant Name Stack/Unit ID Unit Type Emissions (mmBtu) Emissions (mmBtu) Emissions (mmBtu)

IL Joppa Steam 3 Table1 16,246,827 15,836,007 -2.53%

IL Joppa Steam 4 Table1 15,657,774 15,627,050 -0.20%

IL Joppa Steam CS3 (5, 6) 7,636 8,165 6.93%

IL Joppa Steam 5 Table1 16,131,320 16,107,187 -0.15%

IL Joppa Steam 6 Table1 14,904,104 16,183,167 8.58%

IL Kincaid CS0102 (1, 2) 46,417 19,867 -57.20%

IL Kincaid 1 Table1 18,743,889 31,384,634 67.44%

IL Kincaid 2 Table1 30,554,552 23,830,039 -22.01%

IL Meredosia 5 Table1 8,114,710 10,941 10,944,500 12,450 34.87% 13.79%

IL Newton 1 Substitution 30,901,900 7,508 41,277,526 9,935 33.58% 32.33%

IL Vermilion CS3 (1, 2) 12,220 10,833 -11.35%

IL Vermilion 1 Substitution 3,484,888 3,268,808 -6.20%

IL Vermilion 2 Table1 5,717,555 5,605,084 -1.97%

IL Wood River 1 Substitution 475,387 1 318,431 0 -33.02% -100.00%

IN Bailly XS12 (7, 8) 4,334 3,813 -12.02%

IN Bailly 7 Table1 10,663,125 12,681,533 18.93%

IN Bailly 8 Table1 21,683,417 21,611,162 -0.33%

IN Breed 1 Table1 0 0 0 0 0.00% 0.00%

IN Cayuga 1 Table1 36,106,576 51,345 29,784,383 38,153 -17.51% -25.69%

IN Cayuga 2 Table1 24,672,500 37,593 32,916,838 45,309 33.42% 20.53%

IN Clifty Creek CS001 (1, 2, 3) 46,294 26,131 -43.55%

IN Clifty Creek 1 Table1 15,187,611 14,250,422 -6.17%

IN Clifty Creek 2 Table1 15,722,352 13,829,890 -12.04%

IN Clifty Creek 3 Table1 16,620,156 14,254,172 -14.24%

IN Clifty Creek CS002 (4, 5, 6) 42,899 26,545 -38.12%

IN Clifty Creek 4 Table1 15,129,975 14,347,485 -5.17%

IN Clifty Creek 5 Table1 15,465,474 14,919,136 -3.53%

IN Clifty Creek 6 Table1 11,649,523 15,082,320 29.47%

IN Elmer W Stout 50 Table1 6,373,331 6,638 7,716,376 7,967 21.07% 20.02%

IN Elmer W Stout 60 Table1 6,765,079 7,392 7,104,368 7,812 5.02% 5.68%

IN Elmer W Stout 70 Table1 24,602,220 25,931 27,163,753 28,801 10.41% 11.07%

IN F B Culley XS23 (2, 3) 7,687 8,634 12.32%

IN F B Culley 2 Table1 7,665,616 7,733,260 0.88%

IN F B Culley 3 Table1 24,969,662 22,066,761 -11.63%

IN Frank E Ratts 1SG1 Table1 8,756,973 9,236 5,598,320 6,136 -36.07% -33.56%

IN Frank E Ratts 2SG1 Table1 8,486,975 9,393 9,725,809 11,044 14.60% 17.58%

IN Gibson CS0003 (1, 2) 94,431 84,282 -10.75%

IN Gibson 1 Table1 42,521,424 47,059,174 10.67%

IN Gibson 2 Table1 39,961,024 43,412,460 8.64%

IN Gibson XS34 (3, 4) 51,189 56,662 10.69%

IN Gibson 3 Table1 35,238,356 41,312,568 17.24%

IN Gibson 4 Table1 48,852,984 47,769,475 -2.22%

IN H T Pritchard CS596 (5, 6) 7,512 9,133 21.58%

IN H T Pritchard 5 Substitution 2,725,130 2,797,197 2.64%

IN H T Pritchard 6 Table1 5,325,128 6,165,568 15.78%

B-3, 3
APPENDIX B-3: EMISSIONS AND UTILIZATION OF PHASE I UNITS FOR 1998 AND 1999

1998 1999 Percent Change, 1998-1999

SO2 Utilization SO2 Utilization SO2 Utilization

State Plant Name Stack/Unit ID Unit Type Emissions (mmBtu) Emissions (mmBtu) Emissions (mmBtu)

IN Michigan City 12 Table1 28,722,177 16,672 24,416,874 10,512 -14.99% -36.95%

IN Petersburg 1 Table1 16,853,716 2,247 14,887,120 2,202 -11.67% -2.00%

IN Petersburg 2 Table1 32,849,989 4,136 31,640,108 4,945 -3.68% 19.56%

IN R Gallagher CS0001 (1, 2) 22,954 24,027 4.67%

IN R Gallagher 1 Table1 6,484,783 7,555,385 16.51%

IN R Gallagher 2 Table1 8,078,498 7,205,560 -10.81%

IN R Gallagher CS0002 (3, 4) 27,642 25,850 -6.48%

IN R Gallagher 3 Table1 9,757,824 7,904,914 -18.99%

IN R Gallagher 4 Table1 8,730,732 8,295,461 -4.99%

IN Tanners Creek U4 Table1 21,095,772 32,017 32,193,717 34,708 52.61% 8.40%

IN Wabash River 1 Table1 10,195,928 851 7,004,060 461 -31.31% -45.83%

IN Wabash River CS005 (2, 3, 5, 6) 48,580 49,210 1.30%

IN Wabash River 2 Table1 5,345,939 5,320,471 -0.48%

IN Wabash River 3 Table1 5,574,897 3,366,728 -39.61%

IN Wabash River 5 Table1 6,735,426 5,016,853 -25.52%

IN Wabash River 6 Table1 18,378,868 18,221,805 -0.85%

IN Warrick XS123 (1, 2, 3) 78,964 83,243 5.42%

IN Warrick 1 Opt-In 12,261,983 11,529,866 -5.97%

IN Warrick 2 Opt-In 12,265,399 13,478,104 9.89%

IN Warrick 3 Opt-In 12,241,810 13,388,356 9.37%

IN Warrick 4 Table1 18,411,332 34,078 22,001,632 36,413 19.50% 6.85%

KS La Cygne 1 Substitution 34,557,496 6,319 47,751,036 10,906 38.18% 72.59%

KS Quindaro 2 Table1 6,966,804 2,985 7,717,137 2,411 10.77% -19.23%

KY Coleman C1 Table1 10,837,598 13,908 9,454,607 11,138 -12.76% -19.92%

KY Coleman C2 Table1 7,993,759 9,677 11,006,016 12,879 37.68% 33.09%

KY Coleman C3 Table1 11,281,190 14,568 11,332,658 13,420 0.46% -7.88%

KY Cooper CS1 (1, 2) 17,613 19,882 12.88%

KY Cooper 1 Table1 6,162,103 6,790,255 10.19%

KY Cooper 2 Table1 12,814,633 13,586,572 6.02%

KY E W Brown 1 Table1 6,033,395 6,762 5,957,448 7,051 -1.26% 4.27%

KY E W Brown CS003 (2, 3) 35,473 38,513 8.57%

KY E W Brown 2 Table1 10,629,369 9,673,102 -9.00%

KY E W Brown 3 Table1 22,188,450 24,995,749 12.65%

KY East Bend 2 Substitution 41,851,087 13,064 47,901,080 18,096 14.46% 38.52%

KY Elmer Smith XS12 (1, 2) 7,011 8,402 19.84%

KY Elmer Smith 1 Table1 10,447,080 11,055,201 5.82%

KY Elmer Smith 2 Table1 21,192,016 21,616,916 2.01%

KY Ghent 1 Table1 39,524,506 7,396 38,957,054 6,452 -1.44% -12.76%

KY Green River 5 Table1 6,883,122 14,438 6,090,354 11,122 -11.52% -22.97%

KY H L Spurlock 1 Table1 21,451,848 14,941 22,882,357 16,444 6.67% 10.06%

KY Hmp&L Station 2 H1 Table1 12,326,347 2,397 11,604,941 2,560 -5.85% 6.80%

KY Hmp&L Station 2 H2 Table1 12,467,753 2,130 13,603,299 3,246 9.11% 52.39%

KY Paradise 3 Table1 59,456,328 126,946 65,709,524 145,724 10.52% 14.79%

KY R D Green G1 Substitution 19,256,597 1,828 17,055,276 2,544 -11.43% 39.17%

KY R D Green G2 Substitution 16,646,528 2,136 18,192,091 2,300 9.28% 7.68%

B-3, 4
APPENDIX B-3: EMISSIONS AND UTILIZATION OF PHASE I UNITS FOR 1998 AND 1999

1998 1999 Percent Change, 1998-1999

SO2 Utilization SO2 Utilization SO2 Utilization

State Plant Name Stack/Unit ID Unit Type Emissions (mmBtu) Emissions (mmBtu) Emissions (mmBtu)

KY Shawnee 10 Table1 7,598,398 1,560 6,330,697 1,597 -16.68% 2.37%

MA Brayton Point 1 Compensating 17,886,343 9,739 18,653,762 10,328 4.29% 6.05%

MA Brayton Point 2 Compensating 18,403,534 9,744 17,930,549 10,030 -2.57% 2.94%

MA Mount Tom 1 Substitution 10,400,402 8,417 10,409,818 7,172 0.09% -14.79%

MD C P Crane 1 Table1 12,220,342 15,224 11,048,746 12,942 -9.59% -14.99%

MD C P Crane 2 Table1 10,972,712 13,636 15,139,746 18,121 37.98% 32.89%

MD Chalk Point CSE12 (1, 2) 44,721 45,450 1.63%

MD Chalk Point 1 Table1 23,306,258 25,083,406 7.63%

MD Chalk Point 2 Table1 21,586,648 24,512,463 13.55%

MD Chalk Point 3 Substitution 17,351,546 7,732 19,066,892 7,898 9.89% 2.15%

MD Morgantown 1 Table1 33,077,778 34,953 37,938,653 41,194 14.70% 17.86%

MD Morgantown 2 Table1 43,364,798 44,953 32,452,376 34,325 -25.16% -23.64%

MD R P Smith 9 Substitution 152,062 117 175,810 133 15.62% 13.68%

MD R P Smith 11 Substitution 2,977,734 2,262 3,581,919 2,664 20.29% 17.77%

MI Dan E Karn 2 Substitution 13,176,629 8,426 16,529,722 10,282 25.45% 22.03%

MI J C Weadock CS0009 (7, 8) 12,330 10,701 -13.21%

MI J C Weadock 7 Substitution 11,669,816 9,008,727 -22.80%

MI J C Weadock 8 Substitution 11,474,188 12,791,726 11.48%

MI J H Campbell CS0009 (1, 2) 22,693 24,089 6.15%

MI J H Campbell 1 Table1 13,474,893 17,949,073 33.20%

MI J H Campbell 2 Table1 24,729,551 23,950,447 -3.15%

MI J R Whiting 1 Substitution 6,127,827 3,940 7,071,532 3,835 15.40% -2.66%

MI J R Whiting 2 Substitution 7,251,809 4,561 7,721,975 4,090 6.48% -10.33%

MI J R Whiting 3 Substitution 7,786,674 4,755 9,344,917 4,925 20.01% 3.58%

MN High Bridge CS0001 (3, 4, 5, 6) 4,044 3,482 -13.90%

MN High Bridge 3 Substitution 1,553,609 989,385 -36.32%

MN High Bridge 4 Substitution 1,543,292 1,614,894 4.64%

MN High Bridge 5 Substitution 7,083,980 5,593,372 -21.04%

MN High Bridge 6 Table1 10,753,526 8,615,703 -19.88%

MN Sherburne County CS1 (1, 2) 8,958 10,756 20.07%

MN Sherburne County 1 Substitution 43,745,696 44,597,306 1.95%

MN Sherburne County 2 Substitution 50,587,266 53,564,282 5.88%

MO Asbury 1 Table1 12,859,011 8,212 13,164,172 8,046 2.37% -2.02%

MO Hawthorn 5 Substitution 20,633,908 7,106 2,624,153 821 -87.28% -88.45%

MO James River 3 Substitution 3,121,544 1,409 3,099,540 1,001 -0.70% -28.96%

MO James River 4 Substitution 3,737,611 1,708 4,501,874 1,438 20.45% -15.81%

MO James River 5 Table1 5,934,107 2,810 8,057,047 2,588 35.78% -7.90%

MO Labadie 1 Table1 42,347,449 15,654 39,840,374 10,184 -5.92% -34.94%

MO Labadie 2 Table1 34,534,886 12,987 44,817,914 10,959 29.78% -15.62%

MO Labadie 3 Table1 40,580,655 14,602 35,440,211 9,033 -12.67% -38.14%

MO Labadie 4 Table1 39,516,498 14,354 32,026,366 8,605 -18.95% -40.05%

MO Meramec 1 Substitution 4,991,896 1,670 7,116,930 1,897 42.57% 13.59%

MO Meramec 2 Substitution 4,792,250 1,541 7,057,121 1,798 47.26% 16.68%

MO Meramec 3 Substitution 6,900,132 3,706 8,901,583 3,902 29.01% 5.29%

MO Montrose 1 Table1 11,013,403 4,072 10,737,171 2,644 -2.51% -35.07%

B-3, 5
APPENDIX B-3: EMISSIONS AND UTILIZATION OF PHASE I UNITS FOR 1998 AND 1999

1998 1999 Percent Change, 1998-1999

SO2 Utilization SO2 Utilization SO2 Utilization

State Plant Name Stack/Unit ID Unit Type Emissions (mmBtu) Emissions (mmBtu) Emissions (mmBtu)

MO Montrose CS023 (2, 3) 8,875 7,025 -20.85%

MO Montrose 2 Table1 10,380,984 12,714,292 22.48%

MO Montrose 3 Table1 11,783,069 11,602,632 -1.53%

MO New Madrid 1 Table1 42,006,552 8,735 45,150,430 9,570 7.48% 9.56%

MO New Madrid 2 Table1 46,640,504 9,018 34,610,571 6,863 -25.79% -23.90%

MO Rush Island 1 Substitution 40,512,757 13,485 36,010,237 12,653 -11.11% -6.17%

MO Rush Island 2 Substitution 42,312,616 13,924 42,175,356 14,543 -0.32% 4.45%

MO Sibley CS0001 (1, 2, 3) 27,056 26,183 -3.23%

MO Sibley 1 Substitution 3,195,388 3,387,394 6.01%

MO Sibley 2 Substitution 3,125,667 3,180,319 1.75%

MO Sibley 3 Table1 26,076,510 26,234,888 0.61%

MO Sioux 1 Table1 24,814,785 18,885 28,960,864 25,148 16.71% 33.16%

MO Sioux 2 Table1 30,562,053 23,062 23,062,994 18,624 -24.54% -19.24%

MO Southwest 1 Substitution 16,707,842 6,837 15,623,175 3,538 -6.49% -48.25%

MO Thomas Hill MB1 Table1 15,127,247 3,080 14,575,377 3,139 -3.65% 1.92%

MO Thomas Hill MB2 Table1 23,711,214 4,722 25,046,252 5,220 5.63% 10.55%

MO Thomas Hill MB3 Substitution 47,129,420 9,916 60,434,841 12,768 28.23% 28.76%

MS Jack Watson 4 Table1 18,271,530 18,528 16,484,019 14,038 -9.78% -24.23%

MS Jack Watson 5 Table1 32,387,107 32,033 36,679,476 32,552 13.25% 1.62%

MS R D Morrow 1 Substitution 14,398,624 4,267 12,358,012 3,572 -14.17% -16.29%

MS R D Morrow 2 Substitution 15,094,507 4,383 11,789,856 3,642 -21.89% -16.91%

NH Merrimack 1 Table1 9,625,002 12,126 9,547,754 12,479 -0.80% 2.91%

NH Merrimack 2 Table1 21,653,842 22,794 20,639,634 22,320 -4.68% -2.08%

NJ B L England 1 Table1 7,658,545 15,694 7,429,902 14,323 -2.99% -8.74%

NJ B L England 2 Table1 6,770,210 1,084 8,076,956 978 19.30% -9.78%

NY Dunkirk CS0003 (3, 4) 37,527 36,414 -2.97%

NY Dunkirk 3 Table1 12,014,610 11,671,411 -2.86%

NY Dunkirk 4 Table1 14,506,026 12,125,304 -16.41%

NY Greenidge 6 Table1 8,538,897 9,027 8,188,414 8,865 -4.10% -1.79%

NY Milliken XS12 (1, 2) 8,572 7,524 -12.23%

NY Milliken 1 Table1 12,085,829 12,902,644 6.76%

NY Milliken 2 Table1 12,008,990 12,635,866 5.22%

NY Northport 1 Table1 12,065,492 2,764 21,821,549 5,228 80.86% 89.15%

NY Northport 2 Table1 17,255,806 4,866 21,528,869 5,003 24.76% 2.82%

NY Northport 3 Table1 19,356,322 10,502 12,999,243 7,001 -32.84% -33.34%

NY Northport 4 Substitution 12,918,579 1,136 19,613,318 1,313 51.82% 15.58%

NY Port Jefferson 3 Table1 9,726,121 4,185 7,026,559 2,325 -27.76% -44.44%

NY Port Jefferson 4 Table1 11,039,434 3,171 11,512,191 2,025 4.28% -36.14%

OH Acme 13 Substitution 0 0 0 0 0.00% 0.00%

OH Acme 14 Substitution 0 0 0 0 0.00% 0.00%

OH Acme 15 Substitution 0 0 0 0 0.00% 0.00%

OH Acme 16 Substitution 0 0 0 0 0.00% 0.00%

OH Acme 91 Substitution 0 0 0 0 0.00% 0.00%

OH Acme 92 Substitution 0 0 0 0 0.00% 0.00%

OH Ashtabula 7 Table1 9,268,567 26,164 8,120,031 22,153 -12.39% -15.33%

B-3, 6
APPENDIX B-3: EMISSIONS AND UTILIZATION OF PHASE I UNITS FOR 1998 AND 1999

1998 1999 Percent Change, 1998-1999

SO2 Utilization SO2 Utilization SO2 Utilization

State Plant Name Stack/Unit ID Unit Type Emissions (mmBtu) Emissions (mmBtu) Emissions (mmBtu)

OH Ashtabula CS1 (8, 9, 10, 11) 2,048 3,865 88.72%

OH Ashtabula 8 Substitution 0 279,973

OH Ashtabula 9 Substitution 0 0 0.00%

OH Ashtabula 10 Substitution 287,495 512,626 78.31%

OH Ashtabula 11 Substitution 530,174 450,475 -15.03%

OH Avon Lake 9 Substitution 0 0 0 0 0.00% 0.00%

OH Avon Lake 10 Substitution 1,437,105 1,222 3,083,112 1,714 114.54% 40.26%

OH Avon Lake 11 Table1 0 0 0 0 0.00% 0.00%

OH Avon Lake 12 Table1 36,413,732 27,714 36,160,588 31,154 -0.70% 12.41%

OH Bay Shore CS5 (1, 2, 3, 4) 11,472 7,980 -30.44%

OH Bay Shore 1 Substitution 6,462,382 6,453,497 -0.14%

OH Bay Shore 2 Substitution 6,807,479 4,892,897 -28.12%

OH Bay Shore 3 Substitution 7,261,342 7,622,340 4.97%

OH Bay Shore 4 Substitution 9,238,904 10,722,321 16.06%

OH Cardinal 1 Table1 32,017,382 95,520 27,853,645 60,413 -13.00% -36.75%

OH Cardinal 2 Table1 34,846,000 33,017 29,083,402 34,358 -16.54% 4.06%

OH Conesville CS012 (1, 2) 30,089 25,887 -13.97%

OH Conesville 1 Table1 6,163,071 5,376,545 -12.76%

OH Conesville 2 Table1 6,974,286 6,256,606 -10.29%

OH Conesville 3 Table1 7,761,567 17,937 4,940,431 11,548 -36.35% -35.62%

OH Conesville 4 Table1 32,772,680 72,035 38,097,747 83,894 16.25% 16.46%

OH Eastlake 1 Table1 6,311,370 11,186 5,215,645 10,490 -17.36% -6.22%

OH Eastlake 2 Table1 6,852,009 11,992 5,849,349 12,441 -14.63% 3.74%

OH Eastlake 3 Table1 8,079,638 12,985 6,407,370 12,349 -20.70% -4.90%

OH Eastlake 4 Table1 10,573,149 18,497 9,870,191 19,978 -6.65% 8.01%

OH Eastlake 5 Table1 36,867,392 56,011 29,051,400 60,129 -21.20% 7.35%

OH Edgewater 11 Substitution 0 0 0 0 0.00% 0.00%

OH Edgewater 12 Substitution 0 0 0 0 0.00% 0.00%

OH Edgewater 13 Table1 1,228,962 7 1,041,857 20 -15.22% 185.71%

OH Gen J M Gavin 1 Table1 78,819,640 15,085 89,167,280 8,717 13.13% -42.21%

OH Gen J M Gavin 2 Table1 94,637,496 18,718 65,991,259 6,529 -30.27% -65.12%

OH Gorge 25 Substitution 0 0 0 0 0.00% 0.00%

OH Gorge 26 Substitution 0 0 0 0 0.00% 0.00%

OH J M Stuart 1 Substitution 37,286,928 27,024 33,941,546 24,210 -8.97% -10.41%

OH J M Stuart 2 Substitution 40,858,280 29,520 32,282,115 23,091 -20.99% -21.78%

OH J M Stuart 3 Substitution 32,223,074 23,211 34,980,662 25,129 8.56% 8.26%

OH J M Stuart 4 Substitution 33,318,570 23,603 42,381,845 29,557 27.20% 25.23%

OH Kyger Creek CS001 (1, 2, 3, 4, 5) 119,171 135,558 13.75%

OH Kyger Creek 1 Table1 14,334,231 15,868,388 10.70%

OH Kyger Creek 2 Table1 15,054,039 14,701,108 -2.34%

OH Kyger Creek 3 Table1 14,714,973 13,793,625 -6.26%

OH Kyger Creek 4 Table1 16,147,978 14,024,499 -13.15%

OH Kyger Creek 5 Table1 14,395,578 14,372,849 -0.16%

OH Lake Shore 18 Substitution 3,627,698 1,811 3,158,746 1,527 -12.93% -15.68%

OH Lake Shore 91 Substitution 0 0 0 0 0.00% 0.00%

B-3, 7
APPENDIX B-3: EMISSIONS AND UTILIZATION OF PHASE I UNITS FOR 1998 AND 1999

1998 1999 Percent Change, 1998-1999

SO2 Utilization SO2 Utilization SO2 Utilization

State Plant Name Stack/Unit ID Unit Type Emissions (mmBtu) Emissions (mmBtu) Emissions (mmBtu)

OH Lake Shore 92 Substitution 0 0 0 0 0.00% 0.00%

OH Lake Shore 93 Substitution 0 0 0 0 0.00% 0.00%

OH Lake Shore 94 Substitution 0 0 0 0 0.00% 0.00%

OH Miami Fort CS056 (5-1, 5-2, 6) 19,614 18,199 -7.21%

OH Miami Fort 6 Table1 13,624,571 14,296,977 4.94%

OH Miami Fort 7 Table1 29,030,836 36,473 40,335,185 40,559 38.94% 11.20%

OH Miami Fort 5-1 Table1 1,373,320 1,673,166 21.83%

OH Miami Fort 5-2 Table1 1,374,643 1,669,393 21.44%

OH Muskingum River CS014 (1, 2, 3, 4) 152,316 78,543 -48.43%

OH Muskingum River 1 Table1 9,969,079 3,607,991 -63.81%

OH Muskingum River 2 Table1 10,138,733 6,358,846 -37.28%

OH Muskingum River 3 Table1 11,271,723 7,348,251 -34.81%

OH Muskingum River 4 Table1 10,897,014 4,487,600 -58.82%

OH Muskingum River 5 Table1 27,975,016 15,307 35,774,715 22,096 27.88% 44.35%

OH Niles XS12 (1, 2) 21,636 19,292 -10.83%

OH Niles 1 Table1 7,625,299 6,183,854 -18.90%

OH Niles 2 Table1 5,534,045 6,582,973 18.95%

OH Picway 9 Table1 4,802,830 13,385 3,795,836 9,385 -20.97% -29.88%

OH Poston 1 Substitution 0 0 0 0 0.00% 0.00%

OH Poston 2 Substitution 0 0 0 0 0.00% 0.00%

OH Poston 3 Substitution 0 0 0 0 0.00% 0.00%

OH R E Burger CS0001 (1, 2, 3, 4, 5, 6, 7, 8) 38,543 49,189 27.62%

OH R E Burger 1 Substitution 0 0 0.00%

OH R E Burger 2 Substitution 0 0 0.00%

OH R E Burger 3 Substitution 0 0 0.00%

OH R E Burger 4 Substitution 0 0 0.00%

OH R E Burger 5 Table1 23 482,744 2098786.96%

OH R E Burger 6 Table1 22,906 557,221 2332.64%

OH R E Burger 7 Table1 10,366,887 8,972,115 -13.45%

OH R E Burger 8 Table1 9,213,604 9,084,270 -1.40%

OH Toronto 9 Substitution 0 0 0 0 0.00% 0.00%

OH Toronto 10 Substitution 0 0 0 0 0.00% 0.00%

OH Toronto 11 Substitution 0 0 0 0 0.00% 0.00%

OH W H Sammis 5 Table1 19,236,457 16,812 17,509,532 19,111 -8.98% 13.67%

OH W H Sammis 6 Table1 29,506,312 20,352 45,848,958 36,395 55.39% 78.83%

OH W H Sammis 7 Table1 44,358,048 45,828 37,729,229 44,027 -14.94% -3.93%

OH Walter C Beckjord 5 Table1 15,957,426 20,329 16,565,264 14,764 3.81% -27.37%

OH Walter C Beckjord 6 Table1 29,796,457 39,455 29,571,498 26,050 -0.75% -33.98%

PA Armstrong 1 Table1 11,997,280 18,227 8,714,032 12,471 -27.37% -31.58%

PA Armstrong 2 Table1 11,802,474 17,658 10,502,470 15,125 -11.01% -14.34%

PA Bruce Mansfield 1 Substitution 52,609,590 7,527 40,265,916 7,491 -23.46% -0.48%

PA Bruce Mansfield 2 Substitution 42,620,088 6,765 45,017,219 9,438 5.62% 39.51%

PA Brunner Island CS102 (1, 2) 48,020 40,437 -15.79%

PA Brunner Island 1 Table1 17,977,978 14,119,976 -21.46%

PA Brunner Island 2 Table1 21,591,769 17,835,199 -17.40%

B-3, 8
APPENDIX B-3: EMISSIONS AND UTILIZATION OF PHASE I UNITS FOR 1998 AND 1999

1998 1999 Percent Change, 1998-1999

SO2 Utilization SO2 Utilization SO2 Utilization

State Plant Name Stack/Unit ID Unit Type Emissions (mmBtu) Emissions (mmBtu) Emissions (mmBtu)

PA Brunner Island 3 Table1 38,668,683 47,679 39,197,191 30,751 1.37% -35.50%

PA Cheswick 1 Table1 25,447,980 32,177 32,658,260 41,602 28.33% 29.29%

PA Conemaugh 1 Table1 64,682,996 3,874 69,486,114 4,472 7.43% 15.44%

PA Conemaugh 2 Table1 72,193,913 4,347 55,907,023 3,421 -22.56% -21.30%

PA Hatfield's Ferry XS123 (1, 2, 3) 150,868 141,872 -5.96%

PA Hatfield's Ferry 1 Table1 33,536,438 30,551,752 -8.90%

PA Hatfield's Ferry 2 Table1 29,112,948 22,255,667 -23.55%

PA Hatfield's Ferry 3 Table1 29,387,244 32,926,994 12.05%

PA Martins Creek CS102 (1, 2) 15,834 13,972 -11.76%

PA Martins Creek 1 Table1 6,486,775 5,094,585 -21.46%

PA Martins Creek 2 Table1 6,021,584 4,913,542 -18.40%

PA Martins Creek 3 Substitution 11,288,576 4,742 8,148,433 2,248 -27.82% -52.59%

PA Martins Creek 4 Substitution 10,631,226 4,347 10,305,450 3,310 -3.06% -23.86%

PA Mitchell 33 Substitution 16,084,774 1,050 15,416,659 994 -4.15% -5.33%

PA New Castle 1 Substitution 0 0 0 0 0.00% 0.00%

PA New Castle 2 Substitution 0 0 0 0 0.00% 0.00%

PA Portland 1 Table1 8,564,817 9,772 8,426,585 11,220 -1.61% 14.82%

PA Portland 2 Table1 10,950,567 12,126 11,751,042 15,099 7.31% 24.52%

PA Shawville 1 Table1 8,432,824 12,864 7,078,616 10,974 -16.06% -14.69%

PA Shawville 2 Table1 8,234,692 12,365 8,503,856 12,853 3.27% 3.95%

PA Shawville CS1 (3, 4) 33,535 27,959 -16.63%

PA Shawville 3 Table1 12,435,105 11,014,863 -11.42%

PA Shawville 4 Table1 12,289,735 8,973,627 -26.98%

PA Sunbury 3 Table1 8,357,434 10,307 5,180,806 6,099 -38.01% -40.83%

PA Sunbury 4 Table1 9,405,060 11,970 6,304,698 7,480 -32.96% -37.51%

TN Allen 1 Table1 13,314,521 5,671 9,851,081 3,997 -26.01% -29.52%

TN Allen 2 Table1 17,881,872 7,378 10,664,977 4,393 -40.36% -40.46%

TN Allen 3 Table1 18,246,196 7,162 13,303,435 5,291 -27.09% -26.12%

TN Cumberland 1 Table1 93,425,640 10,610 73,656,897 7,070 -21.16% -33.36%

TN Cumberland 2 Table1 77,445,408 9,891 105,807,314 8,851 36.62% -10.51%

TN DuPont Johnsonville JVD1 Opt-In 0 0 0 0 0.00% 0.00%

TN DuPont Johnsonville JVD2 Opt-In 0 0 0 0 0.00% 0.00%

TN DuPont Johnsonville JVD3 Opt-In 0 0 0 0 0.00% 0.00%

TN DuPont Johnsonville JVD4 Opt-In 0 0 0 0 0.00% 0.00%

TN Gallatin CSGA12 (1, 2) 40,664 37,124 -8.71%

TN Gallatin 1 Table1 16,675,013 19,169,909 14.96%

TN Gallatin 2 Table1 13,358,894 17,111,033 28.09%

TN Gallatin CSGA34 (3, 4) 45,551 47,717 4.76%

TN Gallatin 3 Table1 18,006,243 20,933,769 16.26%

TN Gallatin 4 Table1 14,508,353 19,865,790 36.93%

TN Johnsonville CSJO10 (1, 2, 3, 4, 5, 6, 7, 8, 9, 10) 114,588 119,778 4.53%

TN Johnsonville 1 Table1 8,391,787 8,581,945 2.27%

TN Johnsonville 2 Table1 6,454,090 8,748,656 35.55%

TN Johnsonville 3 Table1 5,676,977 7,790,561 37.23%

TN Johnsonville 4 Table1 7,806,189 8,704,533 11.51%

B-3, 9
APPENDIX B-3: EMISSIONS AND UTILIZATION OF PHASE I UNITS FOR 1998 AND 1999

1998 1999 Percent Change, 1998-1999

SO2 Utilization SO2 Utilization SO2 Utilization

State Plant Name Stack/Unit ID Unit Type Emissions (mmBtu) Emissions (mmBtu) Emissions (mmBtu)

TN Johnsonville 5 Table1 6,805,978 7,690,236 12.99%

TN Johnsonville 6 Table1 7,370,703 7,812,089 5.99%

TN Johnsonville 7 Table1 7,852,052 8,973,487 14.28%

TN Johnsonville 8 Table1 8,457,149 7,349,441 -13.10%

TN Johnsonville 9 Table1 9,737,698 10,876,009 11.69%

TN Johnsonville 10 Table1 8,049,553 8,505,788 5.67%

WI Alma CS2 (B1, B2, B3) 1,287 757 -41.18%

WI Alma B1 Opt-In 663,744 544,455 -17.97%

WI Alma B2 Opt-In 602,030 460,323 -23.54%

WI Alma B3 Opt-In 565,438 499,689 -11.63%

WI Alma CS1 (B1, B2, B3, B4, B5) 6,517 3,060 -53.05%

WI Alma B4 Substitution 3,122,034 2,496,086 -20.05%

WI Alma B5 Substitution 4,318,051 3,249,944 -24.74%

WI Edgewater 3 Substitution 5,011,080 1,973 3,809,692 1,356 -23.97% -31.27%

WI Edgewater 4 Table1 20,197,100 8,391 18,569,057 6,624 -8.06% -21.06%

WI Genoa 1 Table1 16,559,515 9,031 20,395,109 12,513 23.16% 38.56%

WI J P Madgett B1 Substitution 25,231,992 5,223 25,466,640 5,333 0.93% 2.11%

WI Nelson Dewey CS1 (1, 2) 10,861 13,280 22.27%

WI Nelson Dewey 1 Table1 6,172,813 6,991,292 13.26%

WI Nelson Dewey 2 Table1 7,216,679 7,093,604 -1.71%

WI North Oak Creek 1 Table1 0 0 0 0 0.00% 0.00%

WI North Oak Creek 2 Table1 0 0 0 0 0.00% 0.00%

WI North Oak Creek 3 Table1 0 0 0 0 0.00% 0.00%

WI North Oak Creek 4 Table1 0 0 0 0 0.00% 0.00%

WI Pulliam CS56 (5, 6) 1,884 2,278 20.91%

WI Pulliam 5 Substitution 3,766,998 4,010,079 6.45%

WI Pulliam 6 Substitution 5,003,476 6,006,083 20.04%

WI Pulliam 7 Substitution 7,422,811 1,569 5,722,099 1,264 -22.91% -19.44%

WI Pulliam 8 Table1 11,212,789 2,283 10,395,306 2,196 -7.29% -3.81%

WI Rock River 1 Substitution 4,083,241 1,532 2,259,634 656 -44.66% -57.18%

WI Rock River 2 Substitution 4,957,022 1,898 1,948,975 741 -60.68% -60.96%

WI South Oak Creek CS3 (5, 6) 16,781 15,736 -6.23%

WI South Oak Creek 5 Table1 10,136,963 15,289,701 50.83%

WI South Oak Creek 6 Table1 16,111,857 13,120,528 -18.57%

WI South Oak Creek CS4 (7, 8) 26,529 17,153 -35.34%

WI South Oak Creek 7 Table1 20,272,864 20,083,880 -0.93%

WI South Oak Creek 8 Table1 18,324,182 19,699,186 7.50%

WI Weston 1 Substitution 3,956,520 1,111 4,182,326 1,263 5.71% 13.68%

WI Weston 2 Substitution 6,830,073 1,922 5,893,048 1,778 -13.72% -7.49%

WV Albright 1 Substitution 1,843,436 2,202 2,125,873 2,500 15.32% 13.53%

WV Albright 2 Substitution 1,623,422 1,929 2,179,803 2,523 34.27% 30.79%

WV Albright 3 Table1 6,078,740 7,228 9,852,124 11,640 62.08% 61.04%

WV Fort Martin 1 Table1 34,726,484 41,641 39,694,066 50,943 14.30% 22.34%

WV Fort Martin 2 Table1 30,423,447 37,663 37,345,654 48,158 22.75% 27.87%

WV Harrison XS123 (1, 2, 3) 6,934 6,835 -1.43%

B-3, 10
APPENDIX B-3: EMISSIONS AND UTILIZATION OF PHASE I UNITS FOR 1998 AND 1999

1998 1999 Percent Change, 1998-1999

SO2 Utilization SO2 Utilization SO2 Utilization

State Plant Name Stack/Unit ID Unit Type Emissions (mmBtu) Emissions (mmBtu) Emissions (mmBtu)

WV Harrison 1 Table1 46,082,925 51,023,022 10.72%

WV Harrison 2 Table1 51,433,080 44,723,816 -13.04%

WV Harrison 3 Table1 55,241,467 48,979,700 -11.34%

WV Kammer CS013 (1, 2, 3) 108,618 104,231 -4.04%

WV Kammer 1 Table1 13,479,546 11,856,165 -12.04%

WV Kammer 2 Table1 12,639,201 15,026,115 18.89%

WV Kammer 3 Table1 13,391,834 12,839,130 -4.13%

WV Mitchell CS012 (1, 2) 59,330 55,046 -7.22%

WV Mitchell 1 Table1 44,346,849 42,576,634 -3.99%

WV Mitchell 2 Table1 48,141,367 44,230,623 -8.12%

WV Mt Storm CS0 (1, 2) 106,759 101,124 -5.28%

WV Mt Storm 1 Table1 41,523,871 39,788,598 -4.18%

WV Mt Storm 2 Table1 39,716,905 36,646,063 -7.73%

WV Mt Storm 3 Table1 47,191,480 4,576 39,419,794 3,481 -16.47% -23.93%

WV Rivesville 7 Substitution 819,610 624 576,450 444 -29.67% -28.85%

WV Rivesville 8 Substitution 2,531,623 1,995 3,849,565 2,954 52.06% 48.07%

NOTES: (a) Identifies the affected unit as listed in Table 1, as a subsitution or compensating unit, or as an opt-in unit.

B-3, 11
APPENDIX B-4: EMISSIONS AND ALLOWANCE HOLDINGS OF PHASE I UNITS FOR 1999

SO2 SO2 1999 Held in Allowances Deducted Under Allowances

Emissions Emissions Allowances Unit Accounts Deducted for Special Phase I Carried Over

State Plant Name Stack/Unit ID Unit Type (a) 1998(b) 1999(b) Allocated (c) as of 3/1/00 Emissions (d) Provisions (e) to 2000

AL Colbert CSCO14 (1, 2, 3, 4) 26,653 22,601

AL Colbert 1 Table1 13,213 27,111 5,959 21,152

AL Colbert 2 Table1 14,907 36,234 6,236 29,998

AL Colbert 3 Table1 14,995 36,810 5,637 31,173

AL Colbert 4 Table1 15,005 37,703 4,769 32,934

AL Colbert 5 Table1 47,608 46,972 36,202 52,155 46,972 5,183

AL E C Gaston CS0CAN (1, 2) 25,864 29,118

AL E C Gaston 1 Table1 17,624 17,517 16,219 1,298

AL E C Gaston 2 Table1 18,052 13,931 12,899 1,032

AL E C Gaston CS0CBN (3, 4) 25,669 28,502

AL E C Gaston 3 Table1 17,828 16,237 15,034 1,203

AL E C Gaston 4 Table1 18,773 14,545 13,468 1,077

AL E C Gaston 5 Table1 41,489 43,508 58,265 84,395 43,508 40,887

AL Gadsden 1 Substitution 4,751 4,242 5,158 4,742 4,242 500

AL Gadsden 2 Substitution 4,463 4,289 5,374 4,789 4,289 500

FL Big Bend XS12 (BB01, BB02) 90,881 80,704

FL Big Bend BB01 Table1 27,662 44,340 39,545 4,795

FL Big Bend BB02 Table1 26,387 44,158 41,159 2,999

FL Big Bend XS23 (BB03, BB04) 16,544 14,910

FL Big Bend BB03 Table1 26,036 13,851 10,798 3,053

FL Big Bend BB04 Substitution 6,400 9,826 4,112 5,714

FL Crist 4 Substitution 3,255 3,329 9,953 37,585 3,329 34,256

FL Crist 5 Substitution 3,872 2,391 9,374 33,007 2,391 30,616

FL Crist 6 Table1 14,461 13,233 18,695 42,331 13,233 29,098

FL Crist 7 Table1 29,005 26,748 30,846 67,343 26,748 40,595

FL Scholz 1 Substitution 1,877 1,557 8,282 33,431 1,557 31,874

FL Scholz 2 Substitution 2,877 1,733 8,572 32,124 1,733 30,391

GA Arkwright CS001 (1, 2, 3, 4) 4,272 4,089

GA Arkwright 1 Substitution 2,437 5,385 1,023 4,362

GA Arkwright 2 Substitution 2,240 4,794 1,022 3,772

GA Arkwright 3 Substitution 3,944 9,906 1,022 8,884

GA Arkwright 4 Substitution 3,159 7,552 1,022 6,530

GA Bowen 1BLR Table1 34,016 28,631 54,838 94,106 28,631 65,475

GA Bowen 2BLR Table1 28,130 34,348 53,329 110,322 34,348 75,974

GA Bowen 3BLR Table1 47,897 37,294 69,862 138,458 37,294 101,164

GA Bowen 4BLR Table1 35,108 39,881 69,852 151,649 39,881 111,768

GA Hammond CS001 (1, 2, 3) 9,842 10,346

GA Hammond 1 Table1 8,549 19,496 3,448 16,048

B-4, 1
APPENDIX B-4: EMISSIONS AND ALLOWANCE HOLDINGS OF PHASE I UNITS FOR 1999

SO2 SO2 1999 Held in Allowances Deducted Under Allowances

Emissions Emissions Allowances Unit Accounts Deducted for Special Phase I Carried Over

State Plant Name Stack/Unit ID Unit Type (a) 1998(b) 1999(b) Allocated (c) as of 3/1/00 Emissions (d) Provisions (e) to 2000

GA Hammond 2 Table1 8,977 20,780 3,449 17,331

GA Hammond 3 Table1 8,676 19,879 3,449 16,430

GA Hammond 4 Table1 13,217 19,579 36,650 104,458 19,579 84,879

GA Harllee Branch CS001 (1, 2) 32,342 28,996

GA Harllee Branch 1 Substitution 19,221 37,988 14,498 23,490

GA Harllee Branch 2 Substitution 22,735 55,559 14,498 41,061

GA Harllee Branch CS002 (3, 4) 56,643 48,692

GA Harllee Branch 3 Substitution 31,280 54,792 24,346 30,446

GA Harllee Branch 4 Substitution 31,042 53,601 24,346 29,255

GA Jack Mcdonough CS001 (MB1, MB2) 28,516 24,212

GA Jack Mcdonough MB1 Table1 19,386 49,144 12,106 37,038

GA Jack Mcdonough MB2 Table1 20,058 51,832 12,106 39,726

GA Kraft CS001 (1, 2, 3) 5,906 6,759

GA Kraft 1 Substitution 2,265 3,858 1,452 2,406

GA Kraft 2 Substitution 2,137 3,695 1,692 2,003

GA Kraft 3 Substitution 4,121 6,242 3,615 2,627

GA Mcintosh 1 Substitution 6,716 6,182 7,146 9,627 6,182 3,445

GA Mitchell 3 Substitution 4,621 4,430 10,792 34,655 4,430 30,225

GA Wansley 1 Table1 44,760 43,290 68,908 122,624 43,290 79,334

GA Wansley 2 Table1 42,489 37,418 63,708 108,981 37,418 71,563

GA Yates Y1BR Table1 131 179 9,533 32,220 179 32,041

GA Yates CS001 (Y2BR, Y3BR) 6,865 7,191

GA Yates Y2BR Table1 6,855 20,781 3,595 17,186

GA Yates Y3BR Table1 6,767 20,430 3,596 16,834

GA Yates CS002 (Y4BR, Y5BR) 9,136 8,588

GA Yates Y4BR Table1 8,676 25,674 4,294 21,380

GA Yates Y5BR Table1 9,162 27,619 4,294 23,325

GA Yates Y6BR Table1 11,192 9,001 24,108 75,847 9,001 66,846

GA Yates Y7BR Table1 12,150 10,447 20,915 61,808 10,447 51,361

IA Burlington 1 Table1 5,847 6,502 10,428 24,317 6,502 17,815

IA Des Moines 11 Table1 0 0 2,259 0 0 0

IA George Neal North 1 Table1 3,974 3,420 2,571 10,692 3,420 7,272

IA Milton L Kapp 2 Table1 5,282 4,437 13,437 43,424 4,437 23 38,964

IA Prairie Creek 4 Table1 4,035 3,773 7,965 24,488 3,773 20,715

IA Riverside 9 Table1 1,435 1,879 3,885 11,332 1,879 9,453

IL Baldwin 1 Table1 71,396 65,231 46,052 66,785 65,231 1,554

IL Baldwin 2 Table1 92,968 91,310 48,695 92,331 91,310 1,021

IL Baldwin 3 Table1 120,253 88,703 46,644 89,755 88,703 1,052

B-4, 2
APPENDIX B-4: EMISSIONS AND ALLOWANCE HOLDINGS OF PHASE I UNITS FOR 1999

SO2 SO2 1999 Held in Allowances Deducted Under Allowances

Emissions Emissions Allowances Unit Accounts Deducted for Special Phase I Carried Over

State Plant Name Stack/Unit ID Unit Type (a) 1998(b) 1999(b) Allocated (c) as of 3/1/00 Emissions (d) Provisions (e) to 2000

IL Coffeen CS0001 (1, 2) 49,413 47,611

IL Coffeen 1 Table1 12,925 17,322 17,224 98

IL Coffeen 2 Table1 39,102 30,482 30,387 95

IL Grand Tower 9 Table1 9,188 6,813 6,479 6,936 6,813 123

IL Havana 6 Substitution 29 28 34 62 28 34

IL Hennepin CS3 (1, 2) 46,809 27,532

IL Hennepin 1 Substitution 9,847 6,847 5,176 1,671

IL Hennepin 2 Table1 20,182 23,182 22,356 826

IL Hutsonville 5 Substitution 5,238 5,189 9,661 5,565 5,189 376

IL Hutsonville 6 Substitution 5,666 5,463 9,837 5,588 5,463 125

IL Joppa Steam CS1 (1, 2) 8,280 7,627

IL Joppa Steam 1 Table1 12,259 44,959 3,813 41,146

IL Joppa Steam 2 Table1 10,487 36,098 3,814 32,284

IL Joppa Steam CS2 (3, 4) 7,937 7,952

IL Joppa Steam 3 Table1 11,947 43,886 3,976 39,910

IL Joppa Steam 4 Table1 11,061 39,456 3,976 35,480

IL Joppa Steam CS3 (5, 6) 7,636 8,165

IL Joppa Steam 5 Table1 11,119 37,136 4,082 33,054

IL Joppa Steam 6 Table1 10,341 33,246 4,083 29,163

IL Kincaid CS0102 (1, 2) 46,417 19,867

IL Kincaid 1 Table1 34,564 14,412 11,920 2,492

IL Kincaid 2 Table1 37,063 10,881 7,947 2,934

IL Meredosia 5 Table1 10,941 12,450 15,227 12,641 12,450 191

IL Newton 1 Substitution 7,508 9,935 14,599 14,320 9,935 4,385

IL Vermilion CS3 (1, 2) 12,220 10,833

IL Vermilion 1 Substitution 12,972 5,028 3,976 1,052

IL Vermilion 2 Table1 9,735 7,972 6,857 1,115

IL Wood River 1 Substitution 1 0 0 12 0 12

IN Bailly XS12 (7, 8) 4,334 3,813

IN Bailly 7 Table1 15,818 14,255 1,411 12,844

IN Bailly 8 Table1 21,600 32,600 2,402 30,198

IN Breed 1 Table1 0 0 20,280 30,362 0 30,362

IN Cayuga 1 Table1 51,345 38,153 36,581 43,462 38,153 5,309

IN Cayuga 2 Table1 37,593 45,309 37,415 53,814 45,309 8,505

IN Clifty Creek CS001 (1, 2, 3) 46,294 26,131

IN Clifty Creek 1 Table1 19,620 17,885 8,711 153 9,021

IN Clifty Creek 2 Table1 19,289 12,727 8,710 165 3,852

IN Clifty Creek 3 Table1 19,873 13,262 8,710 169 4,383

B-4, 3
APPENDIX B-4: EMISSIONS AND ALLOWANCE HOLDINGS OF PHASE I UNITS FOR 1999

SO2 SO2 1999 Held in Allowances Deducted Under Allowances

Emissions Emissions Allowances Unit Accounts Deducted for Special Phase I Carried Over

State Plant Name Stack/Unit ID Unit Type (a) 1998(b) 1999(b) Allocated (c) as of 3/1/00 Emissions (d) Provisions (e) to 2000

IN Clifty Creek CS002 (4, 5, 6) 42,899 26,545

IN Clifty Creek 4 Table1 19,552 14,774 8,849 140 5,785

IN Clifty Creek 5 Table1 18,851 12,087 8,848 46 3,193

IN Clifty Creek 6 Table1 19,844 34,618 8,848 100 25,670

IN Elmer W Stout 50 Table1 6,638 7,967 4,253 8,565 7,967 598

IN Elmer W Stout 60 Table1 7,392 7,812 5,229 8,153 7,812 341

IN Elmer W Stout 70 Table1 25,931 28,801 25,883 29,700 28,801 899

IN F B Culley XS23 (2, 3) 7,687 8,634

IN F B Culley 2 Table1 4,703 9,347 8,634 713

IN F B Culley 3 Table1 18,603 38,206 0 38,206

IN Frank E Ratts 1SG1 Table1 9,236 6,136 9,131 14,258 6,136 8,122

IN Frank E Ratts 2SG1 Table1 9,393 11,044 9,296 11,918 11,044 874

IN Gibson CS0003 (1, 2) 94,431 84,282

IN Gibson 1 Table1 44,288 68,746 43,427 25,319

IN Gibson 2 Table1 44,956 65,137 40,855 24,282

IN Gibson XS34 (3, 4) 51,189 56,662

IN Gibson 3 Table1 45,033 69,168 28,331 40,837

IN Gibson 4 Table1 44,200 99,319 28,331 70,988

IN H T Pritchard CS596 (5, 6) 7,512 9,133

IN H T Pritchard 5 Substitution 1,458 3,011 2,822 189

IN H T Pritchard 6 Table1 6,325 6,557 6,311 246

IN Michigan City 12 Table1 16,672 10,512 25,553 77,113 10,512 66,601

IN Petersburg 1 Table1 2,247 2,202 18,011 2,412 2,202 210

IN Petersburg 2 Table1 4,136 4,945 35,496 5,400 4,945 455

IN R Gallagher CS0001 (1, 2) 22,954 24,027

IN R Gallagher 1 Table1 7,115 12,954 12,282 672

IN R Gallagher 2 Table1 7,980 12,785 11,745 1,040

IN R Gallagher CS0002 (3, 4) 27,642 25,850

IN R Gallagher 3 Table1 7,159 13,121 12,602 519

IN R Gallagher 4 Table1 8,386 14,689 13,248 1,441

IN Tanners Creek U4 Table1 32,017 34,708 27,209 142,162 34,708 107,454

IN Wabash River 1 Table1 851 461 5,379 15,673 461 15,212

IN Wabash River CS005 (2, 3, 5, 6) 48,580 49,210

IN Wabash River 2 Table1 3,135 9,847 8,297 1,550

IN Wabash River 3 Table1 4,111 11,499 5,182 6,317

IN Wabash River 5 Table1 4,023 9,334 7,813 1,521

IN Wabash River 6 Table1 13,462 28,580 27,918 662

IN Warrick XS123 (1, 2, 3) 78,964 83,243

B-4, 4
APPENDIX B-4: EMISSIONS AND ALLOWANCE HOLDINGS OF PHASE I UNITS FOR 1999

SO2 SO2 1999 Held in Allowances Deducted Under Allowances

Emissions Emissions Allowances Unit Accounts Deducted for Special Phase I Carried Over

State Plant Name Stack/Unit ID Unit Type (a) 1998(b) 1999(b) Allocated (c) as of 3/1/00 Emissions (d) Provisions (e) to 2000

IN Warrick 1 Opt-In 30,372 26,889 25,821 134 934

IN Warrick 2 Opt-In 30,732 29,954 29,549 405

IN Warrick 3 Opt-In 27,668 28,906 27,873 1,033

IN Warrick 4 Table1 34,078 36,413 29,577 38,281 36,413 1,868

KS La Cygne 1 Substitution 6,319 10,906 23,489 11,297 10,906 391

KS Quindaro 2 Table1 2,985 2,411 4,109 7,818 2,411 5,407

KY Coleman C1 Table1 13,908 11,138 10,954 13,478 11,138 2,340

KY Coleman C2 Table1 9,677 12,879 12,502 14,995 12,879 2,116

KY Coleman C3 Table1 14,568 13,420 12,015 15,862 13,420 2,442

KY Cooper CS1 (1, 2) 17,613 19,882

KY Cooper 1 Table1 7,254 13,675 6,561 7,114

KY Cooper 2 Table1 14,917 28,708 13,321 15,387

KY E W Brown 1 Table1 6,762 7,051 6,923 22,972 7,051 15,921

KY E W Brown CS003 (2, 3) 35,473 38,513

KY E W Brown 2 Table1 10,623 33,638 10,813 22,825

KY E W Brown 3 Table1 25,413 87,703 27,700 60,003

KY East Bend 2 Substitution 13,064 18,096 17,447 29,713 18,096 11,617

KY Elmer Smith XS12 (1, 2) 7,011 8,402

KY Elmer Smith 1 Table1 6,348 8,147 2,521 5,626

KY Elmer Smith 2 Table1 14,031 18,231 5,881 12,350

KY Ghent 1 Table1 7,396 6,452 33,701 135,908 6,452 129,456

KY Green River 5 Table1 14,438 11,122 7,614 14,979 11,122 3,857

KY H L Spurlock 1 Table1 14,941 16,444 22,181 53,604 16,444 37,160

KY Hmp&L Station 2 H1 Table1 2,397 2,560 17,900 9,609 2,560 7,049

KY Hmp&L Station 2 H2 Table1 2,130 3,246 17,059 8,311 3,246 5,065

KY Paradise 3 Table1 126,946 145,724 57,613 244,152 145,724 98,428

KY R D Green G1 Substitution 1,828 2,544 5,041 7,367 2,544 4,823

KY R D Green G2 Substitution 2,136 2,300 5,827 8,538 2,300 6,238

KY Shawnee 10 Table1 1,560 1,597 9,902 26,394 1,597 24,797

MA Brayton Point 1 Compensating 9,739 10,328 15,085 11,360 10,328 1,032

MA Brayton Point 2 Compensating 9,744 10,030 15,838 11,035 10,030 1,005

MA Mount Tom 1 Substitution 8,417 7,172 10,708 15,576 7,172 2,311 6,093

MD C P Crane 1 Table1 15,224 12,942 10,058 66,953 12,942 54,011

MD C P Crane 2 Table1 13,636 18,121 8,987 22,611 18,121 4,490

MD Chalk Point CSE12 (1, 2) 44,721 45,450

MD Chalk Point 1 Table1 21,333 30,240 22,986 7,254

MD Chalk Point 2 Table1 23,690 30,290 22,464 7,826

MD Chalk Point 3 Substitution 7,732 7,898 9,000 20,268 7,898 12,370

B-4, 5
APPENDIX B-4: EMISSIONS AND ALLOWANCE HOLDINGS OF PHASE I UNITS FOR 1999

SO2 SO2 1999 Held in Allowances Deducted Under Allowances

Emissions Emissions Allowances Unit Accounts Deducted for Special Phase I Carried Over

State Plant Name Stack/Unit ID Unit Type (a) 1998(b) 1999(b) Allocated (c) as of 3/1/00 Emissions (d) Provisions (e) to 2000

MD Morgantown 1 Table1 34,953 41,194 34,332 62,425 41,194 21,231

MD Morgantown 2 Table1 44,953 34,325 37,467 42,273 34,325 7,948

MD R P Smith 9 Substitution 117 133 386 556 133 423

MD R P Smith 11 Substitution 2,262 2,664 3,128 2,691 2,664 27

MI Dan E Karn 2 Substitution 8,426 10,282 10,984 11,312 10,282 1,030

MI J C Weadock CS0009 (7, 8) 12,330 10,701

MI J C Weadock 7 Substitution 5,473 4,865 4,422 443

MI J C Weadock 8 Substitution 5,451 6,908 6,279 629

MI J H Campbell CS0009 (1, 2) 22,693 24,089

MI J H Campbell 1 Table1 18,773 11,352 10,320 1,032

MI J H Campbell 2 Table1 22,453 15,147 13,769 1,378

MI J R Whiting 1 Substitution 3,940 3,835 4,188 4,220 3,835 385

MI J R Whiting 2 Substitution 4,561 4,090 4,304 4,501 4,090 411

MI J R Whiting 3 Substitution 4,755 4,925 5,498 5,419 4,925 494

MN High Bridge CS0001 (3, 4, 5, 6) 4,044 3,482

MN High Bridge 3 Substitution 299 3,397 201 3,196

MN High Bridge 4 Substitution 242 1,937 336 1,601

MN High Bridge 5 Substitution 410 2,022 1,154 868

MN High Bridge 6 Table1 4,158 9,485 1,791 7,694

MN Sherburne County CS1 (1, 2) 8,958 10,756

MN Sherburne County 1 Substitution 4,681 16,114 4,955 11,159

MN Sherburne County 2 Substitution 4,727 16,227 5,801 10,426

MO Asbury 1 Table1 8,212 8,046 15,764 45,191 8,046 37,145

MO Hawthorn 5 Substitution 7,106 821 6,927 21,707 821 20,886

MO James River 3 Substitution 1,409 1,001 2,536 5,037 1,001 4,036

MO James River 4 Substitution 1,708 1,438 4,304 7,740 1,438 6,302

MO James River 5 Table1 2,810 2,588 4,722 5,400 2,588 2,812

MO Labadie 1 Table1 15,654 10,184 39,055 12,112 10,184 1,928

MO Labadie 2 Table1 12,987 10,959 36,718 12,968 10,959 2,009

MO Labadie 3 Table1 14,602 9,033 39,249 11,448 9,033 2,415

MO Labadie 4 Table1 14,354 8,605 34,994 11,032 8,605 2,427

MO Meramec 1 Substitution 1,670 1,897 1,816 3,017 1,897 1,120

MO Meramec 2 Substitution 1,541 1,798 1,948 3,280 1,798 1,482

MO Meramec 3 Substitution 3,706 3,902 4,166 5,976 3,902 2,074

MO Montrose 1 Table1 4,072 2,644 7,196 4,445 2,644 1,801

MO Montrose CS023 (2, 3) 8,875 7,025

MO Montrose 2 Table1 7,984 5,863 3,674 2,189

MO Montrose 3 Table1 9,824 7,500 3,351 4,149

B-4, 6
APPENDIX B-4: EMISSIONS AND ALLOWANCE HOLDINGS OF PHASE I UNITS FOR 1999

SO2 SO2 1999 Held in Allowances Deducted Under Allowances

Emissions Emissions Allowances Unit Accounts Deducted for Special Phase I Carried Over

State Plant Name Stack/Unit ID Unit Type (a) 1998(b) 1999(b) Allocated (c) as of 3/1/00 Emissions (d) Provisions (e) to 2000

MO New Madrid 1 Table1 8,735 9,570 27,497 27,497 9,570 17,927

MO New Madrid 2 Table1 9,018 6,863 31,625 31,425 6,863 24,562

MO Rush Island 1 Substitution 13,485 12,653 26,935 15,134 12,653 2,481

MO Rush Island 2 Substitution 13,924 14,543 30,146 17,248 14,543 2,705

MO Sibley CS0001 (1, 2, 3) 27,056 26,183

MO Sibley 1 Substitution 2,782 5,598 3,927 1,671

MO Sibley 2 Substitution 3,332 8,326 5,237 3,089

MO Sibley 3 Table1 15,170 18,152 17,019 1,133

MO Sioux 1 Table1 18,885 25,148 21,976 45,197 25,148 20,049

MO Sioux 2 Table1 23,062 18,624 23,067 38,088 18,624 19,464

MO Southwest 1 Substitution 6,837 3,538 3,906 4,230 3,538 692

MO Thomas Hill MB1 Table1 3,080 3,139 9,980 9,980 3,139 6,841

MO Thomas Hill MB2 Table1 4,722 5,220 18,880 18,880 5,220 13,660

MO Thomas Hill MB3 Substitution 9,916 12,768 14,011 14,011 12,768 1,243

MS Jack Watson 4 Table1 18,528 14,038 17,439 26,818 14,038 12,780

MS Jack Watson 5 Table1 32,033 32,552 35,734 52,075 32,552 19,523

MS R D Morrow 1 Substitution 4,267 3,572 4,571 5,186 3,572 1,614

MS R D Morrow 2 Substitution 4,383 3,642 5,002 7,085 3,642 3,443

NH Merrimack 1 Table1 12,126 12,479 9,922 12,825 12,479 346

NH Merrimack 2 Table1 22,794 22,320 21,421 22,674 22,320 354

NJ B L England 1 Table1 15,694 14,323 8,822 20,287 14,323 5,964

NJ B L England 2 Table1 1,084 978 14,886 2,803 978 1,825

NY Dunkirk CS0003 (3, 4) 37,527 36,414

NY Dunkirk 3 Table1 12,268 29,305 25,490 3,815

NY Dunkirk 4 Table1 13,690 15,095 10,924 4,171

NY Greenidge 6 Table1 9,027 8,865 7,342 15,589 8,865 6,724

NY Milliken XS12 (1, 2) 8,572 7,524

NY Milliken 1 Table1 10,876 15,934 3,729 12,205

NY Milliken 2 Table1 12,083 9,316 3,795 5,521

NY Northport 1 Table1 2,764 5,228 19,289 19,953 5,228 14,725

NY Northport 2 Table1 4,866 5,003 23,476 9,486 5,003 4,483

NY Northport 3 Table1 10,502 7,001 25,783 32,397 7,001 25,396

NY Northport 4 Substitution 1,136 1,313 5,516 14,058 1,313 12,745

NY Port Jefferson 3 Table1 4,185 2,325 10,194 10,228 2,325 7,903

NY Port Jefferson 4 Table1 3,171 2,025 12,006 15,846 2,025 13,821

OH Acme 13 Substitution 0 0 0 0 0 0

OH Acme 14 Substitution 0 0 12 0 0 0

OH Acme 15 Substitution 0 0 16 0 0 0

B-4, 7
APPENDIX B-4: EMISSIONS AND ALLOWANCE HOLDINGS OF PHASE I UNITS FOR 1999

SO2 SO2 1999 Held in Allowances Deducted Under Allowances

Emissions Emissions Allowances Unit Accounts Deducted for Special Phase I Carried Over

State Plant Name Stack/Unit ID Unit Type (a) 1998(b) 1999(b) Allocated (c) as of 3/1/00 Emissions (d) Provisions (e) to 2000

OH Acme 16 Substitution 0 0 1,930 0 0 0

OH Acme 91 Substitution 0 0 740 0 0 0

OH Acme 92 Substitution 0 0 662 0 0 0

OH Ashtabula 7 Table1 26,164 22,153 18,351 23,260 22,153 1,107

OH Ashtabula CS1 (8, 9, 10, 11) 2,048 3,865

OH Ashtabula 8 Substitution 7,487 911 866 45

OH Ashtabula 9 Substitution 7,016 0 0 0

OH Ashtabula 10 Substitution 6,155 1,680 1,600 80

OH Ashtabula 11 Substitution 6,452 1,467 1,399 68

OH Avon Lake 9 Substitution 0 0 8,763 672 0 672

OH Avon Lake 10 Substitution 1,222 1,714 7,879 2,000 1,714 286

OH Avon Lake 11 Table1 0 0 12,771 980 0 980

OH Avon Lake 12 Table1 27,714 31,154 33,413 32,791 31,154 1,637

OH Bay Shore CS5 (1, 2, 3, 4) 11,472 7,980

OH Bay Shore 1 Substitution 7,414 1,758 1,676 82

OH Bay Shore 2 Substitution 6,957 1,477 1,404 73

OH Bay Shore 3 Substitution 7,585 2,108 2,011 97

OH Bay Shore 4 Substitution 12,481 3,035 2,889 146

OH Cardinal 1 Table1 95,520 60,413 37,568 63,577 60,413 3,164

OH Cardinal 2 Table1 33,017 34,358 42,008 61,477 34,358 27,119

OH Conesville CS012 (1, 2) 30,089 25,887

OH Conesville 1 Table1 4,615 12,546 11,949 597

OH Conesville 2 Table1 5,360 14,635 13,938 697

OH Conesville 3 Table1 17,937 11,548 6,029 12,125 11,548 577

OH Conesville 4 Table1 72,035 83,894 53,463 87,460 83,894 3,566

OH Eastlake 1 Table1 11,186 10,490 8,551 11,015 10,490 525

OH Eastlake 2 Table1 11,992 12,441 9,471 13,063 12,441 622

OH Eastlake 3 Table1 12,985 12,349 10,984 12,966 12,349 617

OH Eastlake 4 Table1 18,497 19,978 15,906 20,977 19,978 999

OH Eastlake 5 Table1 56,011 60,129 37,349 63,135 60,129 3,006

OH Edgewater 11 Substitution 0 0 1,062 0 0 0

OH Edgewater 12 Substitution 0 0 1,145 0 0 0

OH Edgewater 13 Table1 7 20 5,536 200 20 180

OH Gen J M Gavin 1 Table1 15,085 8,717 113,172 9,156 8,717 439

OH Gen J M Gavin 2 Table1 18,718 6,529 115,070 35,605 6,529 29,076

OH Gorge 25 Substitution 0 0 2,503 0 0 0

OH Gorge 26 Substitution 0 0 2,791 0 0 0

OH J M Stuart 1 Substitution 27,024 24,210 41,189 43,633 24,210 19,423

B-4, 8
APPENDIX B-4: EMISSIONS AND ALLOWANCE HOLDINGS OF PHASE I UNITS FOR 1999

SO2 SO2 1999 Held in Allowances Deducted Under Allowances

Emissions Emissions Allowances Unit Accounts Deducted for Special Phase I Carried Over

State Plant Name Stack/Unit ID Unit Type (a) 1998(b) 1999(b) Allocated (c) as of 3/1/00 Emissions (d) Provisions (e) to 2000

OH J M Stuart 2 Substitution 29,520 23,091 39,041 36,057 23,091 12,966

OH J M Stuart 3 Substitution 23,211 25,129 38,712 42,818 25,129 17,689

OH J M Stuart 4 Substitution 23,603 29,557 40,925 46,727 29,557 17,170

OH Kyger Creek CS001 (1, 2, 3, 4, 5) 119,171 135,558

OH Kyger Creek 1 Table1 18,773 27,612 27,111 501

OH Kyger Creek 2 Table1 18,072 27,612 27,111 12 489

OH Kyger Creek 3 Table1 17,439 27,612 27,112 44 456

OH Kyger Creek 4 Table1 18,218 27,612 27,112 77 423

OH Kyger Creek 5 Table1 18,247 27,612 27,112 51 449

OH Lake Shore 18 Substitution 1,811 1,527 4,508 1,603 1,527 76

OH Lake Shore 91 Substitution 0 0 44 0 0 0

OH Lake Shore 92 Substitution 0 0 80 0 0 0

OH Lake Shore 93 Substitution 0 0 62 0 0 0

OH Lake Shore 94 Substitution 0 0 102 0 0 0

OH Miami Fort CS056 (5-1, 5-2, 6) 19,614 18,199

OH Miami Fort 6 Table1 12,475 30,410 14,797 15,613

OH Miami Fort 7 Table1 36,473 40,559 42,216 56,021 40,559 15,462

OH Miami Fort 5-1 Table1 417 1,933 1,701 232

OH Miami Fort 5-2 Table1 417 1,941 1,701 240

OH Muskingum River CS014 (1, 2, 3, 4) 152,316 78,543

OH Muskingum River 1 Table1 16,312 13,533 12,889 644

OH Muskingum River 2 Table1 15,533 24,039 22,894 1,145

OH Muskingum River 3 Table1 15,293 28,020 26,686 1,334

OH Muskingum River 4 Table1 12,914 16,877 16,074 803

OH Muskingum River 5 Table1 15,307 22,096 44,364 142,332 22,096 120,236

OH Niles XS12 (1, 2) 21,636 19,292

OH Niles 1 Table1 7,608 6,799 6,489 310

OH Niles 2 Table1 9,975 13,416 12,803 613

OH Picway 9 Table1 13,385 9,385 5,404 9,857 9,385 472

OH Poston 1 Substitution 0 0 0 0 0 0

OH Poston 2 Substitution 0 0 0 0 0 0

OH Poston 3 Substitution 0 0 0 0 0 0

OH R E Burger CS0001 (1, 2, 3, 4, 5, 6, 7, 8) 38,543 49,189

OH R E Burger 1 Substitution 2,820 0 0 0

OH R E Burger 2 Substitution 2,751 0 0 0

OH R E Burger 3 Substitution 2,891 0 0 0

OH R E Burger 4 Substitution 2,956 0 0 0

OH R E Burger 5 Table1 3,371 343 343 0

B-4, 9
APPENDIX B-4: EMISSIONS AND ALLOWANCE HOLDINGS OF PHASE I UNITS FOR 1999

SO2 SO2 1999 Held in Allowances Deducted Under Allowances

Emissions Emissions Allowances Unit Accounts Deducted for Special Phase I Carried Over

State Plant Name Stack/Unit ID Unit Type (a) 1998(b) 1999(b) Allocated (c) as of 3/1/00 Emissions (d) Provisions (e) to 2000

OH R E Burger 6 Table1 3,371 515 493 22

OH R E Burger 7 Table1 11,818 25,428 24,201 1,227

OH R E Burger 8 Table1 13,626 25,363 24,152 1,211

OH Toronto 9 Substitution 0 0 5,315 0 0 0

OH Toronto 10 Substitution 0 0 9,505 0 0 0

OH Toronto 11 Substitution 0 0 10,274 0 0 0

OH W H Sammis 5 Table1 16,812 19,111 26,496 20,066 19,111 955

OH W H Sammis 6 Table1 20,352 36,395 43,773 38,215 36,395 1,820

OH W H Sammis 7 Table1 45,828 44,027 47,380 46,486 44,027 2,459

OH Walter C Beckjord 5 Table1 20,329 14,764 9,811 18,952 14,764 4,188

OH Walter C Beckjord 6 Table1 39,455 26,050 25,235 43,169 26,050 17,119

PA Armstrong 1 Table1 18,227 12,471 14,031 14,520 12,471 2,049

PA Armstrong 2 Table1 17,658 15,125 15,024 15,692 15,125 567

PA Bruce Mansfield 1 Substitution 7,527 7,491 10,510 8,908 7,491 1,417

PA Bruce Mansfield 2 Substitution 6,765 9,438 11,537 10,162 9,438 724

PA Brunner Island CS102 (1, 2) 48,020 40,437

PA Brunner Island 1 Table1 27,030 18,952 17,868 1,084

PA Brunner Island 2 Table1 30,282 23,686 22,569 1,117

PA Brunner Island 3 Table1 47,679 30,751 52,404 33,434 30,751 2,683

PA Cheswick 1 Table1 32,177 41,602 38,139 49,133 41,602 7,531

PA Conemaugh 1 Table1 3,874 4,472 81,384 12,945 4,472 8,473

PA Conemaugh 2 Table1 4,347 3,421 91,607 12,398 3,421 8,977

PA Hatfield's Ferry XS123 (1, 2, 3) 150,868 141,872

PA Hatfield's Ferry 1 Table1 36,835 51,231 50,732 499

PA Hatfield's Ferry 2 Table1 36,338 36,964 36,599 365

PA Hatfield's Ferry 3 Table1 39,210 55,096 54,541 555

PA Martins Creek CS102 (1, 2) 15,834 13,972

PA Martins Creek 1 Table1 12,327 7,551 7,112 439

PA Martins Creek 2 Table1 12,483 7,451 6,860 591

PA Martins Creek 3 Substitution 4,742 2,248 12,553 2,562 2,248 314

PA Martins Creek 4 Substitution 4,347 3,310 11,548 3,779 3,310 469

PA Mitchell 33 Substitution 1,050 994 1,101 1,272 994 278

PA New Castle 1 Substitution 0 0 1,367 105 0 105

PA New Castle 2 Substitution 0 0 1,520 117 0 117

PA Portland 1 Table1 9,772 11,220 5,784 66,448 11,220 55,228

PA Portland 2 Table1 12,126 15,099 9,961 18,640 15,099 3,541

PA Shawville 1 Table1 12,864 10,974 10,048 11,082 10,974 108

PA Shawville 2 Table1 12,365 12,853 10,048 13,106 12,853 253

B-4, 10
APPENDIX B-4: EMISSIONS AND ALLOWANCE HOLDINGS OF PHASE I UNITS FOR 1999

SO2 SO2 1999 Held in Allowances Deducted Under Allowances

Emissions Emissions Allowances Unit Accounts Deducted for Special Phase I Carried Over

State Plant Name Stack/Unit ID Unit Type (a) 1998(b) 1999(b) Allocated (c) as of 3/1/00 Emissions (d) Provisions (e) to 2000

PA Shawville CS1 (3, 4) 33,535 27,959

PA Shawville 3 Table1 13,846 15,486 15,380 106

PA Shawville 4 Table1 13,700 12,850 12,579 271

PA Sunbury 3 Table1 10,307 6,099 8,530 16,030 6,099 9,931

PA Sunbury 4 Table1 11,970 7,480 11,149 13,649 7,480 6,169

TN Allen 1 Table1 5,671 3,997 14,917 34,438 3,997 30,441

TN Allen 2 Table1 7,378 4,393 16,329 36,556 4,393 32,163

TN Allen 3 Table1 7,162 5,291 15,258 37,436 5,291 32,145

TN Cumberland 1 Table1 10,610 7,070 114,325 235,645 7,070 228,575

TN Cumberland 2 Table1 9,891 8,851 126,157 245,652 8,851 236,801

TN DuPont Johnsonville JVD1 Opt-In 0 0 1,778 0 0 0

TN DuPont Johnsonville JVD2 Opt-In 0 0 1,778 0 0 0

TN DuPont Johnsonville JVD3 Opt-In 0 0 1,777 0 0 0

TN DuPont Johnsonville JVD4 Opt-In 0 0 1,777 0 0 0

TN Gallatin CSGA12 (1, 2) 40,664 37,124

TN Gallatin 1 Table1 17,400 22,849 19,615 3,234

TN Gallatin 2 Table1 16,855 19,909 17,509 2,400

TN Gallatin CSGA34 (3, 4) 45,551 47,717

TN Gallatin 3 Table1 19,493 28,229 24,483 3,746

TN Gallatin 4 Table1 20,701 26,427 23,234 3,193

TN Johnsonville CSJO10 (1, 2, 3, 4, 5, 6, 7, 8, 9, 10) 114,588 119,778

TN Johnsonville 1 Table1 7,585 14,063 12,089 1,974

TN Johnsonville 2 Table1 7,828 13,454 12,323 1,131

TN Johnsonville 3 Table1 8,189 15,409 10,974 4,435

TN Johnsonville 4 Table1 7,780 13,348 12,261 1,087

TN Johnsonville 5 Table1 8,023 11,230 10,833 397

TN Johnsonville 6 Table1 7,682 11,906 11,004 902

TN Johnsonville 7 Table1 8,744 13,981 12,640 1,341

TN Johnsonville 8 Table1 8,471 13,728 10,353 3,375

TN Johnsonville 9 Table1 6,894 17,190 15,320 1,870

TN Johnsonville 10 Table1 7,351 14,804 11,981 2,823

WI Alma CS2 (B1, B2, B3) 1,287 757

WI Alma B1 Opt-In 537 608 273 335

WI Alma B2 Opt-In 518 612 232 380

WI Alma B3 Opt-In 455 513 252 261

WI Alma CS1 (B1, B2, B3, B4, B5) 6,517 3,060

WI Alma B4 Substitution 2,207 8,714 1,329 7,385

WI Alma B5 Substitution 3,624 18,226 1,731 16,495

B-4, 11
APPENDIX B-4: EMISSIONS AND ALLOWANCE HOLDINGS OF PHASE I UNITS FOR 1999

SO2 SO2 1999 Held in Allowances Deducted Under Allowances

Emissions Emissions Allowances Unit Accounts Deducted for Special Phase I Carried Over

State Plant Name Stack/Unit ID Unit Type (a) 1998(b) 1999(b) Allocated (c) as of 3/1/00 Emissions (d) Provisions (e) to 2000

WI Edgewater 3 Substitution 1,973 1,356 4,493 15,786 1,356 14,430

WI Edgewater 4 Table1 8,391 6,624 24,099 36,598 6,624 29,974

WI Genoa 1 Table1 9,031 12,513 22,103 41,191 12,513 28,678

WI J P Madgett B1 Substitution 5,223 5,333 6,407 12,885 5,333 7,552

WI Nelson Dewey CS1 (1, 2) 10,861 13,280

WI Nelson Dewey 1 Table1 5,852 12,247 6,594 5,653

WI Nelson Dewey 2 Table1 6,504 14,617 6,686 7,931

WI North Oak Creek 1 Table1 0 0 5,083 0 0 0

WI North Oak Creek 2 Table1 0 0 5,005 0 0 0

WI North Oak Creek 3 Table1 0 0 5,229 0 0 0

WI North Oak Creek 4 Table1 0 0 6,154 0 0 0

WI Pulliam CS56 (5, 6) 1,884 2,278

WI Pulliam 5 Substitution 2,097 1,050 912 138

WI Pulliam 6 Substitution 2,844 1,570 1,366 204

WI Pulliam 7 Substitution 1,569 1,264 7,317 1,400 1,264 136

WI Pulliam 8 Table1 2,283 2,196 7,312 2,500 2,196 304

WI Rock River 1 Substitution 1,532 656 5,398 20,924 656 20,268

WI Rock River 2 Substitution 1,898 741 4,034 13,673 741 12,932

WI South Oak Creek CS3 (5, 6) 16,781 15,736

WI South Oak Creek 5 Table1 9,416 10,064 8,469 1,595

WI South Oak Creek 6 Table1 11,723 12,753 7,267 5,486

WI South Oak Creek CS4 (7, 8) 26,529 17,153

WI South Oak Creek 7 Table1 15,754 17,147 8,659 8,488

WI South Oak Creek 8 Table1 15,375 16,634 8,494 8,140

WI Weston 1 Substitution 1,111 1,263 1,579 1,500 1,263 237

WI Weston 2 Substitution 1,922 1,778 3,580 2,000 1,778 222

WV Albright 1 Substitution 2,202 2,500 4,831 3,634 2,500 1,134

WV Albright 2 Substitution 1,929 2,523 5,024 3,041 2,523 518

WV Albright 3 Table1 7,228 11,640 11,684 13,390 11,640 1,750

WV Fort Martin 1 Table1 41,641 50,943 40,496 51,452 50,943 509

WV Fort Martin 2 Table1 37,663 48,158 40,116 48,640 48,158 482

WV Harrison XS123 (1, 2, 3) 6,934 6,835

WV Harrison 1 Table1 68,078 2,422 2,009 413

WV Harrison 2 Table1 64,488 2,090 2,029 61

WV Harrison 3 Table1 57,730 2,825 2,797 28

WV Kammer CS013 (1, 2, 3) 108,618 104,231

WV Kammer 1 Table1 18,247 32,444 30,899 1,545

WV Kammer 2 Table1 18,948 41,313 39,346 1,967

B-4, 12
APPENDIX B-4: EMISSIONS AND ALLOWANCE HOLDINGS OF PHASE I UNITS FOR 1999

SO2 SO2 1999 Held in Allowances Deducted Under Allowances

Emissions Emissions Allowances Unit Accounts Deducted for Special Phase I Carried Over

State Plant Name Stack/Unit ID Unit Type (a) 1998(b) 1999(b) Allocated (c) as of 3/1/00 Emissions (d) Provisions (e) to 2000

WV Kammer 3 Table1 16,932 35,447 33,986 1,461

WV Mitchell CS012 (1, 2) 59,330 55,046

WV Mitchell 1 Table1 42,823 44,242 27,022 17,220

WV Mitchell 2 Table1 44,312 45,859 28,024 17,835

WV Mt Storm CS0 (1, 2) 106,759 101,124

WV Mt Storm 1 Table1 42,570 103,790 50,562 53,228

WV Mt Storm 2 Table1 34,644 77,853 50,562 27,291

WV Mt Storm 3 Table1 4,576 3,481 56,589 108,656 3,481 105,175

WV Rivesville 7 Substitution 624 444 1,009 1,066 444 622

WV Rivesville 8 Substitution 1,995 2,954 3,059 2,984 2,954 30

NOTES:

(a) Identifies the affected unit as listed in Table 1, or as a substitution, compensating, or opt-in unit.

(b) Both 1998 and 1999 emissions appear as reported by CEMS under the Acid Rain Program.

(c) This column lists allowances allocated under the following provisions: Initial Allocation (to Table 1 units), allowances for substitution and

 compensating units, Phase I Extension Allowances, Early Reduction Credits, and Conservation allowances. 

(d) This column displays the 1999 emissions for units that are not connected to a common stack. For units sharing a common stack, an apportionment was 

 made either by the unit or by EPA to divide up the stack's emissions among the units sharing the stack. 

(e) This column displays the sum of allowance deductions made for underutilization and state cap provisions. 

B-4, 13
APPENDIX C

Appendix C-1: List of Averaging Plans and Results in 1999

Appendix C-2: Compliance Results for the 265 NOx Affected Units in 1999

Appendix C-3: Compliance Results for the 274 Early Election Units in 1999
Appendix C-1: List of Averaging Plans and Results in 1999

C-1, 1

Company ORIS Code Plant Name, State and Units Plant Limit Plan Rate

AES Greenidge LLC

2527 Greenidge NY 6

0.45 0.30

2535 Milliken NY 1, 2

Allegheny Energy Supply

3942 Albright WV 1-3

0.49 0.45

3178 Armstrong PA 1, 2

3944 Harrison WV 1-3

3943 Fort Martin WV 1

3181 Mitchell PA 33

6004 Pleasants PA 1, 2

1570 R P Smith PA 9, 11

Ameren Services 862 Grand Tower IL 07-09 0.45 0.32

863 Hutsonville IL 05, 06

864 Meredosia IL 01-05

6017 Newton IL 1, 2

Ameren Services

2103 Labadie MO 1-4

0.45 0.18

2104 Meramec MO 1-4

6155 Rush Island MO 1, 2

Cinergy Corp.

1001 Cayuga IN 1, 2

0.48 0.42

6018 East Bend 2

6113 Gibson IN 1-4

2832 Miami Fort OH 6

1008 R Gallagher IN 1-4

1010 Wabash River IN 2, 3, 5, 6

2830 Walter C Beckjord 5, 6
Appendix C-1: List of Averaging Plans and Results in 1999

Company ORIS Code Plant Name, State and Units Plant Limit Plan Rate

C-1, 2

Dairyland Power Cooperative

4140 Alma WI B4, B5

0.48 0.43

4143 Genoa WI 1

4271 J P Madgett WI B1

Dynegy Midwest Generation, Inc.

889 Baldwin IL 3

0.45 0.40

892 Hennepin IL 2

897 Vermilion IL 1, 2

East Kentucky Power Cooperative 1384 Cooper KY 1, 2 0.50 0.42

FirstEnergy Corporation

6094 Bruce Mansfield PA 1, 2

0.50 0.43

2857 Edgewater OH 13

2858 Gorge OH 25, 26

3138 New Castle PA 1, 2

2867 Toronto OH 10, 11

2864 R E Burger OH 7, 8 

2866 W H Sammis OH 5, 6

Hoosier Energy Rec., Inc. 1043 Frank E Ratts IN 1SG1, 2SG1 0.50 0.47

IES Utilities, Inc.

1104 Burlington IA 1

0.47 0.29

1073 Prairie Creek IA 4
Appendix C-1: List of Averaging Plans and Results in 1999

Company ORIS Code Plant Name, State and Units Plant Limit Plan Rate

C-1, 3

Indianapolis Power & Light

990 Elmer W Stout IN 50, 60, 70

0.45 0.35

991 H T Pritchard IN 3-6

994 Petersburg IN 1-4

LG&E Energy Corporation

1355 E W Brown KY 1-3

1356 Ghent KY 1 0.46 0.41

1357 Green River KY 5

Northern States Power Company

1912 High Bridge MN 3-6

0.46 0.31

6090 Sherburne County MN 1, 2

PP&L

3140 Brunner Island PA 1-3

0.46 0.36

3148 Martins Creek PA 1, 2

3152 Sunbury PA 3, 4

Sithe 3113 Portland PA 1, 2 0.45 0.26

South Mississippi Elec. Power

Assoc. 6061 R D Morrow MS 1, 2 0.50 0.46
Appendix C-1: List of Averaging Plans and Results in 1999

Company ORIS Code Plant Name, State and Units Plant Limit Plan Rate

C-1, 4

Southern Company

699 Arkwright GA 1-4

0.46 0.44

703 Bowen GA 1BLR - 4BLR

641 Crist FL 4-7

26 E C Gaston AL 1-5

7 Gadsden AL 1-2

708 Hammond GA 1-4

709 Harllee Branch GA 2

710 Jack McDonough GA MB1, MB2

2049 Jack Watson MS 4, 5

733 Kraft GA 1-3

6124 McIntosh GA 1

727 Mitchell GA 3

6257 Scherer GA 3

6052 Wansley GA 1, 2

728 Yates GA Y1BR - Y7BR

642 Scholz FL1, 2

6073 Victor J Daniel Jr MS 1, 2

Springfield (MO), City Utilities of

2161 James River MO 3-5

0.50 0.44

6195 Southwest MO 1

TVA

47 Colbert AL 1-5

0.48 0.42

3403 Gallatin TN 1-4

3406 Johnsonville TN 1-10

Wisconsin Electric Power Company

4040 Port Washington WI 1-4

0.48 0.35
Appendix C-1: List of Averaging Plans and Results in 1999

Company ORIS Code Plant Name, State and Units Plant Limit Plan Rate

C-1, 5

4041 South Oak Creek WI 5-8

4042 Valley (WEPCO) WI 1-4

Wisconsin Public Service Corp.

4072 Pulliam WI 7, 8

0.47 0.33

4078 Weston WI 1-3
Appendix C-2: Compliance Results for the 265 Phase I NOx

 Affected Units in 1999

C-2, 1

1999

ST Plant Name Operating Utility

ORIS

Code Boiler Compliance Approach

Emission

Limit

Actual

Emission

Rate

AEL or 

Avg. Plan

Limit

Actual

Avg. Plan

Rate

1990

Emission

Rate

Change from

1990 to

1999

AL Colbert TVA 47 1 Averaging Plan 0.50 0.44 0.47 0.42 0.80 -45%

AL Colbert TVA 47 2 Averaging Plan 0.50 0.44 0.47 0.42 0.67 -34%

AL Colbert TVA 47 3 Averaging Plan 0.50 0.44 0.47 0.42 0.83 -47%

AL Colbert TVA 47 4 Averaging Plan 0.50 0.44 0.47 0.42 0.86 -49%

AL Colbert TVA 47 5 Averaging Plan 0.50 0.40 0.47 0.42 0.78 -49%

AL E C Gaston Alabama Power Co 26 1 Averaging Plan 0.50 0.50 0.46 0.44 0.90 -44%

AL E C Gaston Alabama Power Co 26 2 Averaging Plan 0.50 0.50 0.46 0.44 0.78 -36%

AL E C Gaston Alabama Power Co 26 3 Averaging Plan 0.50 0.47 0.46 0.44 0.80 -41%

AL E C Gaston Alabama Power Co 26 4 Averaging Plan 0.50 0.47 0.46 0.44 0.80 -41%

AL E C Gaston Alabama Power Co 26 5 Averaging Plan 0.45 0.40 0.46 0.44 0.78 -49%

AL Gadsden Alabama Power Co 7 1 Averaging Plan 0.45 0.61 0.46 0.44 0.51 19%

AL Gadsden Alabama Power Co 7 2 Averaging Plan 0.45 0.63 0.46 0.44 0.56 12%

FL Big Bend Tampa Electric Co 645 BB04 Standard Limitation 0.45 0.44 0.46 -5%

FL Crist Gulf Power Co 641 4 Averaging Plan 0.45 0.41 0.46 0.44 0.43 -4%

FL Crist Gulf Power Co 641 5 Averaging Plan 0.45 0.48 0.46 0.44 0.49 -2%

FL Crist Gulf Power Co 641 6 Averaging Plan 0.50 0.49 0.46 0.44 1.04 -53%

FL Crist Gulf Power Co 641 7 Averaging Plan 0.50 0.52 0.46 0.44 1.16 -55%

FL Scholz Gulf Power Co 642 1 Averaging Plan 0.50 0.66 0.46 0.44 0.69 -4%

FL Scholz Gulf Power Co 642 2 Averaging Plan 0.50 0.67 0.46 0.44 0.80 -16%

GA Arkwright Georgia Power Co 699 1 Averaging Plan 0.45 0.74 0.46 0.44 0.90 -18%

GA Arkwright Georgia Power Co 699 2 Averaging Plan 0.45 0.74 0.46 0.44 0.90 -18%

GA Arkwright Georgia Power Co 699 3 Averaging Plan 0.50 0.74 0.46 0.44 0.90 -18%

GA Arkwright Georgia Power Co 699 4 Averaging Plan 0.50 0.74 0.46 0.44 0.90 -18%

GA Bowen Georgia Power Co 703 1BLR Averaging Plan 0.45 0.42 0.46 0.44 0.67 -37%

GA Bowen Georgia Power Co 703 2BLR Averaging Plan 0.45 0.43 0.46 0.44 0.65 -34%

GA Bowen Georgia Power Co 703 3BLR Averaging Plan 0.45 0.42 0.46 0.44 0.56 -25%

GA Bowen Georgia Power Co 703 4BLR Averaging Plan 0.45 0.42 0.46 0.44 0.58 -28%

GA Hammond Georgia Power Co 708 1 Averaging Plan 0.50 0.78 0.46 0.44 0.84 -7%

GA Hammond Georgia Power Co 708 2 Averaging Plan 0.50 0.78 0.46 0.44 0.84 -7%

GA Hammond Georgia Power Co 708 3 Averaging Plan 0.50 0.78 0.46 0.44 0.84 -7%
Appendix C-2: Compliance Results for the 265 Phase I NOx

 Affected Units in 1999

1999

ST Plant Name Operating Utility

ORIS

Code Boiler Compliance Approach

Emission

Limit

Actual

Emission

Rate

AEL or 

Avg. Plan

Limit

Actual

Avg. Plan

Rate

1990

Emission

Rate

Change from

1990 to

1999

C-2, 2

GA Hammond Georgia Power Co 708 4 Averaging Plan 0.50 0.45 0.46 0.44 1.20 -63%

GA Harllee Branch Georgia Power Co 709 2 Averaging Plan 0.50 0.69 0.46 0.44 0.99 -30%

GA Jack McDonough Georgia Power Co 710 MB1 Averaging Plan 0.45 0.33 0.46 0.44 0.66 -50%

GA Jack McDonough Georgia Power Co 710 MB2 Averaging Plan 0.45 0.33 0.46 0.44 0.60 -45%

GA Kraft Savannah Electric & Power 733 1 Averaging Plan 0.45 0.55 0.46 0.44 0.40 39%

GA Kraft Savannah Electric & Power 733 2 Averaging Plan 0.45 0.55 0.46 0.44 0.40 39%

GA Kraft Savannah Electric & Power 733 3 Averaging Plan 0.45 0.55 0.46 0.44 0.40 39%

GA Mcintosh Savannah Electric & Power 6124 1 Averaging Plan 0.50 0.81 0.46 0.44 0.83 -3%

GA Mitchell Georgia Power Co 727 3 Averaging Plan 0.45 0.57 0.46 0.44 0.61 -7%

GA Scherer Georgia Power Co 6257 3 Averaging Plan 0.45 0.26 0.46 0.44 0.20 29%

GA Wansley Georgia Power Co 6052 1 Averaging Plan 0.45 0.41 0.46 0.44 0.73 -44%

GA Wansley Georgia Power Co 6052 2 Averaging Plan 0.45 0.41 0.46 0.44 0.67 -39%

GA Yates Georgia Power Co 728 Y1BR Averaging Plan 0.45 0.40 0.46 0.44 0.56 -29%

GA Yates Georgia Power Co 728 Y2BR Averaging Plan 0.45 0.44 0.46 0.44 0.62 -29%

GA Yates Georgia Power Co 728 Y3BR Averaging Plan 0.45 0.44 0.46 0.44 0.62 -29%

GA Yates Georgia Power Co 728 Y4BR Averaging Plan 0.45 0.37 0.46 0.44 0.56 -34%

GA Yates Georgia Power Co 728 Y5BR Averaging Plan 0.45 0.37 0.46 0.44 0.65 -43%

GA Yates Georgia Power Co 728 Y6BR Averaging Plan 0.45 0.29 0.46 0.44 0.67 -57%

GA Yates Georgia Power Co 728 Y7BR Averaging Plan 0.45 0.29 0.46 0.44 0.61 -52%

IA Burlington IES Utilities, Inc. 1104 1 Averaging Plan 0.45 0.22 0.47 0.29 0.63 -65%

IA Milton L Kapp Interstate Power Co 1048 2 Standard Limitation 0.45 0.33 0.80 -59%

IA Prairie Creek IES Utilities, Inc. 1073 4 Averaging Plan 0.50 0.38 0.47 0.29 1.05 -64%

IA Riverside MidAmerican Energy Company 1081 9 Standard Limitation 0.45 0.33 0.82 -60%

IL Baldwin Illinova Power Marketing, Inc. 889 3 Averaging Plan 0.45 0.34 0.45 0.40 0.67 -49%

IL Grand Tower CIPSCO 862 7 Averaging Plan 0.50 0.72 0.45 0.32 0.78 -7%

IL Grand Tower CIPSCO 862 8 Averaging Plan 0.50 0.8 0.45 0.32 0.96 -17%

IL Grand Tower CIPSCO 862 9 Averaging Plan 0.50 0.65 0.45 0.32 0.64 -2%

IL Hennepin Illinova Power Marketing, Inc. 892 2 Averaging Plan 0.45 0.53 0.45 0.40 0.59 -10%

IL Hutsonville CIPSCO 863 5 Averaging Plan 0.45 0.56 0.45 0.32 0.70 -20%

IL Hutsonville CIPSCO 863 6 Averaging Plan 0.45 0.60 0.45 0.32 0.67 -10%
Appendix C-2: Compliance Results for the 265 Phase I NOx

 Affected Units in 1999

1999

ST Plant Name Operating Utility

ORIS

Code Boiler Compliance Approach

Emission

Limit

Actual

Emission

Rate

AEL or 

Avg. Plan

Limit

Actual

Avg. Plan

Rate

1990

Emission

Rate

Change from

1990 to

1999

C-2, 3

IL Joppa Steam Electric Energy Inc 887 1 Standard Limitation 0.45 0.18 0.56 -68%

IL Joppa Steam Electric Energy Inc 887 2 Standard Limitation 0.45 0.18 0.56 -68%

IL Joppa Steam Electric Energy Inc 887 3 Standard Limitation 0.45 0.18 0.56 -68%

IL Joppa Steam Electric Energy Inc 887 4 Standard Limitation 0.45 0.18 0.56 -68%

IL Joppa Steam Electric Energy Inc 887 5 Standard Limitation 0.45 0.17 0.56 -70%

IL Joppa Steam Electric Energy Inc 887 6 Standard Limitation 0.45 0.17 0.56 -70%

IL Meredosia CIPSCO 864 1 Averaging Plan 0.45 0.53 0.45 0.32 0.50 5%

IL Meredosia CIPSCO 864 2 Averaging Plan 0.45 0.53 0.45 0.32 0.50 5%

IL Meredosia CIPSCO 864 3 Averaging Plan 0.45 0.53 0.45 0.32 0.50 5%

IL Meredosia CIPSCO 864 4 Averaging Plan 0.45 0.53 0.45 0.32 0.50 5%

IL Meredosia CIPSCO 864 5 Averaging Plan 0.45 0.55 0.45 0.32 0.67 -18%

IL Newton CIPSCO 6017 1 Averaging Plan 0.45 0.17 0.45 0.32 0.47 -64%

IL Newton CIPSCO 6017 2 Averaging Plan 0.45 0.29 0.45 0.32 0.39 -26%

IL Vermilion Illinova Power Marketing, Inc. 897 1 Averaging Plan 0.45 0.45 0.45 0.40 0.94 -52%

IL Vermilion Illinova Power Marketing, Inc. 897 2 Averaging Plan 0.45 0.45 0.45 0.40 0.74 -39%

IN Cayuga PSI Energy, Inc. 1001 1 Averaging Plan 0.45 0.31 0.48 0.42 0.42 -26%

IN Cayuga PSI Energy, Inc. 1001 2 Averaging Plan 0.45 0.33 0.48 0.42 0.47 -30%

IN Elmer W Stout Indianapolis Power & Light 990 50 Averaging Plan 0.45 0.37 0.45 0.35 0.63 -41%

IN Elmer W Stout Indianapolis Power & Light 990 60 Averaging Plan 0.45 0.38 0.45 0.35 0.65 -42%

IN Elmer W Stout Indianapolis Power & Light 990 70 Averaging Plan 0.45 0.37 0.45 0.35 0.71 -48%

IN F B Culley Southern Indiana Gas & Elec 1012 2 Standard Limitation 0.50 0.45 1.05 -57%

IN F B Culley Southern Indiana Gas & Elec 1012 3 Standard Limitation 0.50 0.45 1.23 -64%

IN Frank E Ratts Hoosier Energy REC, Inc. 1043 1SG1 Averaging Plan 0.50 0.48 0.50 0.47 1.08 -56%

IN Frank E Ratts Hoosier Energy REC, Inc. 1043 2SG1 Averaging Plan 0.50 0.47 0.50 0.47 1.09 -57%

IN Gibson PSI Energy, Inc. 6113 1 Averaging Plan 0.50 0.45 0.48 0.42 1.03 -56%

IN Gibson PSI Energy, Inc. 6113 2 Averaging Plan 0.50 0.45 0.48 0.42 1.12 -60%

IN Gibson PSI Energy, Inc. 6113 3 Averaging Plan 0.50 0.46 0.48 0.42 0.52 -12%

IN Gibson PSI Energy, Inc. 6113 4 Averaging Plan 0.50 0.41 0.48 0.42 0.66 -38%

IN H T Pritchard Indianapolis Power & Light 991 3 Averaging Plan 0.45 0.68 0.45 0.35 0.74 -8%

IN H T Pritchard Indianapolis Power & Light 991 4 Averaging Plan 0.45 0.68 0.45 0.35 0.74 -8%
Appendix C-2: Compliance Results for the 265 Phase I NOx

 Affected Units in 1999

1999

ST Plant Name Operating Utility

ORIS

Code Boiler Compliance Approach

Emission

Limit

Actual

Emission

Rate

AEL or 

Avg. Plan

Limit

Actual

Avg. Plan

Rate

1990

Emission

Rate

Change from

1990 to

1999

C-2, 4

IN H T Pritchard Indianapolis Power & Light 991 5 Averaging Plan 0.45 0.37 0.45 0.35 0.67 -45%

IN H T Pritchard Indianapolis Power & Light 991 6 Averaging Plan 0.45 0.37 0.45 0.35 0.47 -21%

IN Petersburg Indianapolis Power & Light 994 1 Averaging Plan 0.45 0.26 0.45 0.35 0.56 -53%

IN Petersburg Indianapolis Power & Light 994 2 Averaging Plan 0.45 0.33 0.45 0.35 0.63 -48%

IN Petersburg Indianapolis Power & Light 994 3 Averaging Plan 0.45 0.33 0.45 0.35 0.37 -11%

IN Petersburg Indianapolis Power & Light 994 4 Averaging Plan 0.45 0.32 0.45 0.35 0.37 -14%

IN R Gallagher PSI Energy, Inc. 1008 1 Averaging Plan 0.50 0.46 0.48 0.42 0.74 -38%

IN R Gallagher PSI Energy, Inc. 1008 2 Averaging Plan 0.50 0.46 0.48 0.42 0.95 -52%

IN R Gallagher PSI Energy, Inc. 1008 3 Averaging Plan 0.50 0.42 0.48 0.42 0.95 -56%

IN R Gallagher PSI Energy, Inc. 1008 4 Averaging Plan 0.50 0.42 0.48 0.42 0.95 -56%

IN Wabash River PSI Energy, Inc. 1010 1 Standard Limitation 0.50 0.15 0.52 -71%

IN Wabash River PSI Energy, Inc. 1010 2 Averaging Plan 0.50 0.49 0.48 0.42 0.95 -48%

IN Wabash River PSI Energy, Inc. 1010 3 Averaging Plan 0.50 0.57 0.48 0.42 0.92 -38%

IN Wabash River PSI Energy, Inc. 1010 5 Averaging Plan 0.50 0.49 0.48 0.42 0.85 -42%

IN Wabash River PSI Energy, Inc. 1010 6 Averaging Plan 0.45 0.38 0.48 0.42 0.37 2%

KS La Cygne Kansas City Power & Light 1241 2 Standard Limitation 0.50 0.29 0.29 0%

KS Quindaro Board of Public Util, KS City 1295 2 Standard Limitation 0.50 0.38 0.64 -40%

KY Coleman Big Rivers Electric 1381 C1 Standard Limitation 0.50 0.44 1.41 -69%

KY Coleman Big Rivers Electric 1381 C2 Standard Limitation 0.50 0.45 1.29 -65%

KY Coleman Big Rivers Electric 1381 C3 Standard Limitation 0.50 0.44 1.14 -61%

KY Cooper East Kentucky Power Coop 1384 1 Averaging Plan 0.50 0.42 0.50 0.42 0.90 -53%

KY Cooper East Kentucky Power Coop 1384 2 Averaging Plan 0.50 0.42 0.50 0.42 0.90 -53%

KY E W Brown Kentucky Utilities Co 1355 1 Averaging Plan 0.50 0.50 0.46 0.41 1.00 -50%

KY E W Brown Kentucky Utilities Co 1355 2 Averaging Plan 0.45 0.40 0.46 0.41 0.59 -32%

KY E W Brown Kentucky Utilities Co 1355 3 Averaging Plan 0.45 0.40 0.46 0.41 0.57 -30%

KY East Bend Cincinnati Gas & Electric Co 6018 2 Averaging Plan 0.50 0.41 0.48 0.42 0.31 32%

KY Elmer Smith Owensboro City of 1374 2 Standard Limitation 0.45 0.41 0.86 -52%

KY Ghent Kentucky Utilities Co 1356 1 Averaging Plan 0.45 0.41 0.46 0.41 0.56 -27%

KY Green River Kentucky Utilities Co 1357 5 Averaging Plan 0.50 0.41 0.46 0.41 0.84 -51%

KY H L Spurlock East Kentucky Power Coop 6041 1 Standard Limitation 0.50 0.42 0.90 -53%
Appendix C-2: Compliance Results for the 265 Phase I NOx

 Affected Units in 1999

1999

ST Plant Name Operating Utility

ORIS

Code Boiler Compliance Approach

Emission

Limit

Actual

Emission

Rate

AEL or 

Avg. Plan

Limit

Actual

Avg. Plan

Rate

1990

Emission

Rate

Change from

1990 to

1999

C-2, 5

KY HMP&L Station 2 WKE Station Two, Inc. 1382 H1 Standard Limitation 0.50 0.48 1.34 -64%

KY HMP&L Station 2 WKE Station Two, Inc. 1382 H2 Standard Limitation 0.50 0.48 1.34 -64%

KY R D Green Big Rivers Electric 6639 G1 Standard Limitation 0.50 0.41 0.41 0%

KY R D Green Big Rivers Electric 6639 G2 Standard Limitation 0.50 0.41 0.45 -9%

MD Chalk Point PEPCO 1571 1 AEL Demonstration 0.50 0.76 0.86 1.35 -44%

MD Chalk Point PEPCO 1571 2 AEL Demonstration 0.50 0.81 1.20 1.35 -40%

MD Morgantown PEPCO 1573 1 AEL Demonstration 0.45 0.63 0.70 0.95 -34%

MD Morgantown PEPCO 1573 2 AEL Demonstration 0.45 0.61 0.70 0.95 -36%

MD R P Smith Potomac Edison Co 1570 9 Averaging Plan 0.50 0.46 0.49 0.45 0.87 -47%

MD R P Smith Potomac Edison Co 1570 11 Averaging Plan 0.45 0.41 0.49 0.45 0.78 -47%

MI J H Campbell Consumers Energy Co 1710 1 AEL Demonstration 0.45 0.46 0.55 0.69 -33%

MN High Bridge Northern States Power Co 1912 3 Averaging Plan 0.50 0.55 0.46 0.31 0.48 15%

MN High Bridge Northern States Power Co 1912 4 Averaging Plan 0.50 0.55 0.46 0.31 0.48 15%

MN High Bridge Northern States Power Co 1912 5 Averaging Plan 0.50 0.55 0.46 0.31 0.48 15%

MN High Bridge Northern States Power Co 1912 6 Averaging Plan 0.50 0.55 0.46 0.31 0.48 15%

MN Sherburne County Northern States Power Co 6090 1 Averaging Plan 0.45 0.27 0.46 0.31 0.45 -40%

MN Sherburne County Northern States Power Co 6090 2 Averaging Plan 0.45 0.27 0.46 0.31 0.45 -40%

MO Hawthorn Kansas City Power & Light 2079 5 Standard Limitation 0.45 0.35 0.36 -3%

MO Iatan Kansas City Power & Light 6065 1 Standard Limitation 0.50 0.28 0.31 -9%

MO James River Springfield City of (MO) 2161 3 Averaging Plan 0.50 0.55 0.50 0.44 1.02 -46%

MO James River Springfield City of (MO) 2161 4 Averaging Plan 0.50 0.52 0.50 0.44 0.87 -40%

MO James River Springfield City of (MO) 2161 5 Averaging Plan 0.50 0.58 0.50 0.44 0.93 -38%

MO Labadie Union Electric Co 2103 1 Averaging Plan 0.45 0.13 0.45 0.18 0.62 -79%

MO Labadie Union Electric Co 2103 2 Averaging Plan 0.45 0.14 0.45 0.18 0.62 -77%

MO Labadie Union Electric Co 2103 3 Averaging Plan 0.45 0.14 0.45 0.18 0.62 -77%

MO Labadie Union Electric Co 2103 4 Averaging Plan 0.45 0.15 0.45 0.18 0.62 -76%

MO Meramec Union Electric Co 2104 1 Averaging Plan 0.45 0.46 0.45 0.18 0.82 -44%

MO Meramec Union Electric Co 2104 2 Averaging Plan 0.45 0.38 0.45 0.18 0.63 -39%

MO Meramec Union Electric Co 2104 3 Averaging Plan 0.50 0.57 0.45 0.18 0.96 -40%

MO Meramec Union Electric Co 2104 4 Averaging Plan 0.50 0.33 0.45 0.18 1.17 -72%
Appendix C-2: Compliance Results for the 265 Phase I NOx

 Affected Units in 1999

1999

ST Plant Name Operating Utility

ORIS

Code Boiler Compliance Approach

Emission

Limit

Actual

Emission

Rate

AEL or 

Avg. Plan

Limit

Actual

Avg. Plan

Rate

1990

Emission

Rate

Change from

1990 to

1999

C-2, 6

MO Montrose Kansas City Power & Light 2080 1 Standard Limitation 0.45 0.33 0.32 2%

MO Montrose Kansas City Power & Light 2080 2 Standard Limitation 0.45 0.40 0.34 17%

MO Montrose Kansas City Power & Light 2080 3 Standard Limitation 0.45 0.40 0.34 17%

MO Rush Island Union Electric Co 6155 1 Averaging Plan 0.45 0.15 0.45 0.18 0.63 -76%

MO Rush Island Union Electric Co 6155 2 Averaging Plan 0.45 0.14 0.45 0.18 0.63 -78%

MO Southwest Springfield City of (MO) 6195 1 Averaging Plan 0.50 0.32 0.50 0.44 0.47 -32%

MO Thomas Hill Associated Electric Coop Inc 2168 MB3 Standard Limitation 0.50 0.31 0.31 0%

MS Jack Watson Mississippi Power Co 2049 4 Averaging Plan 0.50 0.51 0.46 0.44 1.10 -54%

MS Jack Watson Mississippi Power Co 2049 5 Averaging Plan 0.50 0.69 0.46 0.44 1.22 -43%

MS R D Morrow South Mississippi Electric Pwr 6061 1 Averaging Plan 0.50 0.45 0.50 0.46 0.42 8%

MS R D Morrow South Mississippi Electric Pwr 6061 2 Averaging Plan 0.50 0.47 0.50 0.46 0.43 10%

MS Victor J Daniel Jr Mississippi Power Co 6073 1 Averaging Plan 0.45 0.32 0.46 0.44 0.27 20%

MS Victor J Daniel Jr Mississippi Power Co 6073 2 Averaging Plan 0.45 0.27 0.46 0.44 0.28 -4%

NY Dunkirk Niagara Mohawk Power Corp 2554 3 Standard Limitation 0.45 0.36 0.48 -26%

NY Dunkirk Niagara Mohawk Power Corp 2554 4 Standard Limitation 0.45 0.36 0.48 -26%

NY Greenidge NGE Generation, Inc. 2527 6 Averaging Plan 0.45 0.31 0.45 0.30 0.55 -44%

NY Milliken NGE Generation, Inc. 2535 1 Averaging Plan 0.45 0.30 0.45 0.30 0.66 -55%

NY Milliken NGE Generation, Inc. 2535 2 Averaging Plan 0.45 0.30 0.45 0.30 0.59 -49%

OH Ashtabula Cleveland Electric Illum 2835 7 Standard Limitation 0.45 0.40 0.61 -34%

OH Conesville Columbus Southern Power 2840 3 Standard Limitation 0.50 0.45 0.93 -52%

OH Conesville Columbus Southern Power 2840 4 Standard Limitation 0.45 0.43 0.55 -22%

OH Eastlake Cleveland Electric Illum 2837 1 Standard Limitation 0.45 0.43 0.49 -12%

OH Eastlake Cleveland Electric Illum 2837 2 Standard Limitation 0.45 0.37 0.68 -46%

OH Eastlake Cleveland Electric Illum 2837 3 Standard Limitation 0.45 0.40 0.54 -26%

OH Eastlake Cleveland Electric Illum 2837 4 Standard Limitation 0.45 0.35 0.51 -31%

OH Edgewater Ohio Edison Co 2857 13 Averaging Plan 0.50 0.37 0.50 0.43 0.87 -57%

OH Gorge Ohio Edison Co 2858 25 Averaging Plan 0.50 Not Oper. 0.50 0.43 0.00

OH Gorge Ohio Edison Co 2858 26 Averaging Plan 0.50 Not Oper. 0.50 0.43 0.00

OH Miami Fort Cincinnati Gas & Electric Co 2832 6 Averaging Plan 0.45 0.51 0.48 0.42 0.73 -30%

OH Picway Columbus Southern Power 2843 9 Standard Limitation 0.50 0.41 0.87 -53%
Appendix C-2: Compliance Results for the 265 Phase I NOx

 Affected Units in 1999

1999

ST Plant Name Operating Utility

ORIS

Code Boiler Compliance Approach

Emission

Limit

Actual

Emission

Rate

AEL or 

Avg. Plan

Limit

Actual

Avg. Plan

Rate

1990

Emission

Rate

Change from

1990 to

1999

C-2, 7

OH R E Burger Ohio Edison Co 2864 7 Averaging Plan 0.50 0.53 0.50 0.43 0.66 -20%

OH R E Burger Ohio Edison Co 2864 8 Averaging Plan 0.50 0.64 0.50 0.43 0.72 -12%

OH Toronto Ohio Edison Co 2867 10 Averaging Plan 0.50 Not Oper. 0.50 0.43 0.00

OH Toronto Ohio Edison Co 2867 11 Averaging Plan 0.50 Not Oper. 0.50 0.43 0.00

OH W H Sammis Ohio Edison Co 2866 5 Averaging Plan 0.50 0.53 0.50 0.43 0.52 1%

OH W H Sammis Ohio Edison Co 2866 6 Averaging Plan 0.50 0.50 0.50 0.43 1.10 -55%

OH Walter C Beckjord Cincinnati Gas & Electric Co 2830 5 Averaging Plan 0.45 0.46 0.48 0.42 0.72 -36%

OH Walter C Beckjord Cincinnati Gas & Electric Co 2830 6 Averaging Plan 0.45 0.35 0.48 0.42 0.71 -51%

PA Armstrong West Penn Power Co 3178 1 Averaging Plan 0.50 0.34 0.49 0.45 0.90 -62%

PA Armstrong West Penn Power Co 3178 2 Averaging Plan 0.50 0.36 0.49 0.45 1.04 -65%

PA Bruce Mansfield Pennsylvania Power Co. 6094 1 Averaging Plan 0.50 0.36 0.50 0.43 0.98 -63%

PA Bruce Mansfield Pennsylvania Power Co. 6094 2 Averaging Plan 0.50 0.32 0.50 0.43 1.13 -72%

PA Brunner Island PP&L 3140 1 Averaging Plan 0.45 0.35 0.46 0.36 0.65 -46%

PA Brunner Island PP&L 3140 2 Averaging Plan 0.45 0.35 0.46 0.36 0.71 -51%

PA Brunner Island PP&L 3140 3 Averaging Plan 0.45 0.33 0.46 0.36 0.83 -60%

PA Cheswick Duquesne Light Co 8226 1 Standard Limitation 0.45 0.31 0.71 -56%

PA Conemaugh Sithe Northeast Management Co. 3118 1 Standard Limitation 0.45 0.34 0.65 -47%

PA Conemaugh Sithe Northeast Management Co. 3118 2 Standard Limitation 0.45 0.32 0.71 -55%

PA Martins Creek PP&L 3148 1 Averaging Plan 0.50 0.44 0.46 0.36 1.03 -57%

PA Martins Creek PP&L 3148 2 Averaging Plan 0.50 0.44 0.46 0.36 0.93 -53%

PA Mitchell West Penn Power Co 3181 33 Averaging Plan 0.45 0.36 0.49 0.45 0.68 -47%

PA New Castle Ohio Edison Co 3138 1 Averaging Plan 0.50 Not Oper. 0.50 0.43 0.00

PA New Castle Ohio Edison Co 3138 2 Averaging Plan 0.50 Not Oper. 0.50 0.43 0.00

PA Portland Sithe Northeast Management Co. 3113 1 Averaging Plan 0.45 0.24 0.45 0.26 0.46 -48%

PA Portland Sithe Northeast Management Co. 3113 2 Averaging Plan 0.45 0.28 0.45 0.26 0.66 -58%

PA Shawville Sithe Northeast Management Co. 3131 1 Standard Limitation 0.50 0.43 0.99 -57%

PA Shawville Sithe Northeast Management Co. 3131 2 Standard Limitation 0.50 0.46 1.02 -55%

PA Shawville Sithe Northeast Management Co. 3131 3 Standard Limitation 0.45 0.38 0.83 -54%

PA Shawville Sithe Northeast Management Co. 3131 4 Standard Limitation 0.45 0.38 0.82 -53%

PA Sunbury Sunbury Generation, LLC 3152 3 Averaging Plan 0.50 0.39 0.46 0.36 0.93 -58%
Appendix C-2: Compliance Results for the 265 Phase I NOx

 Affected Units in 1999

1999

ST Plant Name Operating Utility

ORIS

Code Boiler Compliance Approach

Emission

Limit

Actual

Emission

Rate

AEL or 

Avg. Plan

Limit

Actual

Avg. Plan

Rate

1990

Emission

Rate

Change from

1990 to

1999

C-2, 8

PA Sunbury Sunbury Generation, LLC 3152 4 Averaging Plan 0.50 0.39 0.46 0.36 1.29 -70%

TN Gallatin TVA 3403 1 Averaging Plan 0.45 0.33 0.47 0.42 0.59 -44%

TN Gallatin TVA 3403 2 Averaging Plan 0.45 0.33 0.47 0.42 0.63 -48%

TN Gallatin TVA 3403 3 Averaging Plan 0.45 0.35 0.47 0.42 0.59 -41%

TN Gallatin TVA 3403 4 Averaging Plan 0.45 0.35 0.47 0.42 0.55 -36%

TN Johnsonville TVA 3406 1 Averaging Plan 0.45 0.48 0.47 0.42 0.45 7%

TN Johnsonville TVA 3406 2 Averaging Plan 0.45 0.48 0.47 0.42 0.48 0%

TN Johnsonville TVA 3406 3 Averaging Plan 0.45 0.48 0.47 0.42 0.46 4%

TN Johnsonville TVA 3406 4 Averaging Plan 0.45 0.48 0.47 0.42 0.54 -11%

TN Johnsonville TVA 3406 5 Averaging Plan 0.45 0.48 0.47 0.42 0.45 7%

TN Johnsonville TVA 3406 6 Averaging Plan 0.45 0.48 0.47 0.42 0.50 -4%

TN Johnsonville TVA 3406 7 Averaging Plan 0.50 0.48 0.47 0.42 1.00 -52%

TN Johnsonville TVA 3406 8 Averaging Plan 0.50 0.48 0.47 0.42 0.97 -51%

TN Johnsonville TVA 3406 9 Averaging Plan 0.50 0.48 0.47 0.42 1.10 -56%

TN Johnsonville TVA 3406 10 Averaging Plan 0.50 0.48 0.47 0.42 1.07 -55%

WI Alma Dairyland Power Coop 4140 B4 Averaging Plan 0.50 0.61 0.48 0.43 0.85 -28%

WI Alma Dairyland Power Coop 4140 B5 Averaging Plan 0.50 0.61 0.48 0.43 0.85 -28%

WI Genoa Dairyland Power Coop 4143 1 Averaging Plan 0.45 0.41 0.48 0.43 0.75 -45%

WI J P Madgett Dairyland Power Coop 4271 B1 Averaging Plan 0.50 0.41 0.48 0.43 0.30 38%

WI Port Washington Wisconsin Electric Power Co 4040 1 Averaging Plan 0.50 0.30 0.48 0.35 0.32 -6%

WI Port Washington Wisconsin Electric Power Co 4040 2 Averaging Plan 0.50 0.30 0.48 0.35 0.32 -6%

WI Port Washington Wisconsin Electric Power Co 4040 3 Averaging Plan 0.50 0.30 0.48 0.35 0.32 -6%

WI Port Washington Wisconsin Electric Power Co 4040 4 Averaging Plan 0.50 0.28 0.48 0.35 0.37 -25%

WI Port Washington Wisconsin Electric Power Co 4040 5 Standard Limitation 0.50 Not Oper. 0.00

WI Pulliam Wisconsin Public Service 4072 7 Averaging Plan 0.50 0.43 0.47 0.33 0.69 -38%

WI Pulliam Wisconsin Public Service 4072 8 Averaging Plan 0.50 0.36 0.47 0.33 0.57 -37%

WI South Oak Creek Wisconsin Electric Power Co 4041 5 Averaging Plan 0.50 0.26 0.48 0.35 0.28 -6%

WI South Oak Creek Wisconsin Electric Power Co 4041 6 Averaging Plan 0.50 0.26 0.48 0.35 0.28 -6%

WI South Oak Creek Wisconsin Electric Power Co 4041 7 Averaging Plan 0.45 0.37 0.48 0.35 0.66 -44%

WI South Oak Creek Wisconsin Electric Power Co 4041 8 Averaging Plan 0.45 0.37 0.48 0.35 0.67 -44%
Appendix C-2: Compliance Results for the 265 Phase I NOx

 Affected Units in 1999

1999

ST Plant Name Operating Utility

ORIS

Code Boiler Compliance Approach

Emission

Limit

Actual

Emission

Rate

AEL or 

Avg. Plan

Limit

Actual

Avg. Plan

Rate

1990

Emission

Rate

Change from

1990 to

1999

C-2, 9

WI Valley Wisconsin Electric Power Co 4042 1 Averaging Plan 0.50 0.47 0.48 0.35 1.10 -57%

WI Valley Wisconsin Electric Power Co 4042 2 Averaging Plan 0.50 0.47 0.48 0.35 1.10 -57%

WI Valley Wisconsin Electric Power Co 4042 3 Averaging Plan 0.50 0.49 0.48 0.35 1.05 -53%

WI Valley Wisconsin Electric Power Co 4042 4 Averaging Plan 0.50 0.49 0.48 0.35 0.93 -47%

WI Weston Wisconsin Public Service 4078 1 Averaging Plan 0.50 0.79 0.47 0.33 0.90 -12%

WI Weston Wisconsin Public Service 4078 2 Averaging Plan 0.50 0.36 0.47 0.33 1.08 -67%

WI Weston Wisconsin Public Service 4078 3 Averaging Plan 0.45 0.23 0.47 0.33 0.26 -10%

WV Albright Monongahela Power Co 3942 1 Averaging Plan 0.50 0.66 0.49 0.45 1.10 -40%

WV Albright Monongahela Power Co 3942 2 Averaging Plan 0.50 0.69 0.49 0.45 1.10 -37%

WV Albright Monongahela Power Co 3942 3 Averaging Plan 0.45 0.38 0.49 0.45 0.71 -46%

WV Fort Martin Monongahela Power Co 3943 1 Averaging Plan 0.45 0.65 0.49 0.45 0.62 5%

WV Harrison Monongahela Power Co 3944 1 Averaging Plan 0.50 0.47 0.49 0.45 0.99 -53%

WV Harrison Monongahela Power Co 3944 2 Averaging Plan 0.50 0.47 0.49 0.45 1.13 -58%

WV Harrison Monongahela Power Co 3944 3 Averaging Plan 0.50 0.47 0.49 0.45 1.06 -56%

WV Mitchell Ohio Power Co 3948 1 AEL Demonstration 0.50 0.54 0.56 0.77 -30%

WV Mitchell Ohio Power Co 3948 2 AEL Demonstration 0.50 0.52 0.56 0.77 -32%

WV Mt Storm VEPCO 3954 1 AEL Demonstration 0.45 0.64 0.76 0.88 -27%

WV Mt Storm VEPCO 3954 2 AEL Demonstration 0.45 0.64 0.69 0.76 -16%

WV Mt Storm VEPCO 3954 3 AEL Demonstration 0.45 0.67 0.74 1.27 -47%

WV Pleasants Monongahela Power Co 6004 1 Averaging Plan 0.50 0.37 0.49 0.45 0.52 -29%

WV Pleasants Monongahela Power Co 6004 2 Averaging Plan 0.50 0.33 0.49 0.45 0.35 -5%

WY Jim Bridger Pacificorp 8066 BW71 Standard Limitation 0.45 0.41 0.63 -35%

WY Jim Bridger Pacificorp 8066 BW72 Standard Limitation 0.45 0.39 0.51 -24%
Appendix C-2: Compliance Results for the 265 Phase I NOx

 Affected Units in 1999

1999

ST Plant Name Operating Utility

ORIS

Code Boiler Compliance Approach

Emission

Limit

Actual

Emission

Rate

AEL or 

Avg. Plan

Limit

Actual

Avg. Plan

Rate

1990

Emission

Rate

Change from

1990 to

1999

C-2, 10

WY Jim Bridger Pacificorp 8066 BW73 Standard Limitation 0.45 0.37 0.42 -12%

WY Wyodak Pacificorp 6101 BW91 Standard Limitation 0.50 0.29 0.37 -22%
Appendix C-3:Compliance Results for the 274 Early Election Units in 1999

1 New Source Performance Standard subpart

C-3, 1

ST Plant Name Operating Utility

ORIS

Code Boiler NSPS1

Emission

Limit

Actual 1999

Emission Rate

1990

Emission Rate

Change from 

1990 to 1999

AL Charles R Lowman Alabama Electric Coop 56 2 D 0.50 0.48 0.62 -23%

AL Charles R Lowman Alabama Electric Coop 56 3 D 0.50 0.49 0.66 -26%

AR Flint Creek Southwestern Electric Power 6138 1 D 0.50 0.30 0.31 -3%

AR Independence Entergy Arkansas, Inc. 6641 1 D 0.45 0.23 0.34 -33%

AR Independence Entergy Arkansas, Inc. 6641 2 D 0.45 0.29 0.35 -16%

AR White Bluff Entergy Arkansas, Inc. 6009 1 D 0.45 0.35 0.29 21%

AR White Bluff Arkansas Power & Light Co 6009 2 D 0.45 0.34 0.34 1%

AZ Apache Station Arizona Electric Pwr Coop 160 2 D 0.50 0.43 0.58 -26%

AZ Apache Station Arizona Electric Pwr Coop 160 3 D 0.50 0.40 0.58 -31%

AZ Cholla Arizona Public Service 113 1 0.45 0.43 0.46 -7%

AZ Cholla Arizona Public Service 113 2 D 0.45 0.35 0.42 -16%

AZ Cholla Arizona Public Service 113 3 D 0.45 0.32 0.36 -11%

AZ Cholla Arizona Public Service 113 4 D 0.45 0.31 0.38 -18%

AZ Coronado Salt River Project 6177 U1B D 0.50 0.44 0.51 -14%

AZ Coronado Salt River Project 6177 U2B D 0.50 0.42 0.51 -18%

AZ Navajo Salt River Project 4941 1 0.45 0.39 0.41 -5%

AZ Navajo Salt River Project 4941 2 0.45 0.33 0.41 -20%

AZ Navajo Salt River Project 4941 3 0.45 0.37 0.37 -1%

AZ Springerville Tucson Electric Power Co 8223 1 D 0.45 0.37 0.34 9%

AZ Springerville Tucson Electric Power Co 8223 2 D 0.45 0.39 0.33 17%

CO Cherokee Public Service Co of CO 469 3 0.50 0.46 0.73 -37%

CO Cherokee Public Service Co of CO 469 4 0.45 0.35 0.51 -31%

CO Comanche Public Service Co of CO 470 1 0.45 0.30 0.24 27%

CO Comanche Public Service Co of CO 470 2 D 0.50 0.28 0.31 -10%

CO Craig Tri-State G&T Association 6021 C1 D 0.50 0.31 0.39 -21%

CO Craig Tri-State G&T Association 6021 C2 D 0.50 0.42 0.40 5%

CO Craig Tri-State G&T Association 6021 C3 Da 0.50 0.34 0.28 21%

CO Pawnee Public Service Co of CO 6248 1 D 0.50 0.23 0.62 -63%

CO Rawhide Platte River Power Authority 6761 101 Da 0.45 0.35 0.43 -19%

CO Ray D Nixon Colorado Springs Utilities 8219 1 D 0.50 0.42 0.54 -23%

CO Valmont Public Service Co of CO 477 5 0.45 0.26 0.17 53%
Appendix C-3:Compliance Results for the 274 Early Election Units in 1999

ST Plant Name Operating Utility

ORIS

Code Boiler NSPS1

Emission

Limit

Actual 1999

Emission Rate

1990

Emission Rate

Change from 

1990 to 1999

1 New Source Performance Standard subpart

C-3, 2

CT Bridgeport Harbor United Illuminating Co 568 BHB3 0.45 0.18 0.56 -68%

FL C D McIntosh Jr City of Lakeland 676 3 D 0.50 0.47 0.46 2%

FL Crystal River Florida Power Corporation 628 2 0.45 0.43 0.38 14%

FL Crystal River Florida Power Corporation 628 4 D 0.50 0.49 0.50 -3%

FL Crystal River Florida Power Corporation 628 5 D 0.50 0.48 0.47 2%

FL Deerhaven Gainesville Regional Util 663 B2 D 0.50 0.48 0.53 -10%

FL Seminole Seminole Electric Coop Inc 136 1 Da 0.50 0.45 0.43 5%

FL Seminole Seminole Electric Coop Inc 136 2 Da 0.50 0.42 0.36 17%

FL St Johns River Power Jacksonville Electric Auth 207 1 Da 0.50 0.49 0.50 -3%

FL St Johns River Power Jacksonville Electric Auth 207 2 Da 0.50 0.49 0.59 -18%

GA Scherer Georgia Power Co 6257 4 D 0.45 0.27 0.21 30%

IA Ames City of Ames 1122 7 0.45 0.35 0.60 -41%

IA Ames City of Ames 1122 8 D 0.50 0.41 0.55 -25%

IA Council Bluffs Midamerican Energy Company 1082 1 0.50 0.40 0.56 -29%

IA Council Bluffs Midamerican Energy Company 1082 2 0.45 0.37 0.33 11%

IA Council Bluffs Midamerican Energy Company 1082 3 D 0.50 0.46 0.37 23%

IA George Neal North Midamerican Energy Company 1091 2 0.50 0.43 1.06 -59%

IA George Neal North Midamerican Energy Company 1091 3 D 0.50 0.48 0.39 22%

IA George Neal South Midamerican Energy Company 7343 4 D 0.50 0.37 0.64 -42%

IA Lansing Interstate Power Co 1047 4 D 0.50 0.43 0.50 -13%

IA Louisa Midamerican Energy Company 6664 101 D 0.50 0.26 0.25 2%

IA Ottumwa IES Utilities, Inc. 6254 1 D 0.45 0.33 0.69 -52%

IL Crawford Midwest Generation Eme, LLC 867 7 0.45 0.32 0.33 -4%

IL Crawford Midwest Generation Eme, LLC 867 8 0.45 0.37 0.48 -23%

IL Dallman City of Springfield, IL 963 33 D 0.45 0.40 0.55 -27%

IL Fisk Midwest Generation Eme, LLC 886 19 0.45 0.35 0.39 -10%

IL Waukegan Midwest Generation Eme, LLC 883 7 0.45 0.31 0.26 19%

IL Waukegan Midwest Generation Eme, LLC 883 8 0.45 0.33 0.41 -19%

IL Will County Midwest Generation Eme, LLC 884 3 0.45 0.43 0.39 11%

IL Will County Midwest Generation Eme, LLC 884 4 0.45 0.31 0.31 2%

IN A B Brown Southern Indiana Gas & Elec 6137 1 D 0.50 0.42 0.61 -31%
Appendix C-3:Compliance Results for the 274 Early Election Units in 1999

ST Plant Name Operating Utility

ORIS

Code Boiler NSPS1

Emission

Limit

Actual 1999

Emission Rate

1990

Emission Rate

Change from 

1990 to 1999

1 New Source Performance Standard subpart

C-3, 3

IN A B Brown Southern Indiana Gas & Elec 6137 2 Da 0.50 0.47 0.39 19%

IN Dean H Mitchell Northern Indiana Pub Serv 996 4 0.45 0.29 0.43 -33%

IN Dean H Mitchell Northern Indiana Pub Serv 996 5 0.45 0.29 0.43 -33%

IN Dean H Mitchell Northern Indiana Pub Serv 996 6 0.45 0.29 0.58 -50%

IN Dean H Mitchell Northern Indiana Pub Serv 996 11 0.50 0.29 0.58 -50%

IN Merom Hoosier Energy 6213 1SG1 D 0.50 0.40 0.23 74%

IN Merom Hoosier Energy 6213 2SG1 D 0.50 0.37 0.63 -41%

IN R M Schahfer Northern Indiana Pub Serv 6085 15 D 0.50 0.24 0.42 -43%

IN R M Schahfer Northern Indiana Pub Serv 6085 17 Da 0.45 0.37 0.46 -19%

IN R M Schahfer Northern Indiana Pub Serv 6085 18 Da 0.45 0.35 0.44 -20%

IN Rockport Indiana Michigan Power Co 6166 MB1 D 0.50 0.39 0.32 22%

IN Rockport Indiana Michigan Power Co 6166 MB2 D 0.50 0.39 0.32 22%

IN State Line State Line Energy, LLC 981 3 0.45 0.28 0.32 -13%

IN Whitewater Valley City of Richmond, IN 1040 1 0.50 0.43 0.71 -39%

IN Whitewater Valley City of Richmond, IN 1040 2 0.45 0.43 0.71 -39%

KS Nearman Creek Board of Public Util, KS City 6064 N1 D 0.50 0.44 0.46 -4%

KS Riverton Empire District Electric 1239 39 0.50 0.43 0.83 -48%

KS Riverton Empire District Electric 1239 40 0.45 0.43 0.55 -22%

KY Cane Run Louisville Gas & Electric 1363 4 0.50 0.45 0.84 -46%

KY Cane Run Louisville Gas & Electric 1363 5 0.50 0.49 1.15 -57%

KY Cane Run Louisville Gas & Electric 1363 6 0.45 0.36 1.02 -65%

KY Dale East Kentucky Power Coop Inc 1385 3 0.50 0.41 0.73 -44%

KY Dale East Kentucky Power Coop Inc 1385 4 0.50 0.41 0.73 -44%

KY H L Spurlock East Kentucky Power Coop Inc 6041 2 D 0.45 0.41 0.47 -13%

KY Mill Creek Louisville Gas & Electric 1364 1 0.45 0.39 0.76 -49%

KY Mill Creek Louisville Gas & Electric 1364 2 0.45 0.34 0.79 -57%

KY Mill Creek Louisville Gas & Electric 1364 3 D 0.50 0.49 0.62 -21%

KY Mill Creek Louisville Gas & Electric 1364 4 D 0.50 0.47 0.57 -18%

KY Trimble County Louisville Gas & Electric 6071 1 D 0.45 0.39 0.62 -37%

LA Big Cajun 2 Cajun Electric Power 6055 2B1 D 0.50 0.34 0.28 20%

LA Big Cajun 2 Cajun Electric Power 6055 2B2 D 0.50 0.32 0.25 28%
Appendix C-3:Compliance Results for the 274 Early Election Units in 1999

ST Plant Name Operating Utility

ORIS

Code Boiler NSPS1

Emission

Limit

Actual 1999

Emission Rate

1990

Emission Rate

Change from 

1990 to 1999

1 New Source Performance Standard subpart

C-3, 4

LA Big Cajun 2 Cajun Electric Power 6055 2B3 D 0.50 0.29 0.24 19%

LA Dolet Hills Central Louisiana Elec Co 51 1 D 0.50 0.44 0.62 -29%

LA R S Nelson Entergy Gulf States, Inc. 1393 6 D 0.45 0.41 0.20 107%

LA Rodemacher Central Louisiana Elec Co 6190 2 D 0.50 0.42 0.38 10%

MI B C Cobb Consumers Energy Co 1695 4 0.45 0.36 0.38 -6%

MI B C Cobb Consumers Energy Co 1695 5 0.45 0.38 0.36 6%

MI J B Sims City of Grand Haven 1825 3 Da 0.50 0.41 0.51 -19%

MI J C Weadock Consumers Energy Co 1720 7 0.45 0.35 0.44 -21%

MI J C Weadock Consumers Energy Co 1720 8 0.45 0.34 0.44 -23%

MI J R Whiting Consumers Energy Co 1723 1 0.50 0.31 0.82 -62%

MI J R Whiting Consumers Energy Co 1723 3 0.50 0.38 1.04 -63%

MI Presque Isle Wisconsin Electric Power Co. 1769 7 D 0.50 0.48 0.49 -2%

MI Presque Isle Wisconsin Electric Power Co. 1769 8 D 0.50 0.46 0.53 -12%

MI Presque Isle Wisconsin Electric Power Co. 1769 9 D 0.50 0.47 0.66 -28%

MN Clay Boswell Minnesota Power & Light Co 1893 3 0.45 0.35 0.42 -16%

MN Hoot Lake Otter Tail Power Co 1943 2 0.45 0.39 0.58 -32%

MO Sikeston Sikeston Board of Mun Util 6768 1 D 0.50 0.24 0.51 -53%

M T Colstrip PP&L Montana, LLC 6076 1 D 0.45 0.41 0.42 -2%

M T Colstrip PP&L Montana, LLC 6076 2 D 0.45 0.37 0.43 -14%

M T Colstrip PP&L Montana, LLC 6076 3 Da 0.45 0.43 0.34 27%

M T Colstrip PP&L Montana, LLC 6076 4 Da 0.45 0.45 0.35 29%

M T Lewis & Clark PP&L Montana, LLC 6089 B1 0.45 0.38 0.57 -33%

NC Buck Duke Energy Corporation 2720 5 0.45 0.42 0.59 -29%

NC Buck Duke Energy Corporation 2720 6 0.45 0.43 0.54 -21%

NC Buck Duke Energy Corporation 2720 7 0.45 0.45 0.57 -21%

NC Buck Duke Energy Corporation 2720 8 0.45 0.42 0.45 -6%

NC Buck Duke Energy Corporation 2720 9 0.45 0.43 0.51 -15%

NC Cliffside Duke Energy Corporation 2721 1 0.45 0.41 Not Oper.

NC Cliffside Duke Energy Corporation 2721 2 0.45 0.39 Not Oper.

NC Cliffside Duke Energy Corporation 2721 3 0.45 0.39 Not Oper.

NC Cliffside Duke Energy Corporation 2721 4 0.45 0.42 Not Oper.
Appendix C-3:Compliance Results for the 274 Early Election Units in 1999

ST Plant Name Operating Utility

ORIS

Code Boiler NSPS1

Emission

Limit

Actual 1999

Emission Rate

1990

Emission Rate

Change from 

1990 to 1999

1 New Source Performance Standard subpart

C-3, 5

NC Cliffside Duke Energy Corporation 2721 5 0.45 0.44 0.51 -13%

NC Dan River Duke Energy Corporation 2723 1 0.45 0.41 0.52 -20%

NC Dan River Duke Energy Corporation 2723 2 0.45 0.42 0.55 -23%

NC Dan River Duke Energy Corporation 2723 3 0.45 0.45 0.56 -20%

NC G G Allen Duke Energy Corporation 2718 1 0.45 0.44 0.65 -32%

NC G G Allen Duke Energy Corporation 2718 2 0.45 0.44 0.61 -28%

NC G G Allen Duke Energy Corporation 2718 3 0.45 0.45 0.64 -30%

NC G G Allen Duke Energy Corporation 2718 4 0.45 0.41 0.68 -40%

NC G G Allen Duke Energy Corporation 2718 5 0.45 0.45 0.68 -34%

NC Marshall Duke Energy Corporation 2727 1 0.45 0.43 0.48 -11%

NC Marshall Duke Energy Corporation 2727 2 0.45 0.43 0.61 -29%

NC Marshall Duke Energy Corporation 2727 3 0.45 0.43 0.52 -17%

NC Marshall Duke Energy Corporation 2727 4 0.45 0.45 0.70 -36%

NC Riverbend Duke Energy Corporation 2732 7 0.45 0.39 0.58 -33%

NC Riverbend Duke Energy Corporation 2732 8 0.45 0.36 0.64 -44%

NC Riverbend Duke Energy Corporation 2732 9 0.45 0.39 Not Oper.

NC Riverbend Duke Energy Corporation 2732 10 0.45 0.41 Not Oper.

ND Antelope Valley Basin Electric Power 6469 B1 D 0.45 0.38 0.43 -11%

ND Antelope Valley Basin Electric Power 6469 B2 D 0.45 0.32 0.27 17%

ND Leland Olds Basin Electric Power 2817 1 0.50 0.26 0.74 -65%

ND Stanton United Power Assn 2824 10 Da 0.45 0.40 0.47 -15%

NE Gerald Gentleman Sta Nebraska Public Power Dist 6077 1 D 0.50 0.45 0.40 13%

NE Gerald Gentleman Sta Nebraska Public Power Dist 6077 2 D 0.50 0.32 0.35 -8%

NE Gerald Whelan Energy City of Hastings 60 1 D 0.45 0.29 0.30 -4%

NE Nebraska City Omaha Public Power Dist 6096 1 D 0.50 0.42 0.48 -12%

NE North Omaha Omaha Public Power Dist 2291 4 0.45 0.34 0.38 -10%

NE Platte City of Grand Island 59 1 D 0.45 0.41 0.48 -14%

NM Escalante Plains Electric Gen & Trans 87 1 Da 0.45 0.41 0.35 18%

NV Mohave Southern California Edison 2341 1 0.45 0.40 0.38 4%

NV Mohave Southern California Edison 2341 2 0.45 0.40 0.46 -13%

NV North Valmy Sierra Pacific Power Co 8224 1 D 0.50 0.36 0.51 -30%
Appendix C-3:Compliance Results for the 274 Early Election Units in 1999

ST Plant Name Operating Utility

ORIS

Code Boiler NSPS1

Emission

Limit

Actual 1999

Emission Rate

1990

Emission Rate

Change from 

1990 to 1999

1 New Source Performance Standard subpart

C-3, 6

NV North Valmy Sierra Pacific Power Co 8224 2 Da 0.50 0.35 0.40 -13%

NV Reid Gardner Nevada Power Company 2324 4 Da 0.50 0.30 0.38 -20%

NY C R Huntley Huntley Power LLC 2549 67 0.45 0.34 0.64 -47%

NY C R Huntley Huntley Power LLC 2549 68 0.45 0.34 0.64 -47%

NY Dunkirk Niagara Mohawk Power Corp 2554 1 0.45 0.36 0.48 -25%

NY Dunkirk Niagara Mohawk Power Corp 2554 2 0.45 0.36 0.48 -25%

NY Kintigh NGE Generation, Inc. 6082 1 Da 0.50 0.36 0.62 -42%

NY S A Carlson City of Jamestown 2682 9 0.50 0.43 0.90 -52%

NY S A Carlson City of Jamestown 2682 10 0.50 0.45 1.05 -57%

NY S A Carlson City of Jamestown 2682 11 0.50 0.45 0.83 -46%

NY S A Carlson City of Jamestown 2682 12 0.50 0.43 0.90 -52%

OH Conesville Columbus Southern Power 2840 5 D 0.45 0.40 0.44 -8%

OH Conesville Columbus Southern Power 2840 6 D 0.45 0.40 0.44 -8%

OH W H Zimmer Cincinnati Gas & Electric Co 6019 1 Da 0.50 0.47 Not Oper.

OK Muskogee Oklahoma Gas & Electric Co 2952 4 D 0.45 0.31 0.44 -29%

OK Muskogee Oklahoma Gas & Electric Co 2952 5 D 0.45 0.34 0.41 -17%

OK Muskogee Oklahoma Gas & Electric Co 2952 6 D 0.45 0.40 0.44 -8%

OK Northeastern Central and Southwest Services 2963 3313 D 0.45 0.37 0.53 -30%

OK Northeastern Central and Southwest Services 2963 3314 D 0.45 0.37 0.53 -30%

OK Sooner Oklahoma Gas & Electric Co 6095 1 D 0.45 0.41 0.33 23%

OK Sooner Oklahoma Gas & Electric Co 6095 2 D 0.45 0.39 0.42 -7%

OR Boardman Portland General Electric 6106 1SG D 0.50 0.41 0.40 2%

PA Bruce Mansfield Pennsylvania Power Co. 6094 3 D 0.50 0.36 0.57 -37%

PA Cromby Peco Energy Company 3159 1 0.50 0.34 0.60 -43%

PA Eddystone Peco Energy Company 3161 1 0.45 0.28 0.42 -34%

PA Eddystone Peco Energy Company 3161 2 0.45 0.24 0.50 -52%

PA Homer City EME Homer City Generation, L.P. 3122 1 0.50 0.42 1.09 -62%

PA Homer City EME Homer City Generation, L.P. 3122 2 0.50 0.41 1.04 -61%

PA Homer City EME Homer City Generation, L.P. 3122 3 D 0.50 0.39 0.62 -37%

PA Keystone Sithe Northeast Management Company 3136 1 0.45 0.34 0.79 -57%

PA Keystone Sithe Northeast Management Company 3136 2 0.45 0.34 0.79 -57%
Appendix C-3:Compliance Results for the 274 Early Election Units in 1999

ST Plant Name Operating Utility

ORIS

Code Boiler NSPS1

Emission

Limit

Actual 1999

Emission Rate

1990

Emission Rate

Change from 

1990 to 1999

1 New Source Performance Standard subpart

C-3, 7

PA Montour PP&L 3149 1 0.45 0.39 0.95 -59%

PA Montour PP&L 3149 2 0.45 0.38 0.46 -18%

PA New Castle Pennsylvania Power Co. 3138 3 0.50 0.38 0.63 -39%

PA New Castle Pennsylvania Power Co. 3138 4 0.50 0.36 0.57 -37%

PA New Castle Pennsylvania Power Co. 3138 5 0.50 0.45 0.73 -38%

PA Titus Sithe Northeast Management Company 3115 1 0.45 0.33 0.73 -55%

PA Titus Sithe Northeast Management Company 3115 2 0.45 0.34 0.68 -50%

PA Titus Sithe Northeast Management Company 3115 3 0.45 0.31 0.77 -60%

SC Cross South Carolina Pub Serv 130 1 Da 0.50 0.30 Not Oper.

SC Cross South Carolina Pub Serv 130 2 Da 0.45 0.36 0.46 -22%

SC W S Lee Duke Energy Corporation 3264 1 0.45 0.44 0.64 -31%

SC W S Lee Duke Energy Corporation 3264 2 0.45 0.44 0.61 -28%

SC W S Lee Duke Energy Corporation 3264 3 0.45 0.44 0.50 -13%

TN John Sevier TVA 3405 1 0.45 0.43 0.62 -31%

TN John Sevier TVA 3405 2 0.45 0.43 0.62 -31%

TN John Sevier TVA 3405 3 0.45 0.41 0.64 -36%

TN John Sevier TVA 3405 4 0.45 0.41 0.64 -36%

TX Big Brown Texas Utilities Electric Co 3497 1 0.45 0.33 0.40 -16%

TX Big Brown Texas Utilities Electric Co 3497 2 0.45 0.34 0.34 -1%

TX Coleto Creek Central Power & Light Co 6178 1 D 0.45 0.24 0.38 -37%

TX Gibbons Creek Texas Municipal Power Agency 6136 1 D 0.45 0.33 0.47 -30%

TX Harrington Station Southwestern Public Service 6193 061B D 0.45 0.31 0.27 17%

TX Harrington Station Southwestern Public Service 6193 062B D 0.45 0.34 0.36 -5%

TX Harrington Station Southwestern Public Service 6193 063B D 0.45 0.26 0.36 -27%

TX J K Spruce City of San Antonio 7097 **1 Da 0.45 0.30 Not Oper.

TX J T Deely City of San Antonio 6181 1 D 0.45 0.29 0.31 -5%

TX J T Deely City of San Antonio 6181 2 D 0.45 0.29 0.31 -5%

TX Limestone Houston Lighting & Power 298 LIM1 Da 0.45 0.43 0.50 -13%

TX Limestone Houston Lighting & Power 298 LIM2 Da 0.45 0.43 0.48 -11%

TX Martin Lake Texas Utilities Electric Co 6146 1 D 0.45 0.30 0.36 -16%

TX Martin Lake Texas Utilities Electric Co 6146 2 D 0.45 0.26 0.35 -25%
Appendix C-3:Compliance Results for the 274 Early Election Units in 1999

ST Plant Name Operating Utility

ORIS

Code Boiler NSPS1

Emission

Limit

Actual 1999

Emission Rate

1990

Emission Rate

Change from 

1990 to 1999

1 New Source Performance Standard subpart

C-3, 8

TX Martin Lake Texas Utilities Electric Co 6146 3 D 0.45 0.32 0.42 -24%

TX Monticello Texas Utilities Electric Co 6147 1 0.45 0.30 0.31 -2%

TX Monticello Texas Utilities Electric Co 6147 2 0.45 0.29 0.40 -28%

TX Monticello Texas Utilities Electric Co 6147 3 D 0.50 0.22 0.21 6%

TX Oklaunion West Texas Utilities Co 127 1 Da 0.50 0.33 0.54 -39%

TX Pirkey Southwestern Electric Power 7902 1 D 0.50 0.36 0.34 5%

TX Sam Seymour Lower Colorado River Auth 6179 1 D 0.45 0.32 0.34 -6%

TX Sam Seymour Lower Colorado River Auth 6179 2 D 0.45 0.29 0.29 0%

TX Sam Seymour Lower Colorado River Auth 6179 3 Da 0.45 0.32 0.25 31%

TX San Miguel San Miguel Electric Coop 6183 SM-1 D 0.50 0.35 0.41 -15%

TX Sandow Texas Utilities Electric Co 6648 4 D 0.45 0.34 0.43 -21%

TX Tolk Station Southwestern Public Service 6194 171B D 0.45 0.30 0.38 -22%

TX Tolk Station Southwestern Public Service 6194 172B D 0.45 0.32 0.24 35%

TX W A Parish Houston Lighting & Power 3470 WAP5 D 0.50 0.34 0.47 -28%

TX W A Parish Houston Lighting & Power 3470 WAP6 D 0.50 0.34 0.53 -35%

TX W A Parish Houston Lighting & Power 3470 WAP7 D 0.45 0.16 0.35 -54%

TX W A Parish Houston Lighting & Power 3470 WAP8 Da 0.45 0.32 0.31 2%

TX Welsh Southwestern Electric Power 6139 1 D 0.50 0.32 0.27 20%

TX Welsh Southwestern Electric Power 6139 2 D 0.50 0.36 0.36 1%

TX Welsh Southwestern Electric Power 6139 3 D 0.50 0.40 0.37 8%

UT Bonanza Deseret Generation & Tran 7790 1-1 Da 0.50 0.31 0.42 -27%

UT Carbon Pacificorp 3644 1 0.45 0.42 0.50 -17%

UT Carbon Pacificorp 3644 2 0.45 0.42 0.58 -27%

UT Hunter (Emery) Pacificorp 6165 1 D 0.45 0.40 0.50 -19%

UT Hunter (Emery) Pacificorp 6165 2 D 0.45 0.36 0.55 -35%

UT Huntington Pacificorp 8069 1 D 0.45 0.41 0.52 -21%

UT Intermountain Intermountain Power Agency 6481 1SGA Da 0.50 0.40 0.45 -12%

UT Intermountain Intermountain Power Agency 6481 2SGA Da 0.50 0.38 0.38 1%

VA Chesapeake VEPCO 3803 1 0.45 0.43 0.42 2%

VA Chesapeake VEPCO 3803 2 0.45 0.42 0.48 -13%

VA Chesapeake VEPCO 3803 4 0.45 0.44 0.54 -19%
Appendix C-3:Compliance Results for the 274 Early Election Units in 1999

ST Plant Name Operating Utility

ORIS

Code Boiler NSPS1

Emission

Limit

Actual 1999

Emission Rate

1990

Emission Rate

Change from 

1990 to 1999

1 New Source Performance Standard subpart

C-3, 9

VA Chesterfield VEPCO 3797 3 0.45 0.42 0.52 -19%

VA Chesterfield VEPCO 3797 4 0.45 0.42 0.49 -14%

VA Glen Lyn Appalachian Power Co 3776 51 0.45 0.41 0.46 -11%

VA Glen Lyn Appalachian Power Co 3776 52 0.45 0.41 Not Oper.

VA Possum Point VEPCO 3804 3 0.45 0.45 0.60 -25%

VA Potomac River PEPCO 3788 1 0.45 0.42 0.51 -18%

VA Potomac River PEPCO 3788 2 0.45 0.37 0.44 -16%

VA Potomac River PEPCO 3788 3 0.45 0.44 0.64 -31%

VA Potomac River PEPCO 3788 4 0.45 0.43 0.46 -6%

VA Potomac River PEPCO 3788 5 0.45 0.43 0.72 -40%

VA Yorktown VEPCO 3809 1 0.45 0.44 0.57 -23%

VA Yorktown VEPCO 3809 2 0.45 0.43 0.57 -25%

WA Centralia Pacificorp 3845 BW21 0.45 0.40 0.40 -1%

WA Centralia Pacificorp 3845 BW22 0.45 0.43 0.45 -5%

WI Blount Street Madison Gas & Electric Co 3992 8 0.50 0.35 0.71 -50%

WI Blount Street Madison Gas & Electric Co 3992 9 0.50 0.44 0.61 -28%

WI Columbia Wisconsin Power & Light 8023 1 0.45 0.37 0.46 -20%

WI Columbia Wisconsin Power & Light 8023 2 D 0.45 0.39 0.49 -20%

WI Edgewater Wisconsin Power & Light 4050 5 D 0.50 0.23 0.21 10%

WV Mountaineer (1301) Appalachian Power Co 6264 1 D 0.50 0.50 0.47 6%

WY Dave Johnston Pacificorp 4158 BW41 0.50 0.42 0.48 -13%

WY Dave Johnston Pacificorp 4158 BW42 0.50 0.40 0.54 -26%

WY Jim Bridger Pacificorp 8066 BW74 D 0.45 0.39 0.41 -4%

WY Laramie River Basin Electric Power 6204 1 D 0.50 0.24 0.35 -31%

WY Laramie River Basin Electric Power 6204 2 D 0.50 0.26 0.32 -19%

WY Laramie River Basin Electric Power 6204 3 D 0.50 0.24 0.42 -43%