United States

Environmental Protection

Agency

Office of Air and Radiation

Acid Rain Division (6204J)

EPA-430-R-99-010

July 1999

1998 Compliance Report

Acid Rain Program

 

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 being implemented in two phases: Phase I began in 1995 for SO2 and 1996 for

NOx, and will last until 1999; Phase II for both pollutants begins in 2000 and is expected to involve over

2,000 units. In 1998, there were 408 units affected by the SO2 provisions of the Acid Rain Program, 235

of which were also affected for NOx, and an additional 305 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 affected utilities. Flexibility is introduced to this command and control measure, however,

through compliance options such as emissions averaging, whereby a utility can meet the standard

emission limitations by averaging the emissions rates of two or more boilers. This allows utilities to

over-control at units where it is technically easier to control emissions, thereby achieving emissions

reductions at a lower cost. Additionally, beginning in 1997, certain Phase II units could elect to become

affected for NOx early. 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 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............................................................14

Phase II Early Election Compliance Results.....................................15

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

Conclusion....................................................................................................18

Appendix A: Phase I Affected And Early Election Units in 1998

Appendix B-1: Table 1 Units Designating Substitution and Compensating Units - 1998

Appendix B-2: List of Phase I Extension Units and 1998 Deductions for Exceeding 1998 Projected

Emissions Limitations

Appendix B-3: Emissions and Utilization of Phase I Units, 1997 and 1998

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

Appendix C-1: List of Averaging Plans and Results in 1998

Appendix C-2: Compliance Results for the 265 Phase I NOX Affected Units in 1998

Appendix C-3: Compliance Results for the 275 Early Election Units in 1998
1998 Compliance Report Page 1

TO THE READER:

The Acid Rain Program 1998 Compliance Report summarizes compliance results that, for the fourth

consecutive year since the Acid Rain Program began, show100 percent compliance with both sulfur

dioxide (SO2) and nitrogen oxide (NOx) requirements. Over the past year there were also a number of

significant Program improvements.

First, the allowance transfer deadline, the date by which a unit’s allowance account is required to hold

enough allowances to account for the previous year’s SO2 emissions, was changed from January 30th

to March 1 (Feb. 29 for leap years). This allows affected facilities additional time to determine their

previous year’s SO2 emissions and to ensure the availability of sufficient allowances to account for

those emissions. 

Second, in order to expedite transfers and reduce transaction costs the Acid Rain Program revised its

regulations to allow an authorized account representative to specify allowance accounts to which

allowances can be transferred without requiring the buyer’s signature on each individual allowance

transfer form.

Third, to avoid the imposition of extremely large excess emissions penalties for minor, inadvertent

accounting errors, the Acid Rain Program now allows for the transfer of unused allowances from unit

accounts at the same source to account for the emissions at a unit that lacks sufficient allowances. This

leads to a smaller penalty, more in line with the violation, while still ensuring the environmental

objective.

Fourth, the monitoring rule have was revised to enhance flexibility for industry by reducing monitoring

requirements for certain units with low mass emissions, creating new monitoring options for some units,

reducing certain quality assurance requirements, and increasing fuel sampling flexibility for certain units. 

The sum of these changes make the rule more efficient and less burdensome for the regulated

community, EPA, and the States.

Finally, the Acid Rain Program permits regulation was revised to make new and retired unit exemptions

easier for sources to comply with and simpler for the States to administer. These changes provide

States with additional flexibility in meeting public notice requirements in the issuance of Acid Rain

permits and allow for “direct/final” issuance of draft and proposed Acid Rain permits. The Program

also eased public notice requirements related to the appointment of, and changes to, the designated

representative and alternate designated representative.

We will continue to look for ways to improve the Acid Rain Program as we prepare for the year 2000

and the beginning of Phase II, and will work with all interested persons in ensuring that the Acid Rain

Program meets its environmental goals with minimum cost and burden for affected sources and States.

Brian J. McLean, Director

Acid Rain Program
1998 Compliance Report Page 2

SUMMARY

100 Percent Compliance with both SO2 and NOx Requirements in 1998

All 713 boilers and combustion turbines (referred to as “units”) affected by the SO2 and NOx

regulations of the Acid Rain Program in 1998 successfully met their emissions compliance obligations.

Ç All 408 units subject to SO2 requirements in 1998 held sufficient allowances to cover their

emissions. Of the 5,300,861 allowances deducted from compliance accounts almost all (5,298,498

or 99.96 percent) were for emissions, but other deductions were also made as required by the Acid

Rain Program regulations. 

Ç All 540 units subject to the NOx requirements in 1998 demonstrated compliance with applicable

annual emission limitations. Of these 540 units, 235 were also subject to SO2 requirements, while

305 units were affected only for NOx (30 Phase I units and 275 Phase II “early election” units). 

1998 SO2 Emissions of Phase I Units were 24 Percent Below Allowable Level

SO2 emissions in 1998 were 1.7 million tons (or 24 percent) below the 7 million ton allowable level as

determined by 1998 allowance allocations. Since an additional 7.9 million allowances were carried

over, or banked, from 1997, the overall number of allowances available in 1998 was 14.9 million, of

which affected units consumed only about 35 percent. Actual emissions for the 408 units participating

in 1998 were 5.3 million tons, down 180,000 tons from emissions of the 423 units affected in 1997. 

1998 Phase I Unit NOx Emission Rates 41 Percent Below 1990; NOx Tons 29 Percent

Lower Than in 1990

Emission rates for the 265 Phase I utility units dropped by 41 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 0.41

lbs/mmBtu; this rate is 16 percent below the compliance rate of 0.49 lbs/mmBtu for these units. NOx

emission levels for these units were 390,254 tons (or 29 percent) below 1990 levels.

1998 NOX Emission Rates of Early Election Units Even Lower Than Rates for Phase I

Units

For the 275 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 0.38 lbs/mmBtu in 1998, a 17 percent decrease and 19 percent

below the compliance rate of 0.47 lbs/mmBtu for these units. Therefore, while utilization of these units

increased by 28 percent between 1990 and 1998, NOx tons increased by only 8 percent.
1998 Compliance Report Page 3

Monitoring Performance Excellent Once Again

For the fourth 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, 3.0 percent; and NOx

monitors, 3.1 percent. 

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

respectively, while NOx monitors achieved a median reliability of 99.2 percent.

SO2 Market Active; Volume of Allowances Transferred Between Distinct Entities in 1998

Continues to Increase 

Activity in the allowance market continued to increase in 1998. The volume of allowances transferred

between unrelated parties in economically significant trades increased from 7.9 million in 1997 to 9.5

million in 1998.
1998 Compliance Report Page 4

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 1997, 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 Variable

Opt-in 0 7 7 10 Variable

TOTAL 445 431 423 408 Variable

NOx Table 1 NA 144 170 171 171

Substitution NA 95 95 94 94

Early-Election NA NA 272 275 Variable

TOTAL NA 239 537 540 Variable

SO2 PROGRAM

408 Units Underwent Annual Reconciliation for SO2 in 1998

There were 398 affected utility units and 10 opt-in units that underwent annual reconciliation in 1998 to

determine whether sufficient allowances were held to cover emissions. These 408 units are listed in

Appendix A and include 263 utility units specifically required to participate during Phase I, 135 utility

units not initially required to participate until Phase II, but electing to participate early as part of
1998 Compliance Report Page 5

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 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.

multi-unit compliance plans1, and 10 other units that elected to join as part of the Opt-in Program2. 

There were 8 fewer units undergoing annual reconciliation than in 1997. 

1998 SO2 Emissions Target was 6.97 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 1998, the emissions target established by the program for the 408 participating units was

6.97 million tons. However, the total allowable SO2 emission level in 1998 was actually 14.93 million

tons, consisting of the 6.97 million 1998 allowances granted through the program and an additional 7.96

million allowances carried over, or banked, from 1997.

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 1998 were also made available through the allowance auctions, held annually

since 1993. Other allowances issued in 1998 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 1998 SO2 Allowable Emissions Level by 24 Percent

The Phase I units affected in 1998 emitted at a level approximately 24 percent below 1998 allocations,

as shown in Exhibit 3. This percentage is about the same as in 1997, with both emissions and 
1998 Compliance Report Page 6

allocations registering slight decreases. Appendix B-3 reports the 1998 emission and utilization levels

for all Phase I affected units, as well as a comparison to these levels in 1997.

Relative to 1997, the 263 Table 1 units decreased their emissions by about 110,000 tons, or more than

two percent in 1998, while increasing their utilization by just over one half of one percent. The 4.7

million tons emitted by these Table 1 units were still substantially below their 1998 allocation of 5.6

million allowable tons.

Exhibit 2

Origin of 1998 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 178,211 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 948,708 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

15,838 Allowances for Compensating Units are the initial allocation

granted to Phase II units which entered Phase I as compensating

units.

Opt-in Allowances 97,932 Opt-in Allowances are provided to units entering the program

voluntarily. 

Small Diesel Allowances 27,656 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 1998 ALLOCATION 6,969,165

BANKED 1997 ALLOWANCES 7,959,676 Banked Allowances are those held over from 1995 through 1997

which can be used for compliance in 1998 or any future year.

TOTAL 1998 ALLOWABLE 14,928,841

Substitution and compensating units in 1998 expended about the same percentage of their annual

allocation as in 1997. In 1998, these 135 units were responsible for emitting approximately 550,000

tons of SO2, about 58 percent of their 950,000 allocation. In 1997, 153 substitution and compensating
1998 Compliance Report Page 7

0

1

2

3

4

5

6

7

8

9

10 1995 1996

'95Allocation '95Emissions '96Allocation '96Emissions '97Allocation '97Emissions '98Allocation '98Emissions

Table 1 Units 5.55 4.45 5.55 4.77 5.55 4.77 5.55 4.66

S & C Units 1.33 0.85 1.18 0.63 1.04 0.62 0.95 0.55

Other 1.86 0.00 1.57 0.04 0.56 0.08 0.45 0.08

TOTALS 8.74 5.30 8.30 5.44 7.15 5.47 6.95 5.29

1997 1998

Allowances

Allowances

Allowances

Allowances

Emissions Emissions Emissions Emissions

Exhibit 3

Summary of SO2 Emissions versus Allocations

(Millions of Tons)

units emitted approximately 620,000 tons of SO2, or 60 percent of their 1.04 million allowable level. 

Three new opt-in units joined the program in 1998, raising the total allocation to 98,000 allowances and

the emissions level to 80,000 tons. The percentage of emissions to allowances allocated to opt-in units

in 1998 increased by approximately 1% compared to 1997.

Deducting Allowances for Compliance

The total number of allowances deducted in 1998 was 5,300,861 which represents approximately 76

percent of all 1998 allowances issued. Almost all (99.95 percent) of the deducted allowances were for

emissions. Exhibit 4 displays these allowance deductions, as well as the remaining bank of 1995

through 1998 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
1998 Compliance Report Page 8

3Qualifying technology is defined in 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 emission 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.

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

allowances equally among the units sharing the stack to cover total emissions reported by the stack. 

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 units4.

For 1998, all 19 control units demonstrated meeting the 90 percent reduction requirement and,

therefore, did not surrender any 1998 extension allowances. The 1998 tonnage emissions limitation,

though, was exceed by five control units and eleven transfer units and resulted in a surrender of a total

of 99,240 vintage 1999 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 408 units affected in 1998 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

408 sources to be in compliance in 1998 and significantly reduced the cost of achieving these emissions

reductions as compared to the cost of a technological mandate. 
1998 Compliance Report Page 9

Exhibit 4

 SO2 Allowance Reconciliation Summary

Total Allowances Held in Accounts as of 3/1/99 (1995 through 1998 Vintages)* 14,928,841

 Table 1 Unit Accounts 8,585,043

 Substitution & Compensating Unit Accounts 1,306,220

 Opt-in Accounts 83,962

 Other Accounts** 4,953,616

1998 Allowances Deducted for Emissions 5,298,498

 Table 1 Unit Accounts 4,664,898

 Substitution & Compensating Unit Accounts 553,349

 Opt-in Unit Accounts 80,251

1998 Allowances Deducted Under Special Phase I Provisions*** 2,363

 Table 1 Unit Accounts 65

 Substitution & Compensating Unit Accounts 1,755

 Opt-in Unit Accounts 543

Banked Allowances 9,627,980

 Table 1 Unit Accounts 3,920,080

 Substitution & Compensating Unit Accounts 751,116

 Opt-in Unit Accounts 3,168

 Other Accounts** 4,953,616

 * The number of allowances held in the Allowance Tracking System (ATS) accounts equals the number of 1998 allowances allocated

(see Exhibit 2) plus the number of 1997 banked allowances. March 1, 1999 represents the Allowance Transfer Deadline, the point in

time at which the 1998 Phase I affected unit accounts are frozen and after which no transfers of 1995 through 1998 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 1998 (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 was $207/ton at the 1999 allowance auction. Prices have

remained in the $205 to $215 range since January of 1999. 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. 
1998 Compliance Report Page 10

0

5 0

100

150

200

250

A ug9 4Feb -

9 5

A ug9 5Feb -

9 6

A ug9 6Feb -

9 7

A ug9 7Feb -

9 8

A ug9 8Feb -

9 9

M o n th -Year

Prices (Dollars)

F ie ldston Pub licat ions Can t or F itzgerald

Exhibit 5

SO2 Allowance Prices

Activity in the allowance market created under the Acid Rain Program remained strong in 1998, with

1,584 transactions moving about 13.5 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 transferred rose from 7.9 million

in 1997 to 9.5 million in 1998. A record 70 percent of annual activity consisted of allowances

transferred between economically distinct organizations, with more than half representing allowances

directly acquired by utilities. 

The most active market segment in 1998 in terms of allowance volume was composed of exchanges

between brokers/traders and utilities, accounting for 6.3 million allowances. The next most active was

the reallocation category, which covered an additional 3.2 million allowances. The category of transfers

between unrelated utilities increased to 1.9 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.
1998 Compliance Report Page 11

1994 1995 1996 1997 1998

Year

0

2

4

6

8

10

Millions

Volume of Allowances

0.9 M

1.9 M

4.4 M

7.9 M

9.5 M

Exhibit 6

Volume of SO2 Allowances in Economically Significant Transfers

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 and 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, Group 1, Phase II 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 for cell burner, cyclones, 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,
1998 Compliance Report Page 12

5 Compared with 1997, the universe of units remained the same, except that Mt. Storm Unit 2 (WV) was

added because its compliance extension expired and Gadsby Unit 3 (UT) was deleted because it was mistakenly

identified in previous years as a coal-fired utility unit.

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 1998

In 1998, 265 coal-fired utility units were subject to the Title IV Phase I emission limitations for NOx.

5

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 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 1998. As in

1996 and 1997, averaging was the most widely chosen compliance option. For 1998, there were 24

averaging plans involving 204 Phase I NOx units. See Appendix C-1: List of Averaging Plans and
1998 Compliance Report Page 13

6

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

Report.

Results in 1998.

Exhibit 8

Compliance Options Chosen in 1998

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 1998, 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 19906 to 1998, the average NOx emission rate of the 265 Phase I units declined by 41% (from

0.70 lb/mmBtu to 0.41 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).

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 1998 were 29 percent lower than in 1990, but 3 percent

higher than in 1997. While this is the second year total NOx mass emissions have increased, the ascent

can be attributed in part to greater electrical production, as evidenced by an increase in heat input in

1997 and 1998 of 3 percent and 6 percent, respectively, compared to 1996. Without further reductions

in emissions rates, NOx emissions would be expected to rise with increased utilization.
1998 Compliance Report Page 14

Exhibit 9

Average NOx Emission Rates for 265 Phase 1 Units

0.77

0.45 0.44 0.43 0.52

0.36 0.36 0.37

0.00

0.20

0.40

0.60

0.80

1.00

1990 1996 1997 1998

NOx Rate 

(lb/mmBtu)

Table 1 Units (171) Substitution Units (94)

Weighted Average

Emissions Limitation

(0.49)

Exhibit 10

NOx Mass Emissions for 265 Phase I Units

1,046,339

669,017 676,797 686,492

287,583

239,373 241,694 257,176

0

400,000

800,000

1,200,000

1,600,000

1990 1996 1997 1998

NOx 

Tons

Table 1 Units (171) Substitution Units (94)

PHASE II EARLY ELECTION UNITS

275 Units Were Subject to Early Election Requirements in 1998

Nineteen ninety-eight was the second year in which early election utility units were required to meet the
1998 Compliance Report Page 15

7

 Compared with 1997, the universe of early election units remained the same, except for W C Dale Units

3 and 4 (KY) and H L Spurlock Unit 2 (KY), which were added after being inadvertently omitted in 1997.

Phase I NOx limit7. Exhibit 11 shows the number of Early Election units by boiler type and their

corresponding emission limit.

Exhibit 11

Distribution of 1998 Early Election Units by Boiler Type

Boiler Type Standard 

Emission Limit

Operating Group 1,

Phase 2 Units 

Early Election

Units

Percent of 

Units Electing

Tangentially-fired 0.45 300 171 57%

Dry Bottom Wall-fired 0.50 314 104 33%

Total 614 275 45%

EARLY ELECTION COMPLIANCE RESULTS

For 1998, EPA determined that all 275 units complied with the Phase I, Group 1 emission limitations

and have continued eligibility for Early Election in 1999 through 2007. See Appendix C-3: Compliance

Results for the 275 Early Election Units in 1998.

Average NOx emission rates for Early Election units have declined by 17%, from 0.46 lb/mmBtu in

1990 to 0.38 lb/mmBtu in 1998. This decline is less dramatic than the decline at Phase I NOx units

because 51% of the Early Election units are newer units already subject to the New Source Performance

Standards (NSPS) NOx emission limits. The overall NOx emission rate for these units is comparable to

the average rate of 0.41 lb/mmBtu for all Phase I NOx units. Exhibit 12 summarizes the NOx emission

rate reductions from 1990 to 1998 by boiler type for the 265 Early Election units that were operating in

1990.
1998 Compliance Report Page 16

8

The 1990 NOx mass emissions value differs slightly from the value in the 1997 NOx Compliance report

due to corrected estimates of heat input for ten units. 

Exhibit 12

Average NOx Emission Rate for 265 Early Election Units (Operating in 1990)

0.45

0.37 0.37

0.47

0.38 0.39

0.00

0.20

0.40

0.60

0.80

1990 1997 1998 1990 1997 1998

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 106,619 tons (or 8

percent) from 19908 to 1998, reflecting an increase in utilization (see Exhibit 13). For the 265 Early

Election units operating in 1990, heat input increased during the eight year period by approximately

28%.
1998 Compliance Report Page 17

Exhibit 13

NOx Mass Emissions for 265 Early Election Units (Operating in 1990)

716,480 750,872 772,054

572,357 583,782 623,402

0

400,000

800,000

1,200,000

1,600,000

1990 1997 1998

NOx 

Tons

T-Fired Units (163) DB Units (102)

SO2 AND NOx MONITORING IN 1998

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 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 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 will also be 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
1998 Compliance Report Page 18

equal to 10 percent for flow (beginning January 1, 2000, the flow standard for superior accuracy will

also be 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 16 highlights the relative accuracy results achieved by Acid Rain CEMS in

1998. 

Exhibit 14

1998 Relative Accuracy Test Audit (RATA) Results

SO2 Concentration Volumetric Flow Rate NOx Rate

Mean Relative Accuracy 4.2% 3.7% 4.1%

Median Relative Accuracy 3.0% 3.0% 3.1%

Percent Meeting Relative Accuracy

Standard

95% 97% 91%

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 17 shows the monitor availabilities reported in 1998 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

1998 CEMS Availability

Parameter Median % Availability at End of 1998

Coal-Fired Units Oil and Gas Units

SO2 99.5 98.5

Flow 99.7 98.8

NOx 99.2 98.0

CONCLUSION

1998 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 1998, all Phase I affected utility units

not only met their compliance goals, but exceeded them, achieving an overall reduction of 390,254 tons
1998 Compliance Report Page 19

9

 U.S. Geological Survey, Trends in Precipitation Chemistry in the United States, 1983-94 - An Analysis

of the Effects in 1995 of Phase I of the CAAA of 1990, Title IV, USGS 96-0346, Washington, DC, June 1996.

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 275 Phase II NOx early election units

had increased emissions of eight 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 19959. 

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, and 24 percent of 1998 allowances that were not retired for

compliance purposes can be used to cover emissions in a later year. However, immediate health and

environmental benefits are arguably more valuable than a benefit 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. 

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

decline steadily to 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 are continuing

the success in 1998. The significant progress evident at this stage of the program is encouraging. 

Through the continued efforts of Phase I participants and by 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. 
1998 Compliance Report Page 20

Appendices A to C-3 were created using a variety of tools. They are not available in PDF; please

download them at:

http://www.epa.gov/acidrain/cmprpt98/appendix.zip
A,1

APPENDIX A: PHASE I AFFECTED (X) AND EARLY ELECTION (E) UNITS IN 1998

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

AL Charles R Lowman 2 E CO Cherokee 3 E

3E 4E

AL Colbert 1 X X CO Pawnee 1 E

2 XX

3 X X CO Rawhide 101 E

4 XX

5 X X CO Ray D Nixon 1 E

AL E C Gaston 1 X X CO Valmont 5 E

2 XX

3 X X CT Bridgeport Harbor BHB3 E

4 XX

5 X X FL Big Bend BB01 X

BB02 X

AL Gadsden 1 X X BB03 X

2 X X BB04 X X

AR Flint Creek 1 E FL C D McIntosh 3 E

AR Independence 1 E FL Crist 4 X X

2 E 5 XX

6 XX

AR White Bluff 1 E 7 X X

2 E

FL Crystal River 2 E

AZ Apache 2 E 4 E

3E 5E

AZ Cholla 1 E FL Deerhaven B2 E

2 E

3 E FL St Johns River 1 E

4E 2E

AZ Coronado U1B E FL Scholz 1 X X

U2B E 2 X X

AZ Navajo 1 E FL Seminole 1 E

2E 2E

3 E

GA Arkwright 1 X X

AZ Springerville 1 E 2 X X

2 E 3 XX

4 XX

CO Craig C1 E

C2 E GA Bowen 1BLR X X

C3 E 2BLR X X

3BLR X X

CO Comanche 1 E 4BLR X X

2 E

GA Hammond 1 X X IA George Neal South 4 E
APPENDIX A: PHASE I AFFECTED (X) AND EARLY ELECTION (E) UNITS IN 1998

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

A,2

2 XX

3 X X IA Lansing 4 E

4 XX

IA Louisa 101 E

GA Harllee Branch 1 X

2 X X IA Milton L Kapp 2 X X

3 X

4 X IA Ottumwa 1 E

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

MB2 X X

IA Riverside 9 X X

GA Kraft 1 X X

2 X X IL Baldwin 1 X

3 XX 2 X

3 XX

GA Mcintosh 1 X X

IL Coffeen 1 X

GA Mitchell 3 X X 2 X

GA Scherer 3 X IL Crawford 7 E

4E 8E

GA Wansley 1 X X IL Dallman 33 E

2 XX

IL Fisk 19 E

GA Yates Y1BR X X

Y2BR X X IL Grand Tower 7 X

Y3BR X X 8 X

Y4BR X X 9 X X

Y5BR X X

Y6BR X X IL Havana 1 X

Y7BR X X 2 X

3 X

IA Ames 7 E 4 X

8 E 5X

6 X

IA Burlington 1 X X 7 X

8 X

IA Council Bluffs 1 E

2 E IL Hennepin 1 X

3 E 2 XX

IA Des Moines 11 X IL Hutsonville 5 X X

6 XX

IA George Neal North 1 X

2 E

3 E

IL Joppa Steam 1 X X IN Dean H Mitchell 4 E
APPENDIX A: PHASE I AFFECTED (X) AND EARLY ELECTION (E) UNITS IN 1998

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

A,3

2 XX 5 E

3 XX 6 E

4 X X 11 E

5 XX

6 X X IN Elmer W Stout 50 X X

60 X X

IL Kincaid 1 X 70 X X

2 X

IN F B Culley 2 X X

IL Meredosia 01 X 3 X X

02 X

03 X IN Frank E Ratts 1SG1 X X

04 X 2SG1 X X

05 X X

IN Gibson 1 X X

IL Newton 1 X X 2 X X

2 XX 3 XX

4 XX

IL Vermilion 1 X X

2 X X IN H T Pritchard 3 X

4 X

IL Waukegan 7 E 5 X X

8 E 6 XX

IL Will County 3 E IN Merom 1SG1 E

4 E 2SG1 E

IL Wood River 1 X IN Michigan City 12 X

IN A B Brown 1 E IN Petersburg 1 X X

2 E 2 XX

3 X

IN Bailly 7 X 4 X

8 X

IN R M Schahfer 15 E

IN Breed 1 X 17 E

18 E

IN Cayuga 1 X X

2 X X IN R Gallagher 1 X X

2 XX

IN Clifty Creek 1 X 3 X X

2 X 4 XX

3 X

4 X IN Rockport MB1 E

5 X MB2 E

6 X

IN State Line 3 E

IN Tanners Creek U4 X

IN Wabash River 1 X X KY H L Spurlock 1 X X
APPENDIX A: PHASE I AFFECTED (X) AND EARLY ELECTION (E) UNITS IN 1998

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

A,4

2 X X 2 E

3 XX

5 X X KY Hmp&L Station 2 H1 X X

6 X X H2 X X

IN Warrick 1 X KY l Mill Creek 1 E

2X 2 E

3X 3 E

4X 4 E

IN Whitewater Valley 1 E KY Paradise 3 X

2 E

KY R D Green G1 X X

KS La Cygne 1 X G2 X X

2 X

KY Shawnee 10 X

KS Nearman Creek 1 E

KY Trimble County 1 E

KS Quindaro 2 X X

KY W C Dale 3 E

KS Riverton 39 E 4 E

40 E

LA Big Cajun 2 2B1 E

KY Cane Run 4 E 2B2 E

5 E 2B3 E

6 E

LA Dolet Hills 1 E

KY Coleman C1 X X

C2 X X LA R S Nelson 6 E

C3 X X

LA Rodemacher 2 E

KY Cooper 1 X X

2 X X MA Brayton Point 2 X

KY D B Wilson W1 E MA Mount Tom X

KY E W Brown 1 X X MD C P Crane 1 X

2 XX 2 X

3 XX

MD Chalk Point 1 X X

KY East Bend 2 X X 2 X X

3 X

KY Elmer Smith 1 X

2 X X MD Morgantown 1 X X

2 XX

KY Ghent 1 X X

MD R P Smith 9 X X

KY Green River 5 X X 11 X X

MI B C Cobb 4 E MO Montrose 1 X X
APPENDIX A: PHASE I AFFECTED (X) AND EARLY ELECTION (E) UNITS IN 1998

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

A,5

5 E 2 XX

3 XX

MI Dan E Karn 2 X

MO New Madrid 1 X

MI J B Sims 3 E 2 X

MI J C Weadock 7 E MO Rush Island 1 X X

8 E 2 XX

MI J H Campbell 1 X X MO Sibley 1 X

2X 2X

 3X

MI J R Whiting 1 E

3 X E MO Sioux 1 X

2 X

MI Presque Isle 7 E

8 E MO Sikeston 1 E

9 E

MO Southwest 1 X X

MN Clay Boswell 3 E

MO Thomas Hill MB1 X

MN High Bridge 3 X X MB2 X

4 X X MB3 X X

5 XX

6 X X MS Jack Watson 4 X X

5 XX

MN Hoot Lake 2 E

MS R D Morrow 1 X X

MN Sherburne County 1 X X 2 X X

2 XX

MS Victor J Daniel Jr 1 X X

MO Asbury 1 X 2 X

MO Hawthorn 5 X X MT Colstrip 1 E

2 E

MO Iatan 1 X 3 E

4 E

MO James River 3 X X

4 X X MT Lewis & Clark B1 E

5 XX

NC Buck 5 E

MO Labadie 1 X X 6 E

2 XX 7 E

3 XX 8 E

4 XX 9 E

MO Meramec 1 X X

2 XX

3 XX

4 X

NC Cliffside 1 E NV Mohave 1 E
APPENDIX A: PHASE I AFFECTED (X) AND EARLY ELECTION (E) UNITS IN 1998

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

A,6

2E 2E

3 E

4 E NV North Valmy 1 E

5E 2E

NC Dan River 1 E NV Reid Gardner 4 E

2 E

3 E NY C R Huntley 67 E

68 E

NC G G Allen 1 E

2 E NY Dunkirk 1 E

3E 2E

4 E 3 XX

5 E 4 XX

NC Marshall 1 E NY Greenidge 6 X X

2 E

3 E NY Kintigh 1 E

4 E

NY Milliken 1 X X

NC Riverbend 7 E 2 X X

8 E

9 E NY Northport 1 X

10 E 2 X

3 X

ND Antelope Valley B1 E 4 X

B2 E

NY Oswego 4 X

ND Leland Olds 1 E 5 X

6 X

ND Stanton 10 E

NY Port Jefferson 3 X

NE Gerald Gentleman 1 E 4 X

2 E

NY Rosetom 1 X

NE Gerald Whelan 1 E 2 X

NE Nebraska City 1 E NY S A Carlson 9 E

10 E

NE North Omaha 4 E 11 E

12 E

NE Platte 1 E

OH Acme 13 X

NH Merrimack 1 X 14 X

2 X 15 X

16 X

NJ B L England 1 X 91 X

2 X 92 X

NM Escalante 1 E

OH Ashatabula 7 X X OH Kyger Creek 1 X
APPENDIX A: PHASE I AFFECTED (X) AND EARLY ELECTION (E) UNITS IN 1998

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

A,7

8X 2X

9X 3X

10 X 4 X

11 X 5 X

OH Avon Lake 9 X OH Lake Shore 18 X

10 X 91 X

11 X 92 X

12 X 93 X

94 X

OH Bay Shore 1 X

2 X OH Miami Fort 5-1 X

3 X 5-2 X

4 X 6 XX

7 X

OH Cardinal 1 X

2 X OH Muskingum River 1 X

2 X

OH Conesville 1 X 3 X

2X 4X

3 XX 5 X

4 XX

5 E OH Niles 1 X

6 E 2X

OH Eastlake 1 X X OH Picway 9 X X

2 XX

3 X X OH Poston 1 X

4 XX 2 X

5X 3X

OH Edgewater 11 X OH R E Burger 1 X

12 X 2 X

13 X X 3 X

4 X

OH Gen J M Gavin 1 X 5 X

2X 6X

7 XX

OH Gorge 25 X X 8 X X

26 X X

OH Toronto 9 X

OH J M Stuart 1 X 10 X X

2 X 11 X X

3 X

4 X OH W H Sammis 5 X X

6 XX

7 X

OH W H Zimmer 1 E

OH Walter C Beckjord 5 X X PA Mitchell 33 X X
APPENDIX A: PHASE I AFFECTED (X) AND EARLY ELECTION (E) UNITS IN 1998

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

A,8

6 XX

PA Montour 1 E

OK Muskogee 4 E 2 E

5 E

6 E PA New Castle 1 X X

2 XX

OK Northeastern 3313 E 3 E

3314 E 4 E

5 E

OK Sooner 1 E

2 E PA Portland 1 X X

2 XX

OR Boardman 1SG E

PA Shawville 1 X X

PA Armstrong 1 X X 2 X X

2 XX 3 XX

4 XX

PA Bruce Mansfield 1 X X

2 X X PA Sunbury 3 X X

3 E 4 XX

PA Brunner Island 1 X X PA Titus 1 E

2 XX 2 E

3 XX 3 E

PA Cheswick 1 X X SC Cross 1 E

2 E

PA Conemaugh 1 X X

2 X X SC W S Lee 1 E

2 E

PA Cromby 1 E 3 E

PA Eddystone 1 E TN Allen 1 X

2 E 2X

3 X

PA Hatfield’s Ferry 1 X

2 X TN Cumberland 1 X

3X 2X

PA Homer City 1 E TN DuPont JVD1 X

2 E Johnsonville JVD2 X

3 E JVD3 X

JVD4 X

PA Keystone 1 E

2 E TN Gallatin 1 X X

2 XX

PA Martins Creek 1 X X 3 X X

2 XX 4 XX

3 X

4 X

TN John Sevier 1 E TX San Miguel SM-1 E
APPENDIX A: PHASE I AFFECTED (X) AND EARLY ELECTION (E) UNITS IN 1998

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

A,9

2 E

3 E TX Sandow 4 E

4 E

TX Tolk 171B E

TN Johnsonville 1 X X 172B E

2 XX

3 X X TX W A Parish WAP5 E

4 X X WAP6 E

5 X X WAP7 E

6 X X WAP8 E

7 XX

8 X X TX Welsh 1 E

9 XX 2 E

10 X X 3 E

TX Big Brown 1 E UT Bonanza 1-1 E

2 E

UT Carbon 1 E

TX Coleto Creek 1 E 2 E

TX Gibbons Creek 1 E UT Hunter 1 E

2 E

TX Harrington 061B E

062B E UT Huntington 1 E

063B E

UT Intermountain 1SGA E

TX J K Spruce BLR1 E 2SGA E

TX J T Deely 1 E VA Chesapeake 1 E

2E 2E

4 E

TX Limestone LIM1 E

LIM2 E VA Chesterfield 3 E

4 E

TX Martin Lake 1 E

2 E VA Glen Lyn 51 E

3 E 52 E

TX Monticello 1 E VA Possum Point 3 E

2 E

3 E VA Potomac River 1 E

2 E

TX Oklaunion 1 E 3 E

4 E

TX Pirkey 1 E 5 E

TX Sam Seymour 1 E VA Yorktown 1 E

2E 2E

3 E

WA Centralia BW21 E WI Valley 1 X
APPENDIX A: PHASE I AFFECTED (X) AND EARLY ELECTION (E) UNITS IN 1998

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

A,10

BW22 E 2 X

3 X

WI Alma B1 X 4 X

B2 X

B3 X WI Weston 1 X X

B4 X X 2 X X

B5 X X 3 X

WI Blount Street 8 E WV Albright 1 X X

9 E

WI Columbia 1 E

2 E 2 XX

3 XX

WI Edgewater 3 X

4 X WV Fort Martin 1 X X

5 E 2X

WI Genoa 1 X X WV Harrison 1 X X

2 XX

WI J P Madgett B1 X X 3 X X

WI Nelson Dewey 1 X WV Kammer 1 X

2X 2X

3 X

WI North Oak Creek 1 X

2 X WV Mitchell 1 X X

3 X 2 XX

4 X

WV Mountaineer 1 E

WI Port Washington 1 X

2 X WV Mt Storm 1 X X

3 X 2 XX

4 X 3 XX

5 X

WV Pleasants 1 X

WI Pulliam 5 X 2 X

6 X

7 X X WV Rivesville 7 X

8 XX 8 X

WI Rock River 1 X WV Willow Island 2 X

2 X

WY Dave Johnston BW41 E

WI South Oak Creek 5 X X BW42 E

6 XX

7 X X WY Jim Bridger BW71 X

8 X X BW72 X

BW73 X

BW74 E

WY Laramie River 1 E
APPENDIX A: PHASE I AFFECTED (X) AND EARLY ELECTION (E) UNITS IN 1998

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

A,11

2 E

3 E

WY Wyodak BW91 X
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 1,2,3,4,5,6,7,8

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

APPENDIX B-1:

Table 1 Units Designating Substitution and Compensating Units - 1998

Substitution Units

Table 1 Units Substitution 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 3

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

MS Jack Watson 5 MS Victor J Daniel 1

NH Merrimack 1,2 MA Mount Tom 1

NY Dunkirk 3,4 NY Oswego 4,5,6

NY Roseton 1,2

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

WV Fort Martin 2 MD R P Smith 11

WV Harrison 1 WV Rivesville 7,8

WV Harrison 3 WV Willow Island 2

State Plant Name Units State Plant Name Units

OH Edgewater 13 MA Brayton Point 2

Table 1 Units Compensating Units

Compensating Units
 APPENDIX B-2: 1999 DEDUCTION FOR EXCEEDING 1998 PHASE I EXTENSION

PROJECTED EMISSIONS LIMITATION

State Plant Name Unit ID Ph I Ext Type

1999 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 7214

IN Michigan City 12 TRANSFER 5317

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 0

IN Wabash River 5 TRANSFER 0

IN Wabash River 6 TRANSFER 0

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 918

KY Hmp&L Station 2 H2 CONTROL 622

KY Paradise 3 TRANSFER 0

MD C P Crane 1 TRANSFER 0

MD Chalk Point 1 TRANSFER 1197

MD Morgantown 1 TRANSFER 0

MD Morgantown 2 TRANSFER 0

NJ B L England 1 TRANSFER 0

NJ B L England 2 CONTROL 0

OH Cardinal 1 TRANSFER 21315

OH Conesville 1 TRANSFER 1116

OH Conesville 3 TRANSFER 5937

OH Eastlake 5 TRANSFER 0

OH Gen J M Gavin 1 CONTROL 3610

OH Gen J M Gavin 2 CONTROL 6808

OH Muskingum River 1 TRANSFER 6522

OH Muskingum River 2 TRANSFER 5965

OH Muskingum River 3 TRANSFER 11823

OH Muskingum River 4 TRANSFER 10856

OH Niles 1 TRANSFER 0

OH Niles 2 TRANSFER 0

OH Picway 9 TRANSFER 3760

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

B-2, 1
 APPENDIX B-2: 1999 DEDUCTION FOR EXCEEDING 1998 PHASE I EXTENSION

PROJECTED EMISSIONS LIMITATION

State Plant Name Unit ID Ph I Ext Type

1999 Allowance 

Deduction

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

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 1 UNITS, 1997 AND 1998

1997 1998 Per

SO2 Utilization SO2 Utilization 

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

AL Colbert CSCO14 (1, 2, 3, 4) 27,220 26,653 AL Colbert 1 Table 1 10,745,711 13,688,471 AL Colbert 2 Table 1 12,048,491 11,842,057 AL Colbert 3 Table 1 9,359,699 11,608,467 AL Colbert 4 Table 1 11,770,490 10,521,841 AL Colbert 5 Table 1 50,803 27,875,666 47,608 27,619,312 

AL E C Gaston CS0CAN (1, 2) 24,949 25,864 AL E C Gaston 1 Table 1 14,950,877 16,687,420 AL E C Gaston 2 Table 1 16,144,807 16,356,089 AL E C Gaston CS0CBN (3, 4) 26,165 25,669 AL E C Gaston 3 Table 1 17,580,910 18,250,153 AL E C Gaston 4 Table 1 16,180,310 16,100,133 AL E C Gaston 5 Table 1 36,094 46,377,835 41,489 55,502,484 AL Gadsden 1 Substitution 4,716 3,257,292 4,751 3,411,299 AL Gadsden 2 Substitution 4,876 3,258,590 4,463 3,271,925 FL Big Bend CS001 (BB01, BB02) 82,191 90,881 FL Big Bend BB01 Table 1 25,060,591 26,361,877 FL Big Bend BB02 Table 1 30,800,835 25,476,465 FL Big Bend XS23 (BB03, BB04) 20,303 16,544 -FL Big Bend BB03 Table 1 26,885,523 26,111,060 FL Big Bend BB04 Substitution 37,274,636 36,267,261 FL Crist 4 Substitution 2,563 3,014,961 3,255 4,108,663 FL Crist 5 Substitution 4,354 5,324,877 3,872 5,008,436 -FL Crist 6 Table 1 10,243 12,828,682 14,461 18,656,237 FL Crist 7 Table 1 19,563 23,238,171 29,005 35,964,652 FL Scholz 1 Substitution 1,280 840,579 1,877 1,583,869 FL Scholz 2 Substitution 2,112 1,337,456 2,877 2,415,353 GA Arkwright CS001 (1, 2, 3, 4) 3,431 4,272 GA Arkwright 1 Substitution 595,763 1,138,948 GA Arkwright 2 Substitution 884,920 1,048,245 GA Arkwright 3 Substitution 919,471 1,220,110 GA Arkwright 4 Substitution 701,745 797,426 GA Bowen 1BLR Table 1 37,241 49,977,072 34,016 46,331,230 GA Bowen 2BLR Table 1 33,675 45,321,466 28,130 37,829,783 -GA Bowen 3BLR Table 1 40,828 54,811,544 47,897 63,956,453 GA Bowen 4BLR Table 1 42,319 57,170,903 35,108 47,544,565 -GA Hammond CS001 (1, 2, 3) 8,609 9,842 GA Hammond 1 Table 1 3,940,166 4,057,785 GA Hammond 2 Table 1 3,355,443 5,257,052 

B-3, 1
APPENDIX B-3: EMISSIONS AND UTILIZATION OF PHASE 1 UNITS, 1997 AND 1998

1997 1998 Per

SO2 Utilization SO2 Utilization 

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

GA Hammond 3 Table 1 4,809,927 4,656,394 GA Hammond 4 Table 1 16,571 23,714,698 13,217 18,223,752 -GA Harllee Branch CS001 (1, 2) 29,845 32,342 GA Harllee Branch 1 Substitution 13,643,892 13,350,533 GA Harllee Branch 2 Substitution 13,727,469 16,451,112 GA Harllee Branch CS002 (3, 4) 53,136 56,643 GA Harllee Branch 3 Substitution 25,801,742 24,716,035 GA Harllee Branch 4 Substitution 25,840,817 28,122,964 GA Jack Mcdonough CS001 (MB1, MB2) 28,284 28,516 GA Jack Mcdonough MB1 Table 1 17,391,180 16,039,404 GA Jack Mcdonough MB2 Table 1 18,039,198 19,355,611 GA Kraft XS123 (1, 2, 3) 7,267 5,906 -GA Kraft 1 Substitution 1,485,281 2,430,615 GA Kraft 2 Substitution 1,775,138 1,960,136 GA Kraft 3 Substitution 4,273,319 4,977,302 GA Mcintosh 1 Substitution 6,175 7,719,743 6,716 7,791,088 GA Mitchell 3 Substitution 3,892 4,404,128 4,621 4,595,267 GA Wansley 1 Table 1 34,105 45,956,580 44,760 49,668,355 GA Wansley 2 Table 1 32,258 45,215,913 42,489 48,149,781 GA Yates Y1BR Table 1 130 2,562,462 131 3,531,547 GA Yates CS001 (Y2BR, Y3BR) 6,412 6,865 GA Yates Y2BR Table 1 3,568,288 4,503,564 GA Yates Y3BR Table 1 3,782,679 3,787,505 GA Yates CS002 (Y4BR, Y5BR) 8,923 9,136 GA Yates Y4BR Table 1 5,505,970 6,401,735 GA Yates Y5BR Table 1 4,525,391 4,344,893 GA Yates Y6BR Table 1 9,393 12,553,519 11,192 13,969,410 GA Yates Y7BR Table 1 9,702 12,915,696 12,150 15,552,726 IA Burlington 1 Table 1 6,352 10,287,375 5,847 11,743,015 IA Des Moines 11 Table 1 0 0 0 0 IA George Neal North 1 Table 1 4,040 9,719,336 3,974 9,767,070 IA Milton L Kapp 2 Table 1 4,839 10,867,684 5,282 12,293,176 IA Prairie Creek 4 Table 1 2,985 8,488,312 4,035 10,102,922 IA Riverside 9 Table 1 2,545 6,955,832 1,435 6,283,598 -IL Baldwin 1 Table 1 88,439 34,346,752 71,396 27,377,162 -IL Baldwin 2 Table 1 92,284 35,355,084 92,968 35,735,840 IL Baldwin 3 Table 1 95,312 37,180,092 120,253 46,260,316 IL Coffeen CS0001 (1, 2) 47,756 49,413 IL Coffeen 1 Table 1 13,363,732 12,847,399 

B-3, 2
APPENDIX B-3: EMISSIONS AND UTILIZATION OF PHASE 1 UNITS, 1997 AND 1998

1997 1998 Per

SO2 Utilization SO2 Utilization 

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

IL Coffeen 2 Table 1 31,126,083 28,483,817 IL Grand Tower 9 Table 1 18,586 7,209,130 9,188 3,949,534 -IL Havana 1 Substitution 0 0 0 0 IL Havana 2 Substitution 0 0 5 10,635 IL Havana 3 Substitution 0 0 9 19,243 IL Havana 4 Substitution 0 0 39 83,760 IL Havana 5 Substitution 0 0 41 86,786 IL Havana 6 Substitution 0 0 29 61,257 IL Havana 7 Substitution 0 0 24 51,653 IL Havana 8 Substitution 0 0 30 64,432 IL Hennepin CS3 (1, 2) 47,346 46,809 IL Hennepin 1 Substitution 6,127,376 3,345,169 IL Hennepin 2 Table 1 14,943,169 15,865,737 IL Hutsonville 5 Substitution 8,640 3,962,435 5,238 2,449,651 -IL Hutsonville 6 Substitution 10,982 4,920,046 5,666 2,476,690 -IL Joppa Steam CS1 (1, 2) 7,731 8,280 IL Joppa Steam 1 Table 1 15,784,056 16,642,916 IL Joppa Steam 2 Table 1 13,883,968 16,895,957 IL Joppa Steam CS2 (3, 4) 7,998 7,937 IL Joppa Steam 3 Table 1 14,698,413 16,246,827 IL Joppa Steam 4 Table 1 15,562,767 15,657,774 IL Joppa Steam CS3 (5, 6) 8,472 7,636 IL Joppa Steam 5 Table 1 16,251,487 16,131,320 IL Joppa Steam 6 Table 1 15,991,784 14,904,104 IL Kincaid CS0102 (1, 2) 41,096 46,417 IL Kincaid 1 Table 1 18,383,480 18,743,889 IL Kincaid 2 Table 1 22,185,732 30,554,552 IL Meredosia 5 Table 1 15,950 10,034,553 10,941 8,114,710 -IL Newton 1 Substitution 16,698 8,356,418 7,508 30,901,900 -IL Newton 2 Substitution 13,619 30,265,558 14,298 31,776,832 IL Vermilion CS3 (1, 2) 6,208 12,220 IL Vermilion 1 Substitution 1,488,706 3,484,888 IL Vermilion 2 Table 1 2,826,121 5,717,555 IL Wood River 1 Substitution 0 513,068 1 475,387 IN Bailly XS12 (7, 8) 4,736 4,334 IN Bailly 7 Table 1 12,242,636 10,663,125 IN Bailly 8 Table 1 19,485,943 21,683,417 IN Breed 1 Table 1 0 0 0 0 IN Cayuga 1 Table 1 56,992 36,475,622 51,345 36,106,576 

B-3, 3
APPENDIX B-3: EMISSIONS AND UTILIZATION OF PHASE 1 UNITS, 1997 AND 1998

1997 1998 Per

SO2 Utilization SO2 Utilization 

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

IN Cayuga 2 Table 1 51,796 33,321,734 37,593 24,672,500 -IN Clifty Creek CS001 (1, 2, 3) 44,612 46,294 IN Clifty Creek 1 Table 1 15,465,093 15,187,611 IN Clifty Creek 2 Table 1 13,905,955 15,722,352 IN Clifty Creek 3 Table 1 15,588,922 16,620,156 IN Clifty Creek CS002 (4, 5, 6) 48,844 42,899 -IN Clifty Creek 4 Table 1 15,077,344 15,129,975 IN Clifty Creek 5 Table 1 14,905,050 15,465,474 IN Clifty Creek 6 Table 1 14,827,092 11,649,523 IN Elmer W Stout 50 Table 1 7,444 6,831,371 6,638 6,373,331 -IN Elmer W Stout 60 Table 1 6,561 5,794,145 7,392 6,765,079 IN Elmer W Stout 70 Table 1 22,717 20,926,892 25,931 24,602,220 IN F B Culley XS23 (2, 3) 5,152 7,687 IN F B Culley 2 Table 1 6,571,635 7,665,616 IN F B Culley 3 Table 1 19,032,117 24,969,662 IN Frank E Ratts 1SG1 Table 1 8,566 7,431,668 9,236 8,756,973 IN Frank E Ratts 2SG1 Table 1 7,989 6,728,905 9,393 8,486,975 IN Gibson CS0003 (1, 2) 79,183 94,431 IN Gibson 1 Table 1 34,509,324 42,521,424 IN Gibson 2 Table 1 36,456,884 39,961,024 IN Gibson XS34 (3, 4) 49,170 51,189 IN Gibson 3 Table 1 35,455,094 35,238,356 IN Gibson 4 Table 1 47,452,516 48,852,984 IN H T Pritchard CS596 (5, 6) 8,909 7,512 -IN H T Pritchard 5 Substitution 2,270,877 2,725,130 IN H T Pritchard 6 Table 1 6,791,206 5,325,128 IN Michigan City 12 Table 1 15,262 25,071,593 16,672 28,722,177 IN Petersburg 1 Table 1 2,893 17,617,335 2,247 16,853,716 -IN Petersburg 2 Table 1 4,162 32,198,117 4,136 32,849,989 IN R Gallagher CS0001 (1, 2) 25,662 22,954 -IN R Gallagher 1 Table 1 7,671,999 6,484,783 IN R Gallagher 2 Table 1 8,015,384 8,078,498 IN R Gallagher CS0002 (3, 4) 21,183 27,642 IN R Gallagher 3 Table 1 6,067,619 9,757,824 IN R Gallagher 4 Table 1 5,817,989 8,730,732 IN Tanners Creek U4 Table 1 61,344 31,794,760 32,017 21,095,772 -IN Wabash River 1 Table 1 1,051 7,893,969 851 10,195,928 -IN Wabash River XS2356 (2, 3, 5, 6) 37,577 48,580 IN Wabash River 2 Table 1 4,391,103 5,345,939 

B-3, 4
APPENDIX B-3: EMISSIONS AND UTILIZATION OF PHASE 1 UNITS, 1997 AND 1998

1997 1998 Per

SO2 Utilization SO2 Utilization 

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

IN Wabash River 3 Table 1 3,873,572 5,574,897 IN Wabash River 5 Table 1 4,755,001 6,735,426 IN Wabash River 6 Table 1 17,074,386 18,378,868 IN Warrick XS123 (1, 2, 3) 79,037 78,964 IN Warrick 1 Opt In 11,713,016 12,261,983 IN Warrick 2 Opt In 12,777,383 12,265,399 IN Warrick 3 Opt In 12,080,812 12,241,810 IN Warrick 4 Table 1 39,864 22,244,140 34,078 18,411,332 -KS La Cygne 1 Substitution 6,927 43,169,137 6,319 34,557,496 KS Quindaro 2 Table 1 4,052 7,372,206 2,985 6,966,804 -KY Coleman C1 Table 1 15,985 10,496,532 13,908 10,837,598 -KY Coleman C2 Table 1 18,600 12,638,043 9,677 7,993,759 -KY Coleman C3 Table 1 16,037 11,091,506 14,568 11,281,190 KY Cooper CS1 (1, 2) 15,818 17,613 KY Cooper 1 Table 1 6,128,337 6,162,103 KY Cooper 2 Table 1 11,663,764 12,814,633 KY E W Brown 1 Table 1 5,869 5,534,775 6,762 6,033,395 KY E W Brown CS003 (2, 3) 30,538 35,473 KY E W Brown 2 Table 1 10,048,618 10,629,369 KY E W Brown 3 Table 1 20,628,855 22,188,450 KY East Bend 2 Substitution 13,083 50,645,676 13,064 41,851,087 KY Elmer Smith XS12 (1, 2) 7,688 7,011 KY Elmer Smith 1 Table 1 11,998,464 10,447,080 KY Elmer Smith 2 Table 1 20,955,232 21,192,016 KY Ghent 1 Table 1 7,399 38,733,307 7,396 39,524,506 KY Green River 5 Table 1 12,409 5,782,136 14,438 6,883,122 KY H L Spurlock 1 Table 1 15,669 23,080,348 14,941 21,451,848 KY Hmp&L Station 2 H1 Table 1 2,142 11,602,514 2,397 12,326,347 KY Hmp&L Station 2 H2 Table 1 2,482 12,675,842 2,130 12,467,753 -KY Paradise 3 Table 1 173,285 72,721,248 126,946 59,456,328 -KY R D Green G1 Substitution 1,004 15,541,123 1,828 19,256,597 KY R D Green G2 Substitution 1,323 18,062,324 2,136 16,646,528 KY Shawnee 10 Table 1 2,204 8,930,212 1,560 7,598,398 -MA Brayton Point 2 Compensating 10,646 18,916,857 9,744 18,403,534 MA Mount Tom 1 Substitution 9,742 11,867,279 8,417 10,400,402 -MD C P Crane 1 Table 1 12,740 9,725,873 15,224 12,220,342 MD C P Crane 2 Table 1 17,050 13,359,231 13,636 10,972,712 -MD Chalk Point CSE12 (1, 2) 39,789 44,721 MD Chalk Point 1 Table 1 17,952,950 23,306,258 

B-3, 5
APPENDIX B-3: EMISSIONS AND UTILIZATION OF PHASE 1 UNITS, 1997 AND 1998

1997 1998 Per

SO2 Utilization SO2 Utilization 

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

MD Chalk Point 2 Table 1 21,531,764 21,586,648 MD Chalk Point 3 Substitution 2,716 7,631,900 7,732 17,351,546 1MD Morgantown 1 Table 1 39,650 38,101,385 34,953 33,077,778 -MD Morgantown 2 Table 1 33,341 31,834,220 44,953 43,364,798 MD R P Smith 9 Substitution 71 92,709 117 152,062 MD R P Smith 11 Substitution 2,264 2,986,412 2,262 2,977,734 MI Dan E Karn 2 Substitution 9,694 16,458,054 8,426 13,176,629 -MI J H Campbell CS0009 (1, 2) 21,219 22,693 MI J H Campbell 1 Table 1 15,183,312 13,474,893 MI J H Campbell 2 Table 1 19,817,269 24,729,551 MI J R Whiting 3 Substitution 4,801 7,534,265 4,755 7,786,674 MN High Bridge CS0001 (3, 4, 5, 6) 3,848 4,044 MN High Bridge 3 Substitution 1,150,622 1,553,609 MN High Bridge 4 Substitution 1,616,997 1,543,292 MN High Bridge 5 Substitution 3,694,447 7,083,980 MN High Bridge 6 Table 1 10,898,522 10,753,526 MN Sherburne County CS1 (1, 2) 9,132 8,958 MN Sherburne County 1 Substitution 50,979,544 43,745,696 MN Sherburne County 2 Substitution 44,659,663 50,587,266 MO Asbury 1 Table 1 9,236 14,205,505 8,212 12,859,011 -MO Hawthorn 5 Substitution 9,297 25,785,864 7,106 20,633,908 -MO James River 3 Substitution 1,164 2,276,282 1,409 3,121,544 MO James River 4 Substitution 1,780 3,692,173 1,708 3,737,611 MO James River 5 Table 1 3,633 6,726,246 2,810 5,934,107 -MO Labadie 1 Table 1 12,452 30,729,514 15,654 42,347,449 MO Labadie 2 Table 1 15,063 35,276,040 12,987 34,534,886 -MO Labadie 3 Table 1 12,635 36,859,037 14,602 40,580,655 MO Labadie 4 Table 1 13,777 38,871,905 14,354 39,516,498 MO Meramec 1 Substitution 3,147 4,756,769 1,670 4,991,896 -MO Meramec 2 Substitution 3,388 5,293,610 1,541 4,792,250 -MO Meramec 3 Substitution 3,364 4,832,568 3,706 6,900,132 MO Montrose 1 Table 1 2,705 10,856,432 4,072 11,013,403 MO Montrose CS023 (2, 3) 6,684 8,875 MO Montrose 2 Table 1 11,916,991 10,380,984 MO Montrose 3 Table 1 12,520,698 11,783,069 MO New Madrid 1 Table 1 8,924 37,657,244 8,735 42,006,552 MO New Madrid 2 Table 1 10,474 48,200,332 9,018 46,640,504 -MO Rush Island 1 Substitution 13,484 39,221,199 13,485 40,512,757 MO Rush Island 2 Substitution 11,659 33,936,175 13,924 42,312,616 

B-3, 6
APPENDIX B-3: EMISSIONS AND UTILIZATION OF PHASE 1 UNITS, 1997 AND 1998

1997 1998 Per

SO2 Utilization SO2 Utilization 

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

MO Sibley CS0001 (1, 2, 3) 19,839 27,056 MO Sibley 1 Substitution 3,298,131 3,195,388 MO Sibley 2 Substitution 3,238,192 3,125,667 MO Sibley 3 Table 1 23,606,317 26,076,510 MO Sioux 1 Table 1 30,140 26,885,257 18,885 24,814,785 -MO Sioux 2 Table 1 24,968 23,482,964 23,062 30,562,053 MO Southwest 1 Substitution 3,785 14,063,350 6,837 16,707,842 MO Thomas Hill MB1 Table 1 3,382 14,948,531 3,080 15,127,247 MO Thomas Hill MB2 Table 1 4,978 22,396,264 4,722 23,711,214 MO Thomas Hill MB3 Substitution 11,224 48,569,132 9,916 47,129,420 -MS Jack Watson 4 Table 1 11,749 13,197,197 18,528 18,271,530 MS Jack Watson 5 Table 1 30,551 33,634,910 32,033 32,387,107 MS R D Morrow 1 Substitution 5,072 14,735,176 4,267 14,398,624 -MS R D Morrow 2 Substitution 4,255 13,281,477 4,383 15,094,507 MS Victor J Daniel Jr 1 Substitution 11,632 33,717,920 8,109 23,039,448 -NH Merrimack 1 Table 1 13,509 10,134,559 12,126 9,625,002 -NH Merrimack 2 Table 1 26,144 24,340,602 22,794 21,653,842 -NJ B L England 1 Table 1 15,485 7,573,153 15,694 7,658,545 NJ B L England 2 Table 1 1,787 9,896,490 1,084 6,770,210 -NY Dunkirk CS0003 (3, 4) 34,072 37,527 NY Dunkirk 3 Table 1 10,571,064 12,014,610 NY Dunkirk 4 Table 1 11,521,991 14,506,026 NY Greenidge 6 Table 1 8,126 7,315,437 9,027 8,538,897 NY Milliken XS12 (1, 2) 5,620 8,572 NY Milliken 1 Table 1 10,772,403 12,085,829 NY Milliken 2 Table 1 11,167,395 12,008,990 NY Northport 1 Table 1 4,868 8,862,375 2,764 12,065,492 -NY Northport 2 Table 1 2,661 20,781,446 4,866 17,255,806 NY Northport 3 Table 1 4,279 7,753,803 10,502 19,356,322 1NY Northport 4 Substitution 822 20,283,682 1,136 12,918,579 NY Oswego 4 Substitution 0 0 0 0 NY Oswego 5 Substitution 0 0 3,982 8,095,710 NY Oswego 6 Substitution 1,080 5,955,023 1,121 5,315,851 NY Port Jefferson 3 Table 1 1,890 10,691,389 4,185 9,726,121 1NY Port Jefferson 4 Table 1 1,602 7,149,114 3,171 11,039,434 NY Roseton 1 Substitution 4,380 9,526,581 10,538 19,694,318 1NY Roseton 2 Substitution 7,132 16,206,427 14,192 26,363,992 OH Acme 13 Substitution 0 0 0 0 OH Acme 14 Substitution 0 0 0 0 

B-3, 7
APPENDIX B-3: EMISSIONS AND UTILIZATION OF PHASE 1 UNITS, 1997 AND 1998

1997 1998 Per

SO2 Utilization SO2 Utilization 

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

OH Acme 15 Substitution 0 0 0 0 OH Acme 16 Substitution 0 0 0 0 OH Acme 91 Substitution 0 0 0 0 OH Acme 92 Substitution 0 0 0 0 OH Ashtabula 7 Table 1 39,662 12,618,530 26,164 9,268,567 -OH Ashtabula CS1 (8, 9, 10, 11) 6,942 2,048 -OH Ashtabula 8 Substitution 0 0 OH Ashtabula 9 Substitution 0 0 OH Ashtabula 10 Substitution 191,965 287,495 OH Ashtabula 11 Substitution 2,020,623 530,174 OH Avon Lake 9 Substitution 483 597,938 0 0 -OH Avon Lake 10 Substitution 4,274 4,816,566 1,222 1,437,105 -OH Avon Lake 11 Table 1 0 0 0 0 OH Avon Lake 12 Table 1 28,037 32,607,684 27,714 36,413,732 OH Bay Shore CS5 (1, 2, 3, 4) 13,874 11,472 -OH Bay Shore 1 Substitution 6,545,978 6,462,382 OH Bay Shore 2 Substitution 7,024,540 6,807,479 OH Bay Shore 3 Substitution 7,316,921 7,261,342 OH Bay Shore 4 Substitution 10,813,196 9,238,904 OH Cardinal 1 Table 1 84,875 30,461,782 95,520 32,017,382 OH Cardinal 2 Table 1 58,818 36,443,680 33,017 34,846,000 -OH Conesville CS012 (1, 2) 31,975 30,089 OH Conesville 1 Table 1 7,169,706 6,163,071 OH Conesville 2 Table 1 7,275,241 6,974,286 OH Conesville 3 Table 1 16,424 7,352,729 17,937 7,761,567 OH Conesville 4 Table 1 83,428 37,503,728 72,035 32,772,680 -OH Eastlake 1 Table 1 16,379 7,958,930 11,186 6,311,370 -OH Eastlake 2 Table 1 15,487 7,503,532 11,992 6,852,009 -OH Eastlake 3 Table 1 16,084 8,015,486 12,985 8,079,638 -OH Eastlake 4 Table 1 26,322 13,078,361 18,497 10,573,149 -OH Eastlake 5 Table 1 53,952 27,418,308 56,011 36,867,392 OH Edgewater 11 Substitution 0 0 0 0 OH Edgewater 12 Substitution 0 0 0 0 OH Edgewater 13 Table 1 3 190,520 7 1,228,962 1OH Gen J M Gavin 1 Table 1 16,854 86,726,768 15,085 78,819,640 -OH Gen J M Gavin 2 Table 1 16,812 74,801,544 18,718 94,637,496 OH Gorge 25 Substitution 0 0 0 0 OH Gorge 26 Substitution 0 0 0 0 OH J M Stuart 1 Substitution 23,885 33,042,560 27,024 37,286,928 

B-3, 8
APPENDIX B-3: EMISSIONS AND UTILIZATION OF PHASE 1 UNITS, 1997 AND 1998

1997 1998 Per

SO2 Utilization SO2 Utilization 

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

OH J M Stuart 2 Substitution 28,883 40,245,244 29,520 40,858,280 OH J M Stuart 3 Substitution 25,127 35,157,140 23,211 32,223,074 OH J M Stuart 4 Substitution 26,949 37,297,652 23,603 33,318,570 -OH Kyger Creek CS001 (1, 2, 3, 4, 5) 111,419 119,171 OH Kyger Creek 1 Table 1 14,525,068 14,334,231 OH Kyger Creek 2 Table 1 15,156,232 15,054,039 OH Kyger Creek 3 Table 1 15,150,482 14,714,973 OH Kyger Creek 4 Table 1 14,638,612 16,147,978 OH Kyger Creek 5 Table 1 14,960,636 14,395,578 OH Lake Shore 18 Substitution 497 1,692,121 1,811 3,627,698 2OH Lake Shore 91 Substitution 0 0 0 0 OH Lake Shore 92 Substitution 0 0 0 0 OH Lake Shore 93 Substitution 0 0 0 0 OH Lake Shore 94 Substitution 0 0 0 0 OH Miami Fort CS056 (5-1, 5-2, 6) 10,087 19,614 OH Miami Fort 5-1 Table 1 876,111 1,373,320 OH Miami Fort 5-2 Table 1 876,111 1,374,643 OH Miami Fort 6 Table 1 7,661,698 13,624,571 OH Miami Fort 7 Table 1 38,666 36,213,342 36,473 29,030,836 OH Muskingum River CS014 (1, 2, 3, 4) 161,924 152,316 OH Muskingum River 1 Table 1 12,198,445 9,969,079 OH Muskingum River 2 Table 1 9,313,687 10,138,733 OH Muskingum River 3 Table 1 11,202,854 11,271,723 OH Muskingum River 4 Table 1 11,861,307 10,897,014 OH Muskingum River 5 Table 1 21,872 37,710,912 15,307 27,975,016 -OH Niles XS12 (1, 2) 13,340 21,636 OH Niles 1 Table 1 7,712,996 7,625,299 OH Niles 2 Table 1 3,337,159 5,534,045 OH Picway 9 Table 1 16,843 5,797,157 13,385 4,802,830 -OH Poston 1 Substitution 0 0 0 0 OH Poston 2 Substitution 0 0 0 0 OH Poston 3 Substitution 0 0 0 0 OH R E Burger CS0001 (1, 2, 3, 4, 5, 6, 7, 8) 46,842 38,543 -OH R E Burger 1 Substitution 0 0 OH R E Burger 2 Substitution 0 0 OH R E Burger 3 Substitution 0 0 OH R E Burger 4 Substitution 0 0 OH R E Burger 5 Table 1 754,982 23 OH R E Burger 6 Table 1 648,775 22,906 

B-3, 9
APPENDIX B-3: EMISSIONS AND UTILIZATION OF PHASE 1 UNITS, 1997 AND 1998

1997 1998 Per

SO2 Utilization SO2 Utilization 

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

OH R E Burger 7 Table 1 10,903,432 10,366,887 OH R E Burger 8 Table 1 10,116,964 9,213,604 OH Toronto 10 Substitution 0 0 0 0 OH Toronto 11 Substitution 0 0 0 0 OH Toronto 9 Substitution 0 0 0 0 OH W H Sammis 5 Table 1 16,619 20,677,232 16,812 19,236,457 OH W H Sammis 6 Table 1 33,154 38,089,788 20,352 29,506,312 -OH W H Sammis 7 Table 1 30,208 34,854,765 45,828 44,358,048 OH Walter C Beckjord 5 Table 1 14,542 12,225,260 20,329 15,957,426 OH Walter C Beckjord 6 Table 1 33,099 27,984,274 39,455 29,796,457 PA Armstrong 1 Table 1 16,282 10,871,651 18,227 11,997,280 PA Armstrong 2 Table 1 16,847 11,549,498 17,658 11,802,474 PA Bruce Mansfield 1 Substitution 6,555 50,690,148 7,527 52,609,590 PA Bruce Mansfield 2 Substitution 7,123 43,678,116 6,765 42,620,088 PA Brunner Island CS102 (1, 2) 44,391 48,020 PA Brunner Island 1 Table 1 16,560,069 17,977,978 PA Brunner Island 2 Table 1 21,563,393 21,591,769 PA Brunner Island 3 Table 1 52,349 45,583,894 47,679 38,668,683 PA Cheswick 1 Table 1 47,510 37,412,616 32,177 25,447,980 -PA Conemaugh 1 Table 1 3,754 66,299,762 3,874 64,682,996 PA Conemaugh 2 Table 1 3,502 61,034,531 4,347 72,193,913 PA Hatfield's Ferry XS123 (1, 2, 3) 138,630 150,868 PA Hatfield's Ferry 1 Table 1 24,642,421 33,536,438 PA Hatfield's Ferry 2 Table 1 29,327,176 29,112,948 PA Hatfield's Ferry 3 Table 1 35,212,528 29,387,244 PA Martins Creek CS102 (1, 2) 23,661 15,834 -PA Martins Creek 1 Table 1 9,668,016 6,486,775 PA Martins Creek 2 Table 1 9,896,340 6,021,584 PA Martins Creek 3 Substitution 2,082 6,918,551 4,742 11,288,576 1PA Martins Creek 4 Substitution 1,938 5,638,557 4,347 10,631,226 1PA Mitchell 33 Substitution 1,080 16,667,369 1,050 16,084,774 PA New Castle 1 Substitution 0 0 0 0 PA New Castle 2 Substitution 0 0 0 0 PA Portland 1 Table 1 11,574 7,648,014 9,772 8,564,817 -PA Portland 2 Table 1 17,463 11,972,331 12,126 10,950,567 -PA Shawville 1 Table 1 15,230 9,672,852 12,864 8,432,824 -PA Shawville 2 Table 1 15,609 9,861,149 12,365 8,234,692 -PA Shawville CS1 (3, 4) 33,064 33,535 PA Shawville 3 Table 1 10,382,892 12,435,105 

B-3, 10
APPENDIX B-3: EMISSIONS AND UTILIZATION OF PHASE 1 UNITS, 1997 AND 1998

1997 1998 Per

SO2 Utilization SO2 Utilization 

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

PA Shawville 4 Table 1 12,363,361 12,289,735 PA Sunbury 3 Table 1 11,343 8,209,041 10,307 8,357,434 PA Sunbury 4 Table 1 11,326 8,102,198 11,970 9,405,060 TN Allen 1 Table1 6,754 14,847,074 5,671 13,314,521 -TN Allen 2 Table1 7,134 16,492,487 7,378 17,881,872 TN Allen 3 Table1 7,436 17,656,804 7,162 18,246,196 TN Cumberland 1 Table 1 9,846 111,236,832 10,610 93,425,640 TN Cumberland 2 Table 1 11,122 118,698,432 9,891 77,445,408 -TN DuPont Johnsonville JVD1 Opt In 0 0 0 0 TN DuPont Johnsonville JVD2 Opt In 0 0 0 0 TN DuPont Johnsonville JVD3 Opt In 0 0 0 0 TN DuPont Johnsonville JVD4 Opt In 0 0 0 0 TN Gallatin CSGA12 (1, 2) 50,974 40,664 -TN Gallatin 1 Table 1 14,146,293 16,675,013 TN Gallatin 2 Table 1 13,928,512 13,358,894 TN Gallatin CSGA34 (3, 4) 66,129 45,551 -TN Gallatin 3 Table 1 17,014,207 18,006,243 TN Gallatin 4 Table 1 18,173,564 14,508,353 TN Johnsonville CSJO10 (1, 2, 3, 4, 5, 6, 7, 8, 9, 10) 115,938 114,588 TN Johnsonville 1 Table 1 6,385,030 8,391,787 TN Johnsonville 2 Table 1 8,774,006 6,454,090 TN Johnsonville 3 Table 1 8,605,129 5,676,977 TN Johnsonville 4 Table 1 8,448,481 7,806,189 TN Johnsonville 5 Table 1 7,847,835 6,805,978 TN Johnsonville 6 Table 1 6,274,393 7,370,703 TN Johnsonville 7 Table 1 8,278,704 7,852,052 TN Johnsonville 8 Table 1 9,340,449 8,457,149 TN Johnsonville 9 Table 1 9,054,961 9,737,698 TN Johnsonville 10 Table 1 6,274,673 8,049,553 WI Alma CS1 (B1, B2, B3, B4, B5) 5,608 6,517 WI Alma B1 Opt In NA 663,744 WI Alma B2 Opt In NA 602,030 WI Alma B3 Opt In NA 565,438 WI Alma B4 Substitution 2,637,034 3,122,034 WI Alma B5 Substitution 3,645,037 4,318,051 WI Edgewater 3 Substitution 1,620 4,010,042 1,973 5,011,080 WI Edgewater 4 Table 1 7,968 19,448,932 8,391 20,197,100 WI Genoa 1 Table 1 12,750 23,336,894 9,031 16,559,515 -WI J P Madgett B1 Substitution 4,946 21,777,568 5,223 25,231,992 

B-3, 11
APPENDIX B-3: EMISSIONS AND UTILIZATION OF PHASE 1 UNITS, 1997 AND 1998

1997 1998 Per

SO2 Utilization SO2 Utilization 

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

WI Nelson Dewey CS1 (1, 2) 6,092 10,861 WI Nelson Dewey 1 Table 1 8,239,503 6,172,813 WI Nelson Dewey 2 Table 1 8,457,749 7,216,679 WI North Oak Creek 1 Table 1 0 0 0 0 WI North Oak Creek 2 Table 1 0 0 0 0 WI North Oak Creek 3 Table 1 0 0 0 0 WI North Oak Creek 4 Table 1 0 0 0 0 WI Pulliam CS56 (5, 6) 2,141 1,884 -WI Pulliam 5 Substitution 3,268,887 3,766,998 WI Pulliam 6 Substitution 5,354,200 5,003,476 WI Pulliam 7 Substitution 1,540 6,492,200 1,569 7,422,811 WI Pulliam 8 Table 1 2,264 9,850,126 2,283 11,212,789 WI Rock River 1 Substitution 1,560 4,227,957 1,532 4,083,241 WI Rock River 2 Substitution 1,776 4,871,904 1,898 4,957,022 WI South Oak Creek CS3 (5, 6) 15,452 16,781 WI South Oak Creek 5 Table 1 15,182,914 10,136,963 WI South Oak Creek 6 Table 1 9,504,521 16,111,857 WI South Oak Creek CS4 (7, 8) 25,934 26,529 WI South Oak Creek 7 Table 1 22,009,580 20,272,864 WI South Oak Creek 8 Table 1 19,063,307 18,324,182 WI Weston 1 Substitution 1,318 4,399,791 1,111 3,956,520 -WI Weston 2 Substitution 1,678 5,695,054 1,922 6,830,073 WV Albright 1 Substitution 1,578 1,269,279 2,202 1,843,436 WV Albright 2 Substitution 1,682 1,333,070 1,929 1,623,422 WV Albright 3 Table1 9,380 7,411,488 7,228 6,078,740 -WV Fort Martin 1 Table 1 42,733 36,022,017 41,641 34,726,484 WV Fort Martin 2 Table 1 44,413 37,187,816 37,663 30,423,447 -WV Harrison XS123 (1, 2, 3) 6,298 6,934 WV Harrison 1 Table 1 48,646,367 46,082,925 WV Harrison 2 Table 1 48,426,987 51,433,080 WV Harrison 3 Table 1 45,939,810 55,241,467 WV Kammer CS013 (1, 2, 3) 126,273 108,618 -WV Kammer 1 Table 1 13,727,107 13,479,546 WV Kammer 2 Table 1 15,078,749 12,639,201 WV Kammer 3 Table 1 17,379,095 13,391,834 WV Mitchell CS012 (1, 2) 57,239 59,330 WV Mitchell 1 Table 1 40,025,964 44,346,849 WV Mitchell 2 Table 1 50,581,435 48,141,367 WV Mt Storm CS0 (1, 2) 92,716 106,759 

B-3, 12
APPENDIX B-3: EMISSIONS AND UTILIZATION OF PHASE 1 UNITS, 1997 AND 1998

1997 1998 Per

SO2 Utilization SO2 Utilization 

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

WV Mt Storm 1 Table 1 35,476,403 41,523,871 WV Mt Storm 2 Table 1 36,446,948 39,716,905 WV Mt Storm 3 Table 1 4,052 45,013,972 4,576 47,191,480 WV Rivesville 7 Substitution 235 299,093 624 819,610 1WV Rivesville 8 Substitution 1,234 1,531,972 1,995 2,531,623 WV Willow Island 2 Substitution 8,067 8,554,928 7,870 8,015,622 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, 13
APPENDIX B-4: EMISSIONS AND ALLOWANCE HOLDINGS OF PHASE 1 UNITS

SO2 SO2 1998 Held in Allowances 

Emissions Emissions Allowances Unit Accounts Deducted for 

State Plant Name Stack/Unit ID Unit Type (a) 1997 (b) 1998(b) Allocated (c) as of 3/1/99 Emissions (d) 

AL Colbert CSCO14 (1, 2, 3, 4) 27,220 26,653AL Colbert 1 Table 1 13,213 21,577 7,679 AL Colbert 2 Table 1 14,907 28,046 6,719 AL Colbert 3 Table 1 14,995 28,275 6,460 AL Colbert 4 Table 1 15,005 28,493 5,795 AL Colbert 5 Table 1 50,803 47,608 36,202 48,561 47,608 AL E C Gaston CS0CAN (1, 2) 24,949 25,864AL E C Gaston 1 Table 1 17,624 14,332 13,062 AL E C Gaston 2 Table 1 18,052 14,082 12,802 AL E C Gaston CS0CBN (3, 4) 26,165 25,669AL E C Gaston 3 Table 1 17,828 15,002 13,638 AL E C Gaston 4 Table 1 18,773 14,000 12,031 AL E C Gaston 5 Table 1 36,094 41,489 58,265 45,632 41,489 AL Gadsden 1 Substitution 4,716 4,751 5,158 5,226 4,751 AL Gadsden 2 Substitution 4,876 4,463 5,374 4,909 4,463 FL Big Bend CS001 (BB01, BB02) 82,191 90,881FL Big Bend BB01 Table 1 27,662 49,712 46,712 FL Big Bend BB02 Table 1 26,387 47,169 44,169 FL Big Bend XS23 (BB03, BB04) 20,303 16,544FL Big Bend BB03 Table 1 26,036 15,759 12,173 FL Big Bend BB04 Substitution 6,400 7,797 4,371 FL Crist 4 Substitution 2,563 3,255 9,953 30,887 3,255 FL Crist 5 Substitution 4,354 3,872 9,374 27,505 3,872 FL Crist 6 Table 1 10,243 14,461 18,695 38,097 14,461 FL Crist 7 Table 1 19,563 29,005 30,846 64,922 29,005 FL Scholz 1 Substitution 1,280 1,877 8,282 27,026 1,877 FL Scholz 2 Substitution 2,112 2,877 8,572 26,429 2,877 GA Arkwright CS001 (1, 2, 3, 4) 3,431 4,272GA Arkwright 1 Substitution 2,437 4,016 1,068 GA Arkwright 2 Substitution 2,240 3,622 1,068 GA Arkwright 3 Substitution 3,944 7,030 1,068 GA Arkwright 4 Substitution 3,159 5,461 1,068 GA Bowen 1BLR Table 1 37,241 34,016 54,838 123,284 34,016 GA Bowen 2BLR Table 1 33,675 28,130 53,329 85,123 28,130 GA Bowen 3BLR Table 1 40,828 47,897 69,862 116,493 47,897 GA Bowen 4BLR Table 1 42,319 35,108 69,852 116,905 35,108 GA Hammond CS001 (1, 2, 3) 8,609 9,842GA Hammond 1 Table 1 8,549 14,228 3,281 GA Hammond 2 Table 1 8,977 15,084 3,281 

B-4, 1
APPENDIX B-4: EMISSIONS AND ALLOWANCE HOLDINGS OF PHASE 1 UNITS

SO2 SO2 1998 Held in Allowances 

Emissions Emissions Allowances Unit Accounts Deducted for 

State Plant Name Stack/Unit ID Unit Type (a) 1997 (b) 1998(b) Allocated (c) as of 3/1/99 Emissions (d) 

GA Hammond 3 Table 1 8,676 14,483 3,280 GA Hammond 4 Table 1 16,571 13,217 36,650 81,025 13,217 GA Harllee Branch CS001 (1, 2) 29,845 32,342GA Harllee Branch 1 Substitution 19,221 34,938 16,171 GA Harllee Branch 2 Substitution 22,735 48,995 16,171 GA Harllee Branch CS002 (3, 4) 53,136 56,643GA Harllee Branch 3 Substitution 31,280 51,834 28,322 GA Harllee Branch 4 Substitution 31,042 50,880 28,321 GA Jack Mcdonough MB1 Table 1 19,386 44,016 14,258 GA Jack Mcdonough CS001 (MB1, MB2) 28,284 28,516GA Jack Mcdonough MB2 Table 1 20,058 46,032 14,258 GA Kraft XS123 (1, 2, 3) 7,267 5,906GA Kraft 1 Substitution 2,265 5,125 1,532 GA Kraft 2 Substitution 2,137 4,794 1,236 GA Kraft 3 Substitution 4,121 7,304 3,138 GA Mcintosh 1 Substitution 6,175 6,716 7,146 11,232 6,716 GA Mitchell 3 Substitution 3,892 4,621 10,792 28,484 4,621 GA Wansley 1 Table 1 34,105 44,760 68,908 109,452 44,760 GA Wansley 2 Table 1 32,258 42,489 63,708 100,342 42,489 GA Yates Y1BR Table 1 130 131 9,533 23,227 131 GA Yates Y2BR Table 1 6,855 17,359 3,433 GA Yates CS001 (Y2BR, Y3BR) 6,412 6,865GA Yates Y3BR Table 1 6,767 17,095 3,432 GA Yates Y4BR Table 1 8,676 21,566 4,568 GA Yates CS002 (Y4BR, Y5BR) 8,923 9,136GA Yates Y5BR Table 1 9,162 23,025 4,568 GA Yates Y6BR Table 1 9,393 11,192 24,108 62,931 11,192 GA Yates Y7BR Table 1 9,702 12,150 20,915 53,043 12,150 IA Burlington 1 Table 1 6,352 5,847 10,428 19,736 5,847 IA Des Moines 11 Table 1 0 0 2,259 0 0 IA George Neal North 1 Table 1 4,040 3,974 2,571 9,598 3,974 IA Milton L Kapp 2 Table 1 4,839 5,282 13,437 35,269 5,282 IA Prairie Creek 4 Table 1 2,985 4,035 7,965 20,558 4,035 IA Riverside 9 Table 1 2,545 1,435 3,885 8,882 1,435 IL Baldwin 1 Table 1 88,439 71,396 46,052 74,791 71,396 IL Baldwin 2 Table 1 92,284 92,968 48,695 97,625 92,968 IL Baldwin 3 Table 1 95,312 120,253 46,644 127,677 120,253 IL Coffeen CS0001 (1, 2) 47,756 49,413IL Coffeen 1 Table 1 12,925 15,570 15,473 

B-4, 2
APPENDIX B-4: EMISSIONS AND ALLOWANCE HOLDINGS OF PHASE 1 UNITS

SO2 SO2 1998 Held in Allowances 

Emissions Emissions Allowances Unit Accounts Deducted for 

State Plant Name Stack/Unit ID Unit Type (a) 1997 (b) 1998(b) Allocated (c) as of 3/1/99 Emissions (d) 

IL Coffeen 2 Table 1 39,102 34,070 33,940 IL Grand Tower 9 Table 1 18,586 9,188 6,479 9,245 9,188 IL Havana 1 Substitution 0 0 34 11 0 IL Havana 2 Substitution 0 5 43 63 5 IL Havana 3 Substitution 0 9 34 61 9 IL Havana 4 Substitution 0 39 34 61 39 IL Havana 5 Substitution 0 41 34 61 41 IL Havana 6 Substitution 0 29 34 61 29 IL Havana 7 Substitution 0 24 34 61 24 IL Havana 8 Substitution 0 30 34 61 30 IL Hennepin CS3 (1, 2) 47,346 46,809IL Hennepin 1 Substitution 9,847 7,847 6,101 IL Hennepin 2 Table 1 20,182 47,246 40,708 IL Hutsonville 5 Substitution 8,640 5,238 9,661 5,442 5,238 IL Hutsonville 6 Substitution 10,982 5,666 9,837 5,917 5,666 IL Joppa Steam CS1 (1, 2) 7,731 8,280IL Joppa Steam 1 Table 1 12,259 36,840 4,140 IL Joppa Steam 2 Table 1 10,487 29,751 4,140 IL Joppa Steam CS2 (3, 4) 7,998 7,937IL Joppa Steam 3 Table 1 11,947 35,908 3,969 IL Joppa Steam 4 Table 1 11,061 32,363 3,968 IL Joppa Steam CS3 (5, 6) 8,472 7,636IL Joppa Steam 5 Table 1 11,119 29,835 3,818 IL Joppa Steam 6 Table 1 10,341 26,723 3,818 IL Kincaid CS0102 (1, 2) 41,096 46,417IL Kincaid 1 Table 1 34,564 25,556 23,208 IL Kincaid 2 Table 1 37,063 24,527 23,209 IL Meredosia 5 Table 1 15,950 10,941 15,227 11,105 10,941 IL Newton 1 Substitution 16,698 7,508 14,599 7,629 7,508 IL Newton 2 Substitution 13,619 14,298 6,346 14,422 14,298 IL Vermilion CS3 (1, 2) 6,208 12,220IL Vermilion 1 Substitution 12,972 6,659 4,631 IL Vermilion 2 Table 1 9,735 8,340 7,589 IL Wood River 1 Substitution 0 1 0 12 1 IN Bailly XS12 (7, 8) 4,736 4,334IN Bailly 7 Table 1 15,826 7,687 1,417 IN Bailly 8 Table 1 21,590 21,946 2,917 IN Breed 1 Table 1 0 0 20,280 30,362 0 IN Cayuga 1 Table 1 56,992 51,345 36,581 62,163 51,345 

B-4, 3
APPENDIX B-4: EMISSIONS AND ALLOWANCE HOLDINGS OF PHASE 1 UNITS

SO2 SO2 1998 Held in Allowances 

Emissions Emissions Allowances Unit Accounts Deducted for 

State Plant Name Stack/Unit ID Unit Type (a) 1997 (b) 1998(b) Allocated (c) as of 3/1/99 Emissions (d) 

IN Cayuga 2 Table 1 51,796 37,593 37,415 57,450 37,593 IN Clifty Creek CS001 (1, 2, 3) 44,612 46,294IN Clifty Creek 1 Table 1 19,620 22,036 15,432 IN Clifty Creek 2 Table 1 19,289 17,908 15,431 IN Clifty Creek 3 Table 1 19,873 18,492 15,431 IN Clifty Creek CS002 (4, 5, 6) 48,844 42,899IN Clifty Creek 4 Table 1 19,552 18,414 14,299 IN Clifty Creek 5 Table 1 18,851 16,400 14,300 IN Clifty Creek 6 Table 1 19,844 29,074 14,300 IN Elmer W Stout 50 Table 1 7,444 6,638 4,253 6,900 6,638 IN Elmer W Stout 60 Table 1 6,561 7,392 5,229 7,756 7,392 IN Elmer W Stout 70 Table 1 22,717 25,931 25,883 26,723 25,931 IN F B Culley XS23 (2, 3) 5,152 7,687IN F B Culley 2 Table 1 4,703 8,331 7,687 IN F B Culley 3 Table 1 18,603 19,603 0 IN Frank E Ratts 1SG1 Table 1 8,566 9,236 9,131 14,363 9,236 IN Frank E Ratts 2SG1 Table 1 7,989 9,393 9,296 12,015 9,393 IN Gibson CS0003 (1, 2) 79,183 94,431IN Gibson 1 Table 1 44,288 60,782 48,712 IN Gibson 2 Table 1 44,956 57,182 45,719 IN Gibson XS34 (3, 4) 49,170 51,189IN Gibson 3 Table 1 45,033 59,533 50,854 IN Gibson 4 Table 1 44,200 90,808 335 IN H T Pritchard CS596 (5, 6) 8,909 7,512IN H T Pritchard 5 Substitution 1,458 2,699 2,479 IN H T Pritchard 6 Table 1 6,325 5,463 5,033 IN Michigan City 12 Table 1 15,262 16,672 25,553 78,549 16,672 IN Petersburg 1 Table 1 2,893 2,247 18,011 2,384 2,247 IN Petersburg 2 Table 1 4,162 4,136 35,496 4,368 4,136 IN R Gallagher CS0001 (1, 2) 25,662 22,954IN R Gallagher 1 Table 1 7,115 12,378 10,208 IN R Gallagher 2 Table 1 7,980 15,442 12,746 IN R Gallagher CS0002 (3, 4) 21,183 27,642IN R Gallagher 3 Table 1 7,159 17,676 14,599 IN R Gallagher 4 Table 1 8,386 15,800 13,043 IN Tanners Creek U4 Table 1 61,344 32,017 27,209 116,844 32,017 IN Wabash River 1 Table 1 1,051 851 5,379 7,716 851 IN Wabash River XS2356 (2, 3, 5, 6) 37,577 48,580IN Wabash River 2 Table 1 3,135 10,380 7,324 

B-4, 4
APPENDIX B-4: EMISSIONS AND ALLOWANCE HOLDINGS OF PHASE 1 UNITS

SO2 SO2 1998 Held in Allowances 

Emissions Emissions Allowances Unit Accounts Deducted for 

State Plant Name Stack/Unit ID Unit Type (a) 1997 (b) 1998(b) Allocated (c) as of 3/1/99 Emissions (d) 

IN Wabash River 3 Table 1 4,111 12,615 7,600 IN Wabash River 5 Table 1 4,023 11,132 9,187 IN Wabash River 6 Table 1 13,462 38,820 24,469 IN Warrick XS123 (1, 2, 3) 79,037 78,964IN Warrick 1 Opt In 30,372 26,927 26,689 IN Warrick 2 Opt In 30,732 28,645 26,233 IN Warrick 3 Opt In 27,668 26,880 26,042 IN Warrick 4 Table 1 39,864 34,078 29,577 36,643 34,078 KS La Cygne 1 Substitution 6,927 6,319 23,489 12,025 6,319 KS Quindaro 2 Table 1 4,052 2,985 4,109 6,694 2,985 KY Coleman C1 Table 1 15,985 13,908 10,954 15,386 13,908 KY Coleman C2 Table 1 18,600 9,677 12,502 11,672 9,677 KY Coleman C3 Table 1 16,037 14,568 12,015 16,120 14,568 KY Cooper CS1 (1, 2) 15,818 17,613KY Cooper 1 Table 1 7,254 12,233 5,812 KY Cooper 2 Table 1 14,917 25,592 11,801 KY E W Brown 1 Table 1 5,869 6,762 6,923 22,811 6,762 KY E W Brown CS003 (2, 3) 30,538 35,473KY E W Brown 2 Table 1 10,623 34,716 11,701 KY E W Brown 3 Table 1 25,413 86,062 23,772 KY East Bend 2 Substitution 13,083 13,064 17,447 17,643 13,064 KY Elmer Smith XS12 (1, 2) 7,688 7,011KY Elmer Smith 1 Table 1 6,348 2,204 2,103 KY Elmer Smith 2 Table 1 14,031 5,007 4,908 KY Ghent 1 Table 1 7,399 7,396 33,701 110,586 7,396 KY Green River 5 Table 1 12,409 14,438 7,614 21,803 14,438 KY H L Spurlock 1 Table 1 15,669 14,941 22,181 46,364 14,941 KY Hmp&L Station 2 H1 Table 1 2,142 2,397 17,920 9,804 2,397 KY Hmp&L Station 2 H2 Table 1 2,482 2,130 17,085 7,808 2,130 KY Paradise 3 Table 1 173,285 126,946 57,613 216,485 126,946 KY R D Green G1 Substitution 1,004 1,828 5,041 9,195 1,828 KY R D Green G2 Substitution 1,323 2,136 5,827 10,674 2,136 KY Shawnee 10 Table 1 2,204 1,560 9,902 18,052 1,560 MA Brayton Point 2 Compensating 10,646 9,744 15,838 29,975 9,744 MA Mount Tom 1 Substitution 9,742 8,417 10,708 14,921 8,417 MD C P Crane 1 Table 1 12,740 15,224 10,058 64,309 15,224 MD C P Crane 2 Table 1 17,050 13,636 8,987 17,202 13,636 MD Chalk Point CSE12 (1, 2) 39,789 44,721MD Chalk Point 1 Table 1 21,333 27,900 23,068 

B-4, 5
APPENDIX B-4: EMISSIONS AND ALLOWANCE HOLDINGS OF PHASE 1 UNITS

SO2 SO2 1998 Held in Allowances 

Emissions Emissions Allowances Unit Accounts Deducted for 

State Plant Name Stack/Unit ID Unit Type (a) 1997 (b) 1998(b) Allocated (c) as of 3/1/99 Emissions (d) 

MD Chalk Point 2 Table 1 23,690 28,253 21,653 MD Chalk Point 3 Substitution 2,716 7,732 9,000 19,000 7,732 MD Morgantown 1 Table 1 39,650 34,953 34,332 45,499 34,953 MD Morgantown 2 Table 1 33,341 44,953 37,467 56,019 44,953 MD R P Smith 9 Substitution 71 117 386 673 117 MD R P Smith 11 Substitution 2,264 2,262 3,128 4,408 2,262 MI Dan E Karn 2 Substitution 9,694 8,426 10,984 11,276 8,426 MI J H Campbell CS0009 (1, 2) 21,219 22,693MI J H Campbell 1 Table 1 18,773 8,804 8,004 MI J H Campbell 2 Table 1 22,453 16,158 14,689 MI J R Whiting 3 Substitution 4,801 4,755 5,498 5,673 4,755 MN High Bridge CS0001 (3, 4, 5, 6) 3,848 4,044MN High Bridge 3 Substitution 299 3,349 251 MN High Bridge 4 Substitution 242 1,946 251 MN High Bridge 5 Substitution 410 2,891 1,279 MN High Bridge 6 Table 1 4,158 10,788 2,263 MN Sherburne County CS1 (1, 2) 9,132 8,958MN Sherburne County 1 Substitution 4,681 15,649 4,216 MN Sherburne County 2 Substitution 4,727 16,242 4,742 MO Asbury 1 Table 1 9,236 8,212 15,764 37,704 8,212 MO Hawthorn 5 Substitution 9,297 7,106 6,927 7,461 7,106 MO James River 3 Substitution 1,164 1,409 2,536 3,910 1,409 MO James River 4 Substitution 1,780 1,708 4,304 5,144 1,708 MO James River 5 Table 1 3,633 2,810 4,722 3,488 2,810 MO Labadie 1 Table 1 12,452 15,654 39,055 16,711 15,654 MO Labadie 2 Table 1 15,063 12,987 36,718 14,237 12,987 MO Labadie 3 Table 1 12,635 14,602 39,249 15,801 14,602 MO Labadie 4 Table 1 13,777 14,354 34,994 15,392 14,354 MO Meramec 1 Substitution 3,147 1,670 1,816 2,871 1,670 MO Meramec 2 Substitution 3,388 1,541 1,948 2,873 1,541 MO Meramec 3 Substitution 3,364 3,706 4,166 5,516 3,706 MO Montrose 1 Table 1 2,705 4,072 7,196 4,276 4,072 MO Montrose CS023 (2, 3) 6,684 8,875MO Montrose 2 Table 1 7,984 4,362 4,153 MO Montrose 3 Table 1 9,824 4,974 4,722 MO New Madrid 1 Table 1 8,924 8,735 27,497 13,202 8,735 MO New Madrid 2 Table 1 10,474 9,018 31,625 33,276 9,018 MO Rush Island 1 Substitution 13,484 13,485 26,935 14,684 13,485 MO Rush Island 2 Substitution 11,659 13,924 30,146 15,026 13,924 

B-4, 6
APPENDIX B-4: EMISSIONS AND ALLOWANCE HOLDINGS OF PHASE 1 UNITS

SO2 SO2 1998 Held in Allowances 

Emissions Emissions Allowances Unit Accounts Deducted for 

State Plant Name Stack/Unit ID Unit Type (a) 1997 (b) 1998(b) Allocated (c) as of 3/1/99 Emissions (d) 

MO Sibley CS0001 (1, 2, 3) 19,839 27,056MO Sibley 1 Substitution 2,782 5,521 2,705 MO Sibley 2 Substitution 3,332 7,700 2,706 MO Sibley 3 Table 1 15,170 22,127 21,645 MO Sioux 1 Table 1 30,140 18,885 21,976 20,106 18,885 MO Sioux 2 Table 1 24,968 23,062 23,067 24,083 23,062 MO Southwest 1 Substitution 3,785 6,837 3,906 7,161 6,837 MO Thomas Hill MB1 Table 1 3,382 3,080 9,980 11,078 3,080 MO Thomas Hill MB2 Table 1 4,978 4,722 18,880 28,282 4,722 MO Thomas Hill MB3 Substitution 11,224 9,916 14,011 16,798 9,916 MS Jack Watson 4 Table 1 11,749 18,528 17,439 25,577 18,528 MS Jack Watson 5 Table 1 30,551 32,033 35,734 44,344 32,033 MS R D Morrow 1 Substitution 5,072 4,267 4,571 5,087 4,267 MS R D Morrow 2 Substitution 4,255 4,383 5,002 7,152 4,383 MS Victor J Daniel Jr 1 Substitution 11,632 8,109 9,427 10,937 8,109 NH Merrimack 1 Table 1 13,509 12,126 9,922 12,457 12,126 NH Merrimack 2 Table 1 26,144 22,794 21,421 23,047 22,794 NJ B L England 1 Table 1 15,485 15,694 8,822 18,159 15,694 NJ B L England 2 Table 1 1,787 1,084 14,886 2,254 1,084 NY Dunkirk CS0003 (3, 4) 34,072 37,527NY Dunkirk 3 Table 1 12,268 34,855 20,640 NY Dunkirk 4 Table 1 13,690 18,292 16,887 NY Greenidge 6 Table 1 8,126 9,027 7,342 17,274 9,027 NY Milliken XS12 (1, 2) 5,620 8,572NY Milliken 1 Table 1 10,876 73,288 4,073 NY Milliken 2 Table 1 12,083 26,732 4,499 NY Northport 1 Table 1 4,868 2,764 19,289 29,053 2,764 NY Northport 2 Table 1 2,661 4,866 23,476 18,693 4,866 NY Northport 3 Table 1 4,279 10,502 25,783 24,616 10,502 NY Northport 4 Substitution 822 1,136 5,516 14,797 1,136 NY Oswego 4 Substitution 0 0 371 1,492 0 NY Oswego 5 Substitution 0 3,982 12,365 36,993 3,982 NY Oswego 6 Substitution 1,080 1,121 4,499 12,773 1,121 NY Port Jefferson 3 Table 1 1,890 4,185 10,194 14,406 4,185 NY Port Jefferson 4 Table 1 1,602 3,171 12,006 18,011 3,171 NY Roseton 1 Substitution 4,380 10,538 19,147 19,147 10,538 NY Roseton 2 Substitution 7,132 14,192 16,872 16,872 14,192 OH Acme 13 Substitution 0 0 0 0 0 OH Acme 14 Substitution 0 0 12 0 0 

B-4, 7
APPENDIX B-4: EMISSIONS AND ALLOWANCE HOLDINGS OF PHASE 1 UNITS

SO2 SO2 1998 Held in Allowances 

Emissions Emissions Allowances Unit Accounts Deducted for 

State Plant Name Stack/Unit ID Unit Type (a) 1997 (b) 1998(b) Allocated (c) as of 3/1/99 Emissions (d) 

OH Acme 15 Substitution 0 0 16 0 0 OH Acme 16 Substitution 0 0 1,930 0 0 OH Acme 91 Substitution 0 0 740 0 0 OH Acme 92 Substitution 0 0 662 0 0 OH Ashtabula 7 Table 1 39,662 26,164 18,351 28,835 26,164 OH Ashtabula CS1 (8, 9, 10, 11) 6,942 2,048OH Ashtabula 8 Substitution 7,487 0 0 OH Ashtabula 9 Substitution 7,016 7,016 0 OH Ashtabula 10 Substitution 6,155 812 637 OH Ashtabula 11 Substitution 6,452 1,745 1,411 OH Avon Lake 9 Substitution 483 0 8,763 64 0 OH Avon Lake 10 Substitution 4,274 1,222 7,879 1,527 1,222 OH Avon Lake 11 Table 1 0 0 12,771 0 0 OH Avon Lake 12 Table 1 28,037 27,714 33,413 40,913 27,714 OH Bay Shore CS5 (1, 2, 3, 4) 13,874 11,472OH Bay Shore 1 Substitution 7,414 7,629 2,490 OH Bay Shore 2 Substitution 6,957 7,248 2,627 OH Bay Shore 3 Substitution 7,585 7,876 2,799 OH Bay Shore 4 Substitution 12,481 12,986 3,556 OH Cardinal 1 Table 1 84,875 95,520 37,568 100,301 95,520 OH Cardinal 2 Table 1 58,818 33,017 42,008 52,486 33,017 OH Conesville CS012 (1, 2) 31,975 30,089OH Conesville 1 Table 1 4,615 14,778 14,074 OH Conesville 2 Table 1 5,360 16,816 16,015 OH Conesville 3 Table 1 16,424 17,937 6,029 18,834 17,937 OH Conesville 4 Table 1 83,428 72,035 53,463 73,920 72,035 OH Eastlake 1 Table 1 16,379 11,186 8,551 13,392 11,186 OH Eastlake 2 Table 1 15,487 11,992 9,471 14,120 11,992 OH Eastlake 3 Table 1 16,084 12,985 10,984 14,599 12,985 OH Eastlake 4 Table 1 26,322 18,497 15,906 21,962 18,497 OH Eastlake 5 Table 1 53,952 56,011 37,349 67,970 56,011 OH Edgewater 11 Substitution 0 0 1,062 0 0 OH Edgewater 12 Substitution 0 0 1,145 645 0 OH Edgewater 13 Table 1 3 7 5,536 33 7 OH Gen J M Gavin 1 Table 1 16,854 15,085 113,172 15,839 15,085 OH Gen J M Gavin 2 Table 1 16,812 18,718 115,070 19,653 18,718 OH Gorge 25 Substitution 0 0 2,503 2,503 0 OH Gorge 26 Substitution 0 0 2,791 2,791 0 OH J M Stuart 1 Substitution 23,885 27,024 41,189 42,720 27,024 

B-4, 8
APPENDIX B-4: EMISSIONS AND ALLOWANCE HOLDINGS OF PHASE 1 UNITS

SO2 SO2 1998 Held in Allowances 

Emissions Emissions Allowances Unit Accounts Deducted for 

State Plant Name Stack/Unit ID Unit Type (a) 1997 (b) 1998(b) Allocated (c) as of 3/1/99 Emissions (d) 

OH J M Stuart 2 Substitution 28,883 29,520 39,041 38,961 29,520 OH J M Stuart 3 Substitution 25,127 23,211 38,712 37,597 23,211 OH J M Stuart 4 Substitution 26,949 23,603 40,925 38,323 23,603 OH Kyger Creek CS001 (1, 2, 3, 4, 5) 111,419 119,171OH Kyger Creek 1 Table 1 18,773 24,335 23,835 OH Kyger Creek 2 Table 1 18,072 24,335 23,834 OH Kyger Creek 3 Table 1 17,439 24,335 23,834 OH Kyger Creek 4 Table 1 18,218 24,335 23,834 OH Kyger Creek 5 Table 1 18,247 24,335 23,834 OH Lake Shore 18 Substitution 497 1,811 4,508 3,709 1,811 OH Lake Shore 91 Substitution 0 0 44 0 0 OH Lake Shore 92 Substitution 0 0 80 0 0 OH Lake Shore 93 Substitution 0 0 62 0 0 OH Lake Shore 94 Substitution 0 0 102 0 0 OH Miami Fort 6 Table 1 12,475 24,491 16,306 OH Miami Fort 7 Table 1 38,666 36,473 42,216 50,633 36,473 OH Miami Fort CS056 (5-1, 5-2, 6) 10,087 19,614OH Miami Fort 5-1 Table 1 417 2,513 1,654 OH Miami Fort 5-2 Table 1 417 2,513 1,654 OH Muskingum River CS014 (1, 2, 3, 4) 161,924 152,316OH Muskingum River 1 Table 1 16,312 37,786 35,987 OH Muskingum River 2 Table 1 15,533 38,320 36,495 OH Muskingum River 3 Table 1 15,293 42,607 40,578 OH Muskingum River 4 Table 1 12,914 41,219 39,256 OH Muskingum River 5 Table 1 21,872 15,307 44,364 114,045 15,307 OH Niles XS12 (1, 2) 13,340 21,636OH Niles 1 Table 1 7,608 9,801 6,878 OH Niles 2 Table 1 9,975 16,325 14,758 OH Picway 9 Table 1 16,843 13,385 5,404 14,221 13,385 OH Poston 1 Substitution 0 0 0 0 0 OH Poston 2 Substitution 0 0 0 0 0 OH Poston 3 Substitution 0 0 0 0 0 OH R E Burger CS0001 (1, 2, 3, 4, 5, 6, 7, 8) 46,842 38,543OH R E Burger 1 Substitution 2,820 0 0 OH R E Burger 2 Substitution 2,751 0 0 OH R E Burger 3 Substitution 2,891 1 0 OH R E Burger 4 Substitution 2,956 2,956 0 OH R E Burger 5 Table 1 3,371 4,389 0 OH R E Burger 6 Table 1 3,371 2,854 39 

B-4, 9
APPENDIX B-4: EMISSIONS AND ALLOWANCE HOLDINGS OF PHASE 1 UNITS

SO2 SO2 1998 Held in Allowances 

Emissions Emissions Allowances Unit Accounts Deducted for 

State Plant Name Stack/Unit ID Unit Type (a) 1997 (b) 1998(b) Allocated (c) as of 3/1/99 Emissions (d) 

OH R E Burger 7 Table 1 11,818 22,782 20,389 OH R E Burger 8 Table 1 13,626 20,697 18,115 OH Toronto 9 Substitution 0 0 5,315 5,315 0 OH Toronto 10 Substitution 0 0 9,505 9,505 0 OH Toronto 11 Substitution 0 0 10,274 274 0 OH W H Sammis 5 Table 1 16,619 16,812 26,496 31,377 16,812 OH W H Sammis 6 Table 1 33,154 20,352 43,773 48,619 20,352 OH W H Sammis 7 Table 1 30,208 45,828 47,380 87,696 45,828 OH Walter C Beckjord 5 Table 1 14,542 20,329 9,811 30,526 20,329 OH Walter C Beckjord 6 Table 1 33,099 39,455 25,235 48,925 39,455 PA Armstrong 1 Table 1 16,282 18,227 14,031 32,747 18,227 PA Armstrong 2 Table 1 16,847 17,658 15,024 33,350 17,658 PA Bruce Mansfield 1 Substitution 6,555 7,527 10,510 20,720 7,527 PA Bruce Mansfield 2 Substitution 7,123 6,765 11,537 22,827 6,765 PA Brunner Island CS102 (1, 2) 44,391 48,020PA Brunner Island 1 Table 1 27,030 53,949 21,817 PA Brunner Island 2 Table 1 30,282 57,671 26,203 PA Brunner Island 3 Table 1 52,349 47,679 52,404 115,628 47,679 PA Cheswick 1 Table 1 47,510 32,177 38,139 43,171 32,177 PA Conemaugh 1 Table 1 3,754 3,874 82,006 14,930 3,874 PA Conemaugh 2 Table 1 3,502 4,347 90,904 15,136 4,347 PA Hatfield's Ferry XS123 (1, 2, 3) 138,630 150,868PA Hatfield's Ferry 1 Table 1 36,835 55,009 55,009 PA Hatfield's Ferry 2 Table 1 36,338 47,719 47,719 PA Hatfield's Ferry 3 Table 1 39,210 48,140 48,140 PA Martins Creek CS102 (1, 2) 23,661 15,834PA Martins Creek 1 Table 1 12,327 36,073 8,211 PA Martins Creek 2 Table 1 12,483 34,780 7,623 PA Martins Creek 3 Substitution 2,082 4,742 12,553 33,135 4,742 PA Martins Creek 4 Substitution 1,938 4,347 11,548 29,690 4,347 PA Mitchell 33 Substitution 1,080 1,050 1,101 2,322 1,050 PA New Castle 1 Substitution 0 0 1,367 1,367 0 PA New Castle 2 Substitution 0 0 1,520 1,520 0 PA Portland 1 Table 1 11,574 9,772 5,784 51,498 9,772 PA Portland 2 Table 1 17,463 12,126 9,961 14,405 12,126 PA Shawville 1 Table 1 15,230 12,864 10,048 14,698 12,864 PA Shawville 2 Table 1 15,609 12,365 10,048 13,823 12,365 PA Shawville CS1 (3, 4) 33,064 33,535PA Shawville 3 Table 1 13,846 17,695 16,855 

B-4, 10
APPENDIX B-4: EMISSIONS AND ALLOWANCE HOLDINGS OF PHASE 1 UNITS

SO2 SO2 1998 Held in Allowances 

Emissions Emissions Allowances Unit Accounts Deducted for 

State Plant Name Stack/Unit ID Unit Type (a) 1997 (b) 1998(b) Allocated (c) as of 3/1/99 Emissions (d) 

PA Shawville 4 Table 1 13,700 17,430 16,680 PA Sunbury 3 Table 1 11,343 10,307 8,530 22,698 10,307 PA Sunbury 4 Table 1 11,326 11,970 11,149 24,147 11,970 TN Allen 1 Table1 6,754 5,671 14,917 25,192 5,671 TN Allen 2 Table1 7,134 7,378 16,329 27,605 7,378 TN Allen 3 Table1 7,436 7,162 15,258 29,340 7,162 TN Cumberland 1 Table 1 9,846 10,610 114,325 215,879 10,610 TN Cumberland 2 Table 1 11,122 9,891 126,157 218,813 9,891 TN DuPont Johnsonville JVD1 Opt In 0 0 1,778 0 0 TN DuPont Johnsonville JVD2 Opt In 0 0 1,778 0 0 TN DuPont Johnsonville JVD3 Opt In 0 0 1,777 0 0 TN DuPont Johnsonville JVD4 Opt In 0 0 1,777 0 0 TN Gallatin CSGA12 (1, 2) 50,974 40,664TN Gallatin 1 Table 1 17,400 22,769 22,320 TN Gallatin 2 Table 1 16,855 19,398 18,344 TN Gallatin CSGA34 (3, 4) 66,129 45,551TN Gallatin 3 Table 1 19,493 25,693 25,188 TN Gallatin 4 Table 1 20,701 24,089 20,363 TN Johnsonville CSJO10 (1, 2, 3, 4, 5, 6, 7, 8, 9, 10) 115,938 114,588TN Johnsonville 1 Table 1 7,585 17,267 12,567 TN Johnsonville 2 Table 1 7,828 13,527 9,679 TN Johnsonville 3 Table 1 8,189 13,891 8,448 TN Johnsonville 4 Table 1 7,780 15,471 11,680 TN Johnsonville 5 Table 1 8,023 10,386 10,179 TN Johnsonville 6 Table 1 7,682 11,248 11,024 TN Johnsonville 7 Table 1 8,744 11,955 11,718 TN Johnsonville 8 Table 1 8,471 12,916 12,659 TN Johnsonville 9 Table 1 6,894 14,890 14,594 TN Johnsonville 10 Table 1 7,351 12,493 12,040 WI Alma CS1 (B1, B2, B3, B4, B5) 5,608 6,517WI Alma B1 Opt In 537 537 466 WI Alma B2 Opt In 518 518 424 WI Alma B3 Opt In 455 455 397 WI Alma B4 Substitution 2,207 8,702 2,195 WI Alma B5 Substitution 3,624 17,637 3,035 WI Edgewater 3 Substitution 1,620 1,973 4,493 13,704 1,973 WI Edgewater 4 Table 1 7,968 8,391 24,099 25,802 8,391 WI Genoa 1 Table 1 12,750 9,031 22,103 31,624 9,031 WI J P Madgett B1 Substitution 4,946 5,223 6,407 11,701 5,223 

B-4, 11
APPENDIX B-4: EMISSIONS AND ALLOWANCE HOLDINGS OF PHASE 1 UNITS

SO2 SO2 1998 Held in Allowances 

Emissions Emissions Allowances Unit Accounts Deducted for 

State Plant Name Stack/Unit ID Unit Type (a) 1997 (b) 1998(b) Allocated (c) as of 3/1/99 Emissions (d) 

WI Nelson Dewey CS1 (1, 2) 6,092 10,861WI Nelson Dewey 1 Table 1 5,852 11,590 5,195 WI Nelson Dewey 2 Table 1 6,504 13,779 5,666 WI North Oak Creek 1 Table 1 0 0 5,083 0 0 WI North Oak Creek 2 Table 1 0 0 5,005 0 0 WI North Oak Creek 3 Table 1 0 0 5,229 0 0 WI North Oak Creek 4 Table 1 0 0 6,154 0 0 WI Pulliam CS56 (5, 6) 2,141 1,884WI Pulliam 5 Substitution 2,097 970 810 WI Pulliam 6 Substitution 2,844 1,290 1,074 WI Pulliam 7 Substitution 1,540 1,569 7,317 1,900 1,569 WI Pulliam 8 Table 1 2,264 2,283 7,312 2,700 2,283 WI Rock River 1 Substitution 1,560 1,532 5,398 17,058 1,532 WI Rock River 2 Substitution 1,776 1,898 4,034 11,537 1,898 WI South Oak Creek CS3 (5, 6) 15,452 16,781WI South Oak Creek 5 Table 1 9,416 7,128 6,480 WI South Oak Creek 6 Table 1 11,723 11,331 10,301 WI South Oak Creek CS4 (7, 8) 25,934 26,529WI South Oak Creek 7 Table 1 15,754 15,327 13,934 WI South Oak Creek 8 Table 1 15,375 13,854 12,595 WI Weston 1 Substitution 1,318 1,111 1,579 1,300 1,111 WI Weston 2 Substitution 1,678 1,922 3,580 2,300 1,922 WV Albright 1 Substitution 1,578 2,202 4,831 5,836 2,202 WV Albright 2 Substitution 1,682 1,929 5,024 4,970 1,929 WV Albright 3 Table1 9,380 7,228 11,684 20,618 7,228 WV Fort Martin 1 Table 1 42,733 41,641 40,496 64,608 41,641 WV Fort Martin 2 Table 1 44,413 37,663 40,116 85,160 37,663 WV Harrison XS123 (1, 2, 3) 6,298 6,934WV Harrison 1 Table 1 68,078 4,149 2,177 WV Harrison 2 Table 1 64,488 4,197 2,403 WV Harrison 3 Table 1 57,730 4,317 2,354 WV Kammer CS013 (1, 2, 3) 126,273 108,618WV Kammer 1 Table 1 18,247 38,749 36,904 WV Kammer 2 Table 1 18,948 36,653 34,908 WV Kammer 3 Table 1 16,932 38,646 36,806 WV Mitchell CS012 (1, 2) 57,239 59,330WV Mitchell 1 Table 1 42,823 29,811 28,392 WV Mitchell 2 Table 1 44,312 32,485 30,938 WV Mt Storm CS0 (1, 2) 92,716 106,759WV Mt Storm 1 Table 1 42,570 114,600 53,380 

B-4, 12
APPENDIX B-4: EMISSIONS AND ALLOWANCE HOLDINGS OF PHASE 1 UNITS

SO2 SO2 1998 Held in Allowances 

Emissions Emissions Allowances Unit Accounts Deducted for 

State Plant Name Stack/Unit ID Unit Type (a) 1997 (b) 1998(b) Allocated (c) as of 3/1/99 Emissions (d) 

WV Mt Storm 2 Table 1 34,644 96,588 53,379 WV Mt Storm 3 Table 1 4,052 4,576 56,589 59,130 4,576 WV Rivesville 7 Substitution 235 624 1,009 1,690 624 WV Rivesville 8 Substitution 1,234 1,995 3,059 4,635 1,995 WV Willow Island 2 Substitution 8,067 7,870 7,765 17,190 7,870 

NOTES:(a) Identifies the affected unit as listed in Table 1, or as a substitution, compensating, or opt-in unit.(b) Both 1997 and 1998 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 1998 emissions for units that are not connected to a common stack. For units sharing a common stack, an apportio 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-1: List of Averaging Plans and Results in 1998

C-1, 1

Company ORIS Code Plant Name, State and Units Plant Limit P

R

Allegheny Power System 3942 Albright WV 1-3 0.49 

3178 Armstrong PA 1, 23944 Harrison WV 1-33943 Fort Martin WV 13181 Mitchell PA 336004 Pleasants PA 1, 21570 R P Smith PA 9, 11

Ameren Services 862 Grand Tower IL 07-09 0.45 

863 Hutsonville IL 05, 06864 Meredosia IL 01-056017 Newton IL 1, 2

Ameren Services 2103 Labadie MO 1-4 0.45 

2104 Meramec MO 1-46155 Rush Island MO 1, 2

Cinergy Corp. 1001 Cayuga IN 1, 2 0.48 

6018 East Bend 26113 Gibson IN 1-42832 Miami Fort OH 61008 R Gallagher IN 1-41010 Wabash River IN 2, 3, 5, 62830 Walter C Beckjord 5, 6

Dairyland PowerCooperative

4140 Alma WI B4, B5 0.48 4143 Genoa WI 14271 J P Madgett WI B1
Appendix C-1: List of Averaging Plans and Results in 1998

Company ORIS Code Plant Name, State and Units Plant Limit P

R

C-1, 2

East Kentucky PowerCooperative 1384 Cooper KY 1, 2 0.50 FirstEnergy 6094 Bruce Mansfield PA 1, 2 0.50 

2857 Edgewater OH 132858 Gorge OH 25, 263138 New Castle PA 1, 22867 Toronto OH 10, 112864 R E Burger OH 7, 8 2866 W H Sammis OH 5, 6

GPU Generation, Inc. 3113 Portland PA 1, 2 0.45 Hoosier Energy Rec., Inc. 1043 Frank E Ratts IN 1SG1, 2SG1 0.50 Illinois Power Company 889 Baldwin IL 3 0.45 

892 Hennepin IL 2897 Vermilion IL 1, 2

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

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

LG&E Energy Corporation

1355 E W Brown KY 1-31356 Ghent KY 1 0.46 1357 Green River KY 5
Appendix C-1: List of Averaging Plans and Results in 1998

Company ORIS Code Plant Name, State and Units Plant Limit P

R

C-1, 3

NGE Generation, Inc. 2527 Greenidge NY 6 0.45 

2535 Milliken NY 1, 2

Northern States PowerCompany

1912 High Bridge MN 3-6 0.46 6090 Sherburne County MN 1, 2

PP&L 3140 Brunner Island PA 1-3 0.46 

3148 Martins Creek PA 1, 23152 Sunbury PA 3, 4

South Mississippi Elec.Power Assoc. 6061 R D Morrow MS 1, 2 0.50 Southern Company

26 E C Gaston AL 1-5

0.48 

7 Gadsden AL 1-2

Southern Company 699 Arkwright GA 1-4 0.46 

703 Bowen GA 1BLR - 4BLR708 Hammond GA 1-4709 Harllee Branch GA 2710 Jack McDonough GA MB1,

MB2

733 Kraft GA 1-36124 McIntosh GA 1727 Mitchell GA 36257 Scherer GA 36052 Wansley GA 1, 2728 Yates GA Y1BR - Y7BR
Appendix C-1: List of Averaging Plans and Results in 1998

Company ORIS Code Plant Name, State and Units Plant Limit P

R

C-1, 4

Southern Company 641 Crist FL 4-7 0.48 

2049 Jack Watson MS 4, 5642 Scholz FL1, 26073 Victor J Daniel Jr MS 1, 2

Springfield (MO), CityUtilities of

2161 James River MO 3-5 0.50 6195 Southwest MO 1

TVA

47 Colbert AL 1-5

0.48 

3403 Gallatin TN 1-43406 Johnsonville TN 1-10

Wisconsin Electric PowerCompany

4040 Port Washington WI 1-4 0.48 4041 South Oak Creek WI 5-84042 Valley WI 1-4

Wisconsin Power & LightCompany

1104 Burlington IA 1 0.47 1073 Prairie Creek IA 4

Wisconsin Public ServiceCorp.

4072 Pulliam WI 7, 8 0.48 4078 Weston WI 1-3
Appendix C-2: Compliance Results for the 265 Phase I NOx Affected Units in 1998

C-2, 1

1998

ST Plant Name Operating Utility

ORISCode Boiler Compliance Approach

Emission

Limit

Actual

Emission

Rate

AE

Avg

L

AL Colbert TVA 47 1 Averaging Plan 0.50 0.45 0AL Colbert TVA 47 2 Averaging Plan 0.50 0.45 0AL Colbert TVA 47 3 Averaging Plan 0.50 0.45 0AL Colbert TVA 47 4 Averaging Plan 0.50 0.45 0AL Colbert TVA 47 5 Averaging Plan 0.50 0.38 0AL E C Gaston Alabama Power Co 26 1 Averaging Plan 0.50 0.43 0AL E C Gaston Alabama Power Co 26 2 Averaging Plan 0.50 0.43 0AL E C Gaston Alabama Power Co 26 3 Averaging Plan 0.50 0.45 0AL E C Gaston Alabama Power Co 26 4 Averaging Plan 0.50 0.45 0AL E C Gaston Alabama Power Co 26 5 Averaging Plan 0.45 0.47 0AL Gadsden Alabama Power Co 7 1 Averaging Plan 0.45 0.64 0AL Gadsden Alabama Power Co 7 2 Averaging Plan 0.45 0.64 0FL Big Bend Tampa Electric Co 645 BB04 Standard Limitation 0.45 0.40 FL Crist Gulf Power Co 641 4 Averaging Plan 0.45 0.43 0FL Crist Gulf Power Co 641 5 Averaging Plan 0.45 0.55 0FL Crist Gulf Power Co 641 6 Averaging Plan 0.50 0.46 0FL Crist Gulf Power Co 641 7 Averaging Plan 0.50 0.49 0FL Scholz Gulf Power Co 642 1 Averaging Plan 0.50 0.70 0FL Scholz Gulf Power Co 642 2 Averaging Plan 0.50 0.71 0GA Arkwright Georgia Power Co 699 1 Averaging Plan 0.45 0.72 0GA Arkwright Georgia Power Co 699 2 Averaging Plan 0.45 0.72 0GA Arkwright Georgia Power Co 699 3 Averaging Plan 0.50 0.72 0GA Arkwright Georgia Power Co 699 4 Averaging Plan 0.50 0.72 0GA Bowen Georgia Power Co 703 1BLR Averaging Plan 0.45 0.42 0GA Bowen Georgia Power Co 703 2BLR Averaging Plan 0.45 0.44 0GA Bowen Georgia Power Co 703 3BLR Averaging Plan 0.45 0.42 0GA Bowen Georgia Power Co 703 4BLR Averaging Plan 0.45 0.43 0GA Hammond Georgia Power Co 708 1 Averaging Plan 0.50 0.83 0GA Hammond Georgia Power Co 708 2 Averaging Plan 0.50 0.83 0GA Hammond Georgia Power Co 708 3 Averaging Plan 0.50 0.83 0GA Hammond Georgia Power Co 708 4 Averaging Plan 0.50 0.44 0GA Harllee Branch Georgia Power Co 709 2 Averaging Plan 0.50 0.71 0
Appendix C-2: Compliance Results for the 265 Phase I NOx Affected Units in 1998

1998

ST Plant Name Operating Utility

ORISCode Boiler Compliance Approach

Emission

Limit

Actual

Emission

Rate

AE

Avg

L

C-2, 2

GA Jack McDonough Georgia Power Co 710 MB1 Averaging Plan 0.45 0.41 0GA Jack McDonough Georgia Power Co 710 MB2 Averaging Plan 0.45 0.41 0GA Kraft Savannah Electric & Power 733 1 Averaging Plan 0.45 0.62 0GA Kraft Savannah Electric & Power 733 2 Averaging Plan 0.45 0.62 0GA Kraft Savannah Electric & Power 733 3 Averaging Plan 0.45 0.62 0GA Mcintosh Savannah Electric & Power 6124 1 Averaging Plan 0.50 0.95 0GA Mitchell Georgia Power Co 727 3 Averaging Plan 0.45 0.56 0GA Scherer Georgia Power Co 6257 3 Averaging Plan 0.45 0.29 0GA Wansley Georgia Power Co 6052 1 Averaging Plan 0.45 0.39 0GA Wansley Georgia Power Co 6052 2 Averaging Plan 0.45 0.40 0GA Yates Georgia Power Co 728 Y1BR Averaging Plan 0.45 0.47 0GA Yates Georgia Power Co 728 Y2BR Averaging Plan 0.45 0.50 0GA Yates Georgia Power Co 728 Y3BR Averaging Plan 0.45 0.50 0GA Yates Georgia Power Co 728 Y4BR Averaging Plan 0.45 0.39 0GA Yates Georgia Power Co 728 Y5BR Averaging Plan 0.45 0.39 0GA Yates Georgia Power Co 728 Y6BR Averaging Plan 0.45 0.33 0GA Yates Georgia Power Co 728 Y7BR Averaging Plan 0.45 0.32 0IA Burlington IES Utilities, Inc. 1104 1 Averaging Plan 0.45 0.23 0IA Milton L Kapp Interstate Power Co 1048 2 Standard Limitation 0.45 0.36 IA Prairie Creek IES Utilities, Inc. 1073 4 Averaging Plan 0.50 0.33 0IA Riverside MidAmerican Energy Company 1081 9 Standard Limitation 0.45 0.36 IL Baldwin Illinois Power Co 889 3 Averaging Plan 0.45 0.35 0IL Grand Tower CIPSCO 862 7 Averaging Plan 0.50 0.70 0IL Grand Tower CIPSCO 862 8 Averaging Plan 0.50 0.72 0IL Grand Tower CIPSCO 862 9 Averaging Plan 0.50 0.56 0IL Hennepin Illinois Power Co 892 2 Averaging Plan 0.45 0.54 0IL Hutsonville CIPSCO 863 5 Averaging Plan 0.45 0.53 0IL Hutsonville CIPSCO 863 6 Averaging Plan 0.45 0.49 0IL Joppa Steam Electric Energy Inc 887 1 Standard Limitation 0.45 0.20 IL Joppa Steam Electric Energy Inc 887 2 Standard Limitation 0.45 0.20 IL Joppa Steam Electric Energy Inc 887 3 Standard Limitation 0.45 0.20 IL Joppa Steam Electric Energy Inc 887 4 Standard Limitation 0.45 0.20 
Appendix C-2: Compliance Results for the 265 Phase I NOx Affected Units in 1998

1998

ST Plant Name Operating Utility

ORISCode Boiler Compliance Approach

Emission

Limit

Actual

Emission

Rate

AE

Avg

L

C-2, 3

IL Joppa Steam Electric Energy Inc 887 5 Standard Limitation 0.45 0.20 IL Joppa Steam Electric Energy Inc 887 6 Standard Limitation 0.45 0.20 IL Meredosia CIPSCO 864 1 Averaging Plan 0.45 0.47 0IL Meredosia CIPSCO 864 2 Averaging Plan 0.45 0.47 0IL Meredosia CIPSCO 864 3 Averaging Plan 0.45 0.47 0IL Meredosia CIPSCO 864 4 Averaging Plan 0.45 0.47 0IL Meredosia CIPSCO 864 5 Averaging Plan 0.45 0.52 0IL Newton CIPSCO 6017 1 Averaging Plan 0.45 0.21 0IL Newton CIPSCO 6017 2 Averaging Plan 0.45 0.36 0IL Vermilion Illinois Power Co 897 1 Averaging Plan 0.45 0.44 0IL Vermilion Illinois Power Co 897 2 Averaging Plan 0.45 0.44 0IN Cayuga PSI Energy, Inc. 1001 1 Averaging Plan 0.45 0.32 0IN Cayuga PSI Energy, Inc. 1001 2 Averaging Plan 0.45 0.33 0IN Elmer W Stout Indianapolis Power & Light 990 50 Averaging Plan 0.45 0.35 0IN Elmer W Stout Indianapolis Power & Light 990 60 Averaging Plan 0.45 0.38 0IN Elmer W Stout Indianapolis Power & Light 990 70 Averaging Plan 0.45 0.34 0IN F B Culley Southern Indiana Gas & Elec 1012 2 Standard Limitation 0.50 0.46 IN F B Culley Southern Indiana Gas & Elec 1012 3 Standard Limitation 0.50 0.46 IN Frank E Ratts Hoosier Energy Rec, Inc. 1043 1SG1 Averaging Plan 0.50 0.49 0IN Frank E Ratts Hoosier Energy Rec, Inc. 1043 2SG1 Averaging Plan 0.50 0.49 0IN Gibson PSI Energy, Inc. 6113 1 Averaging Plan 0.50 0.50 0IN Gibson PSI Energy, Inc. 6113 2 Averaging Plan 0.50 0.50 0IN Gibson PSI Energy, Inc. 6113 3 Averaging Plan 0.50 0.41 0IN Gibson PSI Energy, Inc. 6113 4 Averaging Plan 0.50 0.42 0IN H T Pritchard Indianapolis Power & Light 991 3 Averaging Plan 0.45 0.71 0IN H T Pritchard Indianapolis Power & Light 991 4 Averaging Plan 0.45 0.71 0IN H T Pritchard Indianapolis Power & Light 991 5 Averaging Plan 0.45 0.40 0IN H T Pritchard Indianapolis Power & Light 991 6 Averaging Plan 0.45 0.40 0IN Petersburg Indianapolis Power & Light 994 1 Averaging Plan 0.45 0.30 0IN Petersburg Indianapolis Power & Light 994 2 Averaging Plan 0.45 0.36 0IN Petersburg Indianapolis Power & Light 994 3 Averaging Plan 0.45 0.39 0IN Petersburg Indianapolis Power & Light 994 4 Averaging Plan 0.45 0.33 0
Appendix C-2: Compliance Results for the 265 Phase I NOx Affected Units in 1998

1998

ST Plant Name Operating Utility

ORISCode Boiler Compliance Approach

Emission

Limit

Actual

Emission

Rate

AE

Avg

L

C-2, 4

IN R Gallagher PSI Energy, Inc. 1008 1 Averaging Plan 0.50 0.46 0IN R Gallagher PSI Energy, Inc. 1008 2 Averaging Plan 0.50 0.46 0IN R Gallagher PSI Energy, Inc. 1008 3 Averaging Plan 0.50 0.43 0IN R Gallagher PSI Energy, Inc. 1008 4 Averaging Plan 0.50 0.43 0IN Wabash River PSI Energy, Inc. 1010 1 Standard Limitation 0.50 0.14 IN Wabash River PSI Energy, Inc. 1010 2 Averaging Plan 0.50 0.50 0IN Wabash River PSI Energy, Inc. 1010 3 Averaging Plan 0.50 0.55 0IN Wabash River PSI Energy, Inc. 1010 5 Averaging Plan 0.50 0.53 0IN Wabash River PSI Energy, Inc. 1010 6 Averaging Plan 0.45 0.33 0KS La Cygne Kansas City Power & Light 1241 2 Standard Limitation 0.50 0.31 KS Quindaro Board of Public Util, KS City 1295 2 Standard Limitation 0.50 0.33 KY Coleman Big Rivers Electric 1381 C1 Standard Limitation 0.50 0.45 KY Coleman Big Rivers Electric 1381 C2 Standard Limitation 0.50 0.43 KY Coleman Big Rivers Electric 1381 C3 Standard Limitation 0.50 0.47 KY Cooper East Kentucky Power Coop 1384 1 Averaging Plan 0.50 0.42 0KY Cooper East Kentucky Power Coop 1384 2 Averaging Plan 0.50 0.42 0KY E W Brown Kentucky Utilities Co 1355 1 Averaging Plan 0.50 0.52 0KY E W Brown Kentucky Utilities Co 1355 2 Averaging Plan 0.45 0.42 0KY E W Brown Kentucky Utilities Co 1355 3 Averaging Plan 0.45 0.42 0KY East Bend Cincinnati Gas & Electric Co 6018 2 Averaging Plan 0.50 0.36 0KY Elmer Smith Owensboro City of 1374 2 Standard Limitation 0.45 0.42 KY Ghent Kentucky Utilities Co 1356 1 Averaging Plan 0.45 0.40 0KY Green River Kentucky Utilities Co 1357 5 Averaging Plan 0.50 0.40 0KY H L Spurlock East Kentucky Power Coop 6041 1 Standard Limitation 0.50 0.42 KY HMP&L Station 2 Big Rivers Electric 1382 H1 Standard Limitation 0.50 0.48 KY HMP&L Station 2 Big Rivers Electric 1382 H2 Standard Limitation 0.50 0.48 KY R D Green Big Rivers Electric 6639 G1 Standard Limitation 0.50 0.42 KY R D Green Big Rivers Electric 6639 G2 Standard Limitation 0.50 0.44 MD Chalk Point Pepco 1571 1 AEL Demonstration 0.50 0.66 0MD Chalk Point Pepco 1571 2 AEL Demonstration 0.50 0.70 1MD Morgantown Pepco 1573 1 AEL Demonstration 0.45 0.61 0MD Morgantown Pepco 1573 2 AEL Demonstration 0.45 0.62 0
Appendix C-2: Compliance Results for the 265 Phase I NOx Affected Units in 1998

1998

ST Plant Name Operating Utility

ORISCode Boiler Compliance Approach

Emission

Limit

Actual

Emission

Rate

AE

Avg

L

C-2, 5

MD R P Smith Potomac Edison Co 1570 9 Averaging Plan 0.50 0.51 0MD R P Smith Potomac Edison Co 1570 11 Averaging Plan 0.45 0.44 0MI J H Campbell Consumers Energy Co 1710 1 AEL Demonstration 0.45 0.48 0MN High Bridge Northern States Power Co 1912 3 Averaging Plan 0.50 0.60 0MN High Bridge Northern States Power Co 1912 4 Averaging Plan 0.50 0.60 0MN High Bridge Northern States Power Co 1912 5 Averaging Plan 0.50 0.60 0MN High Bridge Northern States Power Co 1912 6 Averaging Plan 0.50 0.60 0MN Sherburne County Northern States Power Co 6090 1 Averaging Plan 0.45 0.28 0MN Sherburne County Northern States Power Co 6090 2 Averaging Plan 0.45 0.28 0MO Hawthorn Kansas City Power & Light 2079 5 Standard Limitation 0.45 0.38 MO Iatan Kansas City Power & Light 6065 1 Standard Limitation 0.50 0.30 MO James River Springfield City of (MO) 2161 3 Averaging Plan 0.50 0.64 0MO James River Springfield City of (MO) 2161 4 Averaging Plan 0.50 0.66 0MO James River Springfield City of (MO) 2161 5 Averaging Plan 0.50 0.63 0MO Labadie Union Electric Co 2103 1 Averaging Plan 0.45 0.18 0MO Labadie Union Electric Co 2103 2 Averaging Plan 0.45 0.23 0MO Labadie Union Electric Co 2103 3 Averaging Plan 0.45 0.17 0MO Labadie Union Electric Co 2103 4 Averaging Plan 0.45 0.20 0MO Meramec Union Electric Co 2104 1 Averaging Plan 0.45 0.61 0MO Meramec Union Electric Co 2104 2 Averaging Plan 0.45 0.47 0MO Meramec Union Electric Co 2104 3 Averaging Plan 0.50 0.67 0MO Meramec Union Electric Co 2104 4 Averaging Plan 0.50 0.34 0MO Montrose Kansas City Power & Light 2080 1 Standard Limitation 0.45 0.35 MO Montrose Kansas City Power & Light 2080 2 Standard Limitation 0.45 0.39 MO Montrose Kansas City Power & Light 2080 3 Standard Limitation 0.45 0.39 MO Rush Island Union Electric Co 6155 1 Averaging Plan 0.45 0.17 0MO Rush Island Union Electric Co 6155 2 Averaging Plan 0.45 0.18 0MO Southwest Springfield City of (MO) 6195 1 Averaging Plan 0.50 0.35 0MO Thomas Hill Associated Electric Coop Inc 2168 MB3 Standard Limitation 0.50 0.31 MS Jack Watson Mississippi Power Co 2049 4 Averaging Plan 0.50 0.48 0MS Jack Watson Mississippi Power Co 2049 5 Averaging Plan 0.50 0.68 0MS R D Morrow South Mississippi El Pwr 6061 1 Averaging Plan 0.50 0.42 0
Appendix C-2: Compliance Results for the 265 Phase I NOx Affected Units in 1998

1998

ST Plant Name Operating Utility

ORISCode Boiler Compliance Approach

Emission

Limit

Actual

Emission

Rate

AE

Avg

L

C-2, 6

MS R D Morrow South Mississippi El Pwr 6061 2 Averaging Plan 0.50 0.52 0MS Victor J Daniel Jr Mississippi Power Co 6073 1 Averaging Plan 0.45 0.27 0

MS Victor J Daniel Jr Mississippi Power Co 6073 2 Averaging Plan 0.45 0.21 0

NY Dunkirk Niagara Mohawk Power Corp 2554 3 Standard Limitation 0.45 0.33 NY Dunkirk Niagara Mohawk Power Corp 2554 4 Standard Limitation 0.45 0.33 NY Greenidge NYSEG 2527 6 Averaging Plan 0.45 0.38 0NY Milliken NYSEG 2535 1 Averaging Plan 0.45 0.32 0NY Milliken NYSEG 2535 2 Averaging Plan 0.45 0.32 0OH Ashtabula Cleveland Electric Illum 2835 7 Standard Limitation 0.45 0.39 OH Conesville Columbus Southern Power 2840 3 Standard Limitation 0.50 0.44 OH Conesville Columbus Southern Power 2840 4 Standard Limitation 0.45 0.42 OH Eastlake Cleveland Electric Illum 2837 1 Standard Limitation 0.45 0.40 OH Eastlake Cleveland Electric Illum 2837 2 Standard Limitation 0.45 0.39 OH Eastlake Cleveland Electric Illum 2837 3 Standard Limitation 0.45 0.40 OH Eastlake Cleveland Electric Illum 2837 4 Standard Limitation 0.45 0.37 OH Edgewater Ohio Edison Co 2857 13 Averaging Plan 0.50 0.22 0OH Gorge Ohio Edison Co 2858 25 Averaging Plan 0.50 Not Oper. 0OH Gorge Ohio Edison Co 2858 26 Averaging Plan 0.50 Not Oper. 0OH Miami Fort Cincinnati Gas & Electric Co 2832 6 Averaging Plan 0.45 0.56 0OH Picway Columbus Southern Power 2843 9 Standard Limitation 0.50 0.36 OH R E Burger Ohio Edison Co 2864 7 Averaging Plan 0.50 0.69 0OH R E Burger Ohio Edison Co 2864 8 Averaging Plan 0.50 0.71 0OH Toronto Ohio Edison Co 2867 10 Averaging Plan 0.50 Not Oper. 0OH Toronto Ohio Edison Co 2867 11 Averaging Plan 0.50 Not Oper. 0OH W H Sammis Ohio Edison Co 2866 5 Averaging Plan 0.50 0.51 0OH W H Sammis Ohio Edison Co 2866 6 Averaging Plan 0.50 0.49 0OH Walter C Beckjord Cincinnati Gas & Electric Co 2830 5 Averaging Plan 0.45 0.47 0OH Walter C Beckjord Cincinnati Gas & Electric Co 2830 6 Averaging Plan 0.45 0.43 0PA Armstrong West Penn Power Co 3178 1 Averaging Plan 0.50 0.37 0PA Armstrong West Penn Power Co 3178 2 Averaging Plan 0.50 0.36 0PA Bruce Mansfield Ohio Edison Co 6094 1 Averaging Plan 0.50 0.41 0PA Bruce Mansfield Ohio Edison Co 6094 2 Averaging Plan 0.50 0.39 0
Appendix C-2: Compliance Results for the 265 Phase I NOx Affected Units in 1998

1998

ST Plant Name Operating Utility

ORISCode Boiler Compliance Approach

Emission

Limit

Actual

Emission

Rate

AE

Avg

L

C-2, 7

PA Brunner Island PP&L 3140 1 Averaging Plan 0.45 0.41 0PA Brunner Island PP&L 3140 2 Averaging Plan 0.45 0.41 0PA Brunner Island PP&L 3140 3 Averaging Plan 0.45 0.34 0PA Cheswick Duquesne Light Co 8226 1 Standard Limitation 0.45 0.37 PA Conemaugh GPU 3118 1 Standard Limitation 0.45 0.36 PA Conemaugh GPU 3118 2 Standard Limitation 0.45 0.34 PA Martins Creek PP&L 3148 1 Averaging Plan 0.50 0.44 0PA Martins Creek PP&L 3148 2 Averaging Plan 0.50 0.44 0PA Mitchell West Penn Power Co 3181 33 Averaging Plan 0.45 0.39 0PA New Castle Ohio Edison Co 3138 1 Averaging Plan 0.50 Not Oper. 0PA New Castle Ohio Edison Co 3138 2 Averaging Plan 0.50 Not Oper. 0PA Portland GPU 3113 1 Averaging Plan 0.45 0.28 0PA Portland GPU 3113 2 Averaging Plan 0.45 0.34 0PA Shawville GPU 3131 1 Standard Limitation 0.50 0.47 PA Shawville GPU 3131 2 Standard Limitation 0.50 0.47 PA Shawville GPU 3131 3 Standard Limitation 0.45 0.42 PA Shawville GPU 3131 4 Standard Limitation 0.45 0.42 PA Sunbury PP&L 3152 3 Averaging Plan 0.50 0.42 0PA Sunbury PP&L 3152 4 Averaging Plan 0.50 0.43 0TN Gallatin TVA 3403 1 Averaging Plan 0.45 0.36 0TN Gallatin TVA 3403 2 Averaging Plan 0.45 0.36 0TN Gallatin TVA 3403 3 Averaging Plan 0.45 0.37 0TN Gallatin TVA 3403 4 Averaging Plan 0.45 0.37 0TN Johnsonville TVA 3406 1 Averaging Plan 0.45 0.47 0TN Johnsonville TVA 3406 2 Averaging Plan 0.45 0.47 0TN Johnsonville TVA 3406 3 Averaging Plan 0.45 0.47 0TN Johnsonville TVA 3406 4 Averaging Plan 0.45 0.47 0TN Johnsonville TVA 3406 5 Averaging Plan 0.45 0.47 0TN Johnsonville TVA 3406 6 Averaging Plan 0.45 0.47 0TN Johnsonville TVA 3406 7 Averaging Plan 0.50 0.47 0TN Johnsonville TVA 3406 8 Averaging Plan 0.50 0.47 0TN Johnsonville TVA 3406 9 Averaging Plan 0.50 0.47 0
Appendix C-2: Compliance Results for the 265 Phase I NOx Affected Units in 1998

1998

ST Plant Name Operating Utility

ORISCode Boiler Compliance Approach

Emission

Limit

Actual

Emission

Rate

AE

Avg

L

C-2, 8

TN Johnsonville TVA 3406 10 Averaging Plan 0.50 0.47 0WI Alma Dairyland Power Coop 4140 B4 Averaging Plan 0.50 0.71 0WI Alma Dairyland Power Coop 4140 B5 Averaging Plan 0.50 0.71 0WI Genoa Dairyland Power Coop 4143 1 Averaging Plan 0.45 0.41 0WI J P Madgett Dairyland Power Coop 4271 B1 Averaging Plan 0.50 0.39 0WI Port Washington Wisconsin Electric Power Co 4040 1 Averaging Plan 0.50 0.31 0WI Port Washington Wisconsin Electric Power Co 4040 2 Averaging Plan 0.50 0.31 0WI Port Washington Wisconsin Electric Power Co 4040 3 Averaging Plan 0.50 0.31 0WI Port Washington Wisconsin Electric Power Co 4040 4 Averaging Plan 0.50 0.30 0WI Port Washington Wisconsin Electric Power Co 4040 5 Standard Limitation 0.50 Not Oper. WI Pulliam Wisconsin Public Service 4072 7 Averaging Plan 0.50 0.36 0WI Pulliam Wisconsin Public Service 4072 8 Averaging Plan 0.50 0.36 0WI South Oak Creek Wisconsin Electric Power Co 4041 5 Averaging Plan 0.50 0.29 0

WI South Oak Creek Wisconsin Electric Power Co 4041 6 Averaging Plan 0.50 0.29 0

WI South Oak Creek Wisconsin Electric Power Co 4041 7 Averaging Plan 0.45 0.38 0WI South Oak Creek Wisconsin Electric Power Co 4041 8 Averaging Plan 0.45 0.38 0WI Valley Wisconsin Electric Power Co 4042 1 Averaging Plan 0.50 0.43 0WI Valley Wisconsin Electric Power Co 4042 2 Averaging Plan 0.50 0.43 0WI Valley Wisconsin Electric Power Co 4042 3 Averaging Plan 0.50 0.51 0WI Valley Wisconsin Electric Power Co 4042 4 Averaging Plan 0.50 0.51 0WI Weston Wisconsin Public Service 4078 1 Averaging Plan 0.50 0.86 0WI Weston Wisconsin Public Service 4078 2 Averaging Plan 0.50 0.85 0WI Weston Wisconsin Public Service 4078 3 Averaging Plan 0.45 0.20 0WV Albright Monongahela Power Co 3942 1 Averaging Plan 0.50 0.62 0WV Albright Monongahela Power Co 3942 2 Averaging Plan 0.50 0.68 0WV Albright Monongahela Power Co 3942 3 Averaging Plan 0.45 0.39 0WV Fort Martin Monongahela Power Co 3943 1 Averaging Plan 0.45 0.57 0WV Harrison Monongahela Power Co 3944 1 Averaging Plan 0.50 0.46 0WV Harrison Monongahela Power Co 3944 2 Averaging Plan 0.50 0.46 0WV Harrison Monongahela Power Co 3944 3 Averaging Plan 0.50 0.46 0WV Mitchell Ohio Power Co 3948 1 AEL Demonstration 0.50 0.55 0WV Mitchell Ohio Power Co 3948 2 AEL Demonstration 0.50 0.55 0
Appendix C-2: Compliance Results for the 265 Phase I NOx Affected Units in 1998

1998

ST Plant Name Operating Utility

ORISCode Boiler Compliance Approach

Emission

Limit

Actual

Emission

Rate

AE

Avg

L

C-2, 9

WV Mt Storm Vepco 3954 1 AEL Demonstration 0.45 0.69 0WV Mt Storm Vepco 3954 2 AEL Demonstration 0.45 0.64 0WV Mt Storm Vepco 3954 3 AEL Demonstration 0.45 0.72 0WV Pleasants Monongahela Power Co 6004 1 Averaging Plan 0.50 0.39 0WV Pleasants Monongahela Power Co 6004 2 Averaging Plan 0.50 0.34 0WY Jim Bridger Pacificorp 8066 BW71 Standard Limitation 0.45 0.40 WY Jim Bridger Pacificorp 8066 BW72 Standard Limitation 0.45 0.38 WY Jim Bridger Pacificorp 8066 BW73 Standard Limitation 0.45 0.38 WY Wyodak Pacificorp 6101 BW91 Standard Limitation 0.50 0.31 
Appendix C-3:Compliance Results for the 275 Early Election Units in 1998

1 New Source Performance Standard subpart

C-3, 1

ST Plant Name Operating Utility

ORISCode Boiler NSPS1

Emission

Limit

Actual 19

Emission R

AL Charles R Lowman Alabama Electric Coop 56 2 D 0.50 0.49 AL Charles R Lowman Alabama Electric Coop 56 3 D 0.50 0.49 AR Flint Creek Southwestern Electric Power 6138 1 D 0.50 0.31 AR Independence Arkansas Power & Light Co 6641 1 D 0.45 0.26 AR Independence Arkansas Power & Light Co 6641 2 D 0.45 0.24 AR White Bluff Arkansas Power & Light Co 6009 1 D 0.45 0.39 AR White Bluff Arkansas Power & Light Co 6009 2 D 0.45 0.37 AZ Apache Station Arizona Electric Pwr Coop 160 2 D 0.50 0.46 AZ Apache Station Arizona Electric Pwr Coop 160 3 D 0.50 0.41 AZ Cholla Arizona Public Service 113 1 0.45 0.42 AZ Cholla Arizona Public Service 113 2 D 0.45 0.33 AZ Cholla Arizona Public Service 113 3 D 0.45 0.36 AZ Cholla Arizona Public Service 113 4 D 0.45 0.27 AZ Coronado Salt River Project 6177 U1B D 0.50 0.42 AZ Coronado Salt River Project 6177 U2B D 0.50 0.43 AZ Navajo Salt River Project 4941 1 0.45 0.39 AZ Navajo Salt River Project 4941 2 0.45 0.37 AZ Navajo Salt River Project 4941 3 0.45 0.40 AZ Springerville Tucson Electric Power Co 8223 1 D 0.45 0.38 AZ Springerville Tucson Electric Power Co 8223 2 D 0.45 0.38 CO Cherokee Public Service Co of CO 469 3 0.50 0.40 CO Cherokee Public Service Co of CO 469 4 0.45 0.33 CO Comanche Public Service Co of CO 470 1 0.45 0.26 CO Comanche Public Service Co of CO 470 2 D 0.50 0.28 CO Craig Tri-state G&T Association 6021 C1 D 0.50 0.31 CO Craig Tri-state G&T Association 6021 C2 D 0.50 0.38 CO Craig Tri-state G&T Association 6021 C3 Da 0.50 0.36 CO Pawnee Public Service Co of CO 6248 1 D 0.50 0.21 CO Rawhide Platte River Power 6761 101 Da 0.45 0.35 CO Ray D Nixon Colorado Springs Utilities 8219 1 D 0.50 0.39 CO Valmont Public Service Co of CO 477 5 0.45 0.31 CT Bridgeport Harbor United Illuminating Co 568 BHB3 0.45 0.26 FL C D McIntosh Jr City of Lakeland 676 3 D 0.50 0.46 
Appendix C-3:Compliance Results for the 275 Early Election Units in 1998

ST Plant Name Operating Utility

ORISCode Boiler NSPS1

Emission

Limit

Actual 19

Emission R

1 New Source Performance Standard subpart

C-3, 2

FL Crystal River Florida Power Corporation 628 2 0.45 0.44 FL Crystal River Florida Power Corporation 628 4 D 0.50 0.49 FL Crystal River Florida Power Corporation 628 5 D 0.50 0.48 FL Deerhaven Gainesville Regional Util 663 B2 D 0.50 0.48 FL Seminole Seminole Electric Coop Inc 136 1 Da 0.50 0.46 FL Seminole Seminole Electric Coop Inc 136 2 Da 0.50 0.43 FL St Johns River Power Jacksonville Electric Auth 207 1 Da 0.50 0.49 FL St Johns River Power Jacksonville Electric Auth 207 2 Da 0.50 0.48 GA Scherer Georgia Power Co 6257 4 D 0.45 0.35 IA Ames City of Ames 1122 7 0.45 0.38 IA Ames City of Ames 1122 8 D 0.50 0.43 IA Council Bluffs Midamerican Energy Company 1082 1 0.50 0.47 IA Council Bluffs Midamerican Energy Company 1082 2 0.45 0.38 IA Council Bluffs Midamerican Energy Company 1082 3 D 0.50 0.43 IA George Neal North Midamerican Energy Company 1091 2 0.50 0.45 IA George Neal North Midamerican Energy Company 1091 3 D 0.50 0.47 IA George Neal South Midamerican Energy Company 7343 4 D 0.50 0.39 IA Lansing Interstate Power Co 1047 4 D 0.50 0.42 IA Louisa Midamerican Energy Company 6664 101 D 0.50 0.26 IA Ottumwa IES Utilities, Inc. 6254 1 D 0.45 0.33 IL Crawford Commonwealth Edison Co 867 7 0.45 0.31 IL Crawford Commonwealth Edison Co 867 8 0.45 0.38 IL Dallman City of Springfield, IL 963 33 D 0.45 0.39 IL Fisk Commonwealth Edison Co 886 19 0.45 0.33 IL Waukegan Commonwealth Edison Co 883 7 0.45 0.28 IL Waukegan Commonwealth Edison Co 883 8 0.45 0.40 IL Will County Commonwealth Edison Co 884 3 0.45 0.40 IL Will County Commonwealth Edison Co 884 4 0.45 0.33 IN A B Brown Southern Indiana Gas & Elec 6137 1 D 0.50 0.42 IN A B Brown Southern Indiana Gas & Elec 6137 2 Da 0.50 0.45 IN Dean H Mitchell Northern Indiana Pub Serv 996 4 0.45 0.33 IN Dean H Mitchell Northern Indiana Pub Serv 996 5 0.45 0.33 IN Dean H Mitchell Northern Indiana Pub Serv 996 6 0.45 0.32 
Appendix C-3:Compliance Results for the 275 Early Election Units in 1998

ST Plant Name Operating Utility

ORISCode Boiler NSPS1

Emission

Limit

Actual 19

Emission R

1 New Source Performance Standard subpart

C-3, 3

IN Dean H Mitchell Northern Indiana Pub Serv 996 11 0.50 0.32 IN Merom Hoosier Energy 6213 1SG1 D 0.50 0.39 IN Merom Hoosier Energy 6213 2SG1 D 0.50 0.39 IN R M Schahfer Northern Indiana Pub Serv 6085 15 D 0.50 0.23 IN R M Schahfer Northern Indiana Pub Serv 6085 17 Da 0.45 0.35 IN R M Schahfer Northern Indiana Pub Serv 6085 18 Da 0.45 0.32 IN Rockport Indiana Michigan Power Co 6166 MB1 D 0.50 0.36 IN Rockport Indiana Michigan Power Co 6166 MB2 D 0.50 0.36 IN State Line Commonwealth Edison Co 981 3 0.45 0.21 IN Whitewater Valley City of Richmond, IN 1040 1 0.50 0.42 IN Whitewater Valley City of Richmond, IN 1040 2 0.45 0.42 KS Nearman Creek Board of Public Util, KS City 6064 N1 D 0.50 0.45 KS Riverton Empire District Electric 1239 39 0.50 0.41 KS Riverton Empire District Electric 1239 40 0.45 0.42 KY Cane Run Louisville Gas & Electric 1363 4 0.50 0.41 KY Cane Run Louisville Gas & Electric 1363 5 0.50 0.48 KY Cane Run Louisville Gas & Electric 1363 6 0.45 0.40 KY D B Wilson Big Rivers Electric 6823 W1 Da 0.50 0.50 KY Dale East Kentucky Power Coop Inc 1385 3 0.50 0.41 KY Dale East Kentucky Power Coop Inc 1385 4 0.50 0.41 KY H L Spurlock East Kentucky Power Coop Inc 6041 2 D 0.45 0.41 KY Mill Creek Louisville Gas & Electric 1364 1 0.45 0.45 KY Mill Creek Louisville Gas & Electric 1364 2 0.45 0.40 KY Mill Creek Louisville Gas & Electric 1364 3 D 0.50 0.49 KY Mill Creek Louisville Gas & Electric 1364 4 D 0.50 0.49 KY Trimble County Louisville Gas & Electric 6071 1 D 0.45 0.41 LA Big Cajun 2 Cajun Electric Power 6055 2B1 D 0.50 0.31 LA Big Cajun 2 Cajun Electric Power 6055 2B2 D 0.50 0.30 LA Big Cajun 2 Cajun Electric Power 6055 2B3 D 0.50 0.26 LA Dolet Hills Central Louisiana Elec Co 51 1 D 0.50 0.41 LA R S Nelson Gulf States Utilities 1393 6 D 0.45 0.40 LA Rodemacher Central Louisiana Elec Co 6190 2 D 0.50 0.43 MI B C Cobb Consumers Energy Co 1695 4 0.45 0.40 
Appendix C-3:Compliance Results for the 275 Early Election Units in 1998

ST Plant Name Operating Utility

ORISCode Boiler NSPS1

Emission

Limit

Actual 19

Emission R

1 New Source Performance Standard subpart

C-3, 4

MI B C Cobb Consumers Energy Co 1695 5 0.45 0.39 MI J B Sims City of Grand Haven 1825 3 Da 0.50 0.40 MI J C Weadock Consumers Energy Co 1720 7 0.45 0.36 MI J C Weadock Consumers Energy Co 1720 8 0.45 0.36 MI J R Whiting Consumers Energy Co 1723 1 0.50 0.38 MI J R Whiting Consumers Energy Co 1723 3 0.50 0.38 MI Presque Isle Upper Peninsula Power Co 1769 7 D 0.50 0.44 MI Presque Isle Upper Peninsula Power Co 1769 8 D 0.50 0.44 MI Presque Isle Upper Peninsula Power Co 1769 9 D 0.50 0.46 MN Clay Boswell Minnesota Power & Light Co 1893 3 0.45 0.36 MN Hoot Lake Otter Tail Power Co 1943 2 0.45 0.38 MO Sikeston Sikeston Board of Mun Util 6768 1 D 0.50 0.24 MT Colstrip Montana Power Company 6076 1 D 0.45 0.39 MT Colstrip Montana Power Company 6076 2 D 0.45 0.43 MT Colstrip Montana Power Company 6076 3 Da 0.45 0.43 MT Colstrip Montana Power Company 6076 4 Da 0.45 0.43 MT Lewis & Clark Montana-Dakota Utilities Co 6089 B1 0.45 0.35 NC Buck Duke Energy Corporation 2720 5 0.45 0.41 NC Buck Duke Energy Corporation 2720 6 0.45 0.43 NC Buck Duke Energy Corporation 2720 7 0.45 0.45 NC Buck Duke Energy Corporation 2720 8 0.45 0.43 NC Buck Duke Energy Corporation 2720 9 0.45 0.44 NC Cliffside Duke Energy Corporation 2721 1 0.45 0.41 NC Cliffside Duke Energy Corporation 2721 2 0.45 0.44 NC Cliffside Duke Energy Corporation 2721 3 0.45 0.40 NC Cliffside Duke Energy Corporation 2721 4 0.45 0.43 NC Cliffside Duke Energy Corporation 2721 5 0.45 0.44 NC Dan River Duke Energy Corporation 2723 1 0.45 0.42 NC Dan River Duke Energy Corporation 2723 2 0.45 0.42 NC Dan River Duke Energy Corporation 2723 3 0.45 0.44 NC G G Allen Duke Energy Corporation 2718 1 0.45 0.44 NC G G Allen Duke Energy Corporation 2718 2 0.45 0.42 NC G G Allen Duke Energy Corporation 2718 3 0.45 0.44 
Appendix C-3:Compliance Results for the 275 Early Election Units in 1998

ST Plant Name Operating Utility

ORISCode Boiler NSPS1

Emission

Limit

Actual 19

Emission R

1 New Source Performance Standard subpart

C-3, 5

NC G G Allen Duke Energy Corporation 2718 4 0.45 0.42 NC G G Allen Duke Energy Corporation 2718 5 0.45 0.42 NC Marshall Duke Energy Corporation 2727 1 0.45 0.43 NC Marshall Duke Energy Corporation 2727 2 0.45 0.45 NC Marshall Duke Energy Corporation 2727 3 0.45 0.44 NC Marshall Duke Energy Corporation 2727 4 0.45 0.42 NC Riverbend Duke Energy Corporation 2732 7 0.45 0.42 NC Riverbend Duke Energy Corporation 2732 8 0.45 0.38 NC Riverbend Duke Energy Corporation 2732 9 0.45 0.40 NC Riverbend Duke Energy Corporation 2732 10 0.45 0.38 ND Antelope Valley Basin Electric Power 6469 B1 D 0.45 0.39 ND Antelope Valley Basin Electric Power 6469 B2 D 0.45 0.30 ND Leland Olds Basin Electric Power 2817 1 0.50 0.25 ND Stanton United Power Assn 2824 10 Da 0.45 0.38 NE Gerald Gentleman Sta Nebraska Public Power Dist 6077 1 D 0.50 0.45 NE Gerald Gentleman Sta Nebraska Public Power Dist 6077 2 D 0.50 0.32 NE Gerald Whelan Energy City of Hastings 60 1 D 0.45 0.24 NE Nebraska City Omaha Public Power Dist 6096 1 D 0.50 0.46 NE North Omaha Omaha Public Power Dist 2291 4 0.45 0.31 NE Platte City of Grand Island 59 1 D 0.45 0.39 NM Escalante Plains Electric Gen & Trans 87 1 Da 0.45 0.39 NV Mohave Southern California Edison 2341 1 0.45 0.41 NV Mohave Southern California Edison 2341 2 0.45 0.40 NV North Valmy Sierra Pacific Power Co 8224 1 D 0.50 0.39 NV North Valmy Sierra Pacific Power Co 8224 2 Da 0.50 0.37 NV Reid Gardner Nevada Power Company 2324 4 Da 0.50 0.28 NY C R Huntley Niagara Mohawk Power Corp 2549 67 0.45 0.31 NY C R Huntley Niagara Mohawk Power Corp 2549 68 0.45 0.31 NY Dunkirk Niagara Mohawk Power Corp 2554 1 0.45 0.34 NY Dunkirk Niagara Mohawk Power Corp 2554 2 0.45 0.35 NY Kintigh NYSEG 6082 1 Da 0.50 0.41 NY S A Carlson City of Jamestown 2682 9 0.50 0.43 NY S A Carlson City of Jamestown 2682 10 0.50 0.46 
Appendix C-3:Compliance Results for the 275 Early Election Units in 1998

ST Plant Name Operating Utility

ORISCode Boiler NSPS1

Emission

Limit

Actual 19

Emission R

1 New Source Performance Standard subpart

C-3, 6

NY S A Carlson City of Jamestown 2682 11 0.50 0.46 NY S A Carlson City of Jamestown 2682 12 0.50 0.43 OH Conesville Columbus Southern Power 2840 5 D 0.45 0.41 OH Conesville Columbus Southern Power 2840 6 D 0.45 0.41 OH W H Zimmer Cincinnati Gas & Electric Co 6019 1 Da 0.50 0.44 OK Muskogee Oklahoma Gas & Electric Co 2952 4 D 0.45 0.37 OK Muskogee Oklahoma Gas & Electric Co 2952 5 D 0.45 0.35 OK Muskogee Oklahoma Gas & Electric Co 2952 6 D 0.45 0.38 OK Northeastern Public Service Co of OK 2963 3313 D 0.45 0.35 OK Northeastern Public Service Co of OK 2963 3314 D 0.45 0.35 OK Sooner Oklahoma Gas & Electric Co 6095 1 D 0.45 0.36 OK Sooner Oklahoma Gas & Electric Co 6095 2 D 0.45 0.36 OR Boardman Portland General Electric 6106 1SG D 0.50 0.40 PA Bruce Mansfield Ohio Edison Co 6094 3 D 0.50 0.42 PA Cromby Peco Energy Company 3159 1 0.50 0.43 PA Eddystone Peco Energy Company 3161 1 0.45 0.32 PA Eddystone Peco Energy Company 3161 2 0.45 0.30 PA Homer City GPU 3122 1 0.50 0.45 PA Homer City GPU 3122 2 0.50 0.43 PA Homer City GPU 3122 3 D 0.50 0.43 PA Keystone GPU 3136 1 0.45 0.36 PA Keystone GPU 3136 2 0.45 0.37 PA Montour PP&L 3149 1 0.45 0.44 PA Montour PP&L 3149 2 0.45 0.40 PA New Castle Ohio Edison Co 3138 3 0.50 0.39 PA New Castle Ohio Edison Co 3138 4 0.50 0.36 PA New Castle Ohio Edison Co 3138 5 0.50 0.44 PA Titus GPU 3115 1 0.45 0.39 PA Titus GPU 3115 2 0.45 0.40 PA Titus GPU 3115 3 0.45 0.38 SC Cross South Carolina Pub Serv 130 1 Da 0.50 0.32 SC Cross South Carolina Pub Serv 130 2 Da 0.45 0.39 SC W S Lee Duke Energy Corporation 3264 1 0.45 0.43 
Appendix C-3:Compliance Results for the 275 Early Election Units in 1998

ST Plant Name Operating Utility

ORISCode Boiler NSPS1

Emission

Limit

Actual 19

Emission R

1 New Source Performance Standard subpart

C-3, 7

SC W S Lee Duke Energy Corporation 3264 2 0.45 0.44 SC W S Lee Duke Energy Corporation 3264 3 0.45 0.44 TN John Sevier TVA 3405 1 0.45 0.41 TN John Sevier TVA 3405 2 0.45 0.41 TN John Sevier TVA 3405 3 0.45 0.42 TN John Sevier TVA 3405 4 0.45 0.42 TX Big Brown Texas Utilities Electric Co 3497 1 0.45 0.34 TX Big Brown Texas Utilities Electric Co 3497 2 0.45 0.35 TX Coleto Creek Central Power & Light Co 6178 1 D 0.45 0.28 TX Gibbons Creek Texas Municipal Power Agency 6136 1 D 0.45 0.34 TX Harrington Station Southwestern Public Service 6193 061B D 0.45 0.36 TX Harrington Station Southwestern Public Service 6193 062B D 0.45 0.29 TX Harrington Station Southwestern Public Service 6193 063B D 0.45 0.26 TX J K Spruce City of San Antonio 7097 **1 Da 0.45 0.38 TX J T Deely City of San Antonio 6181 1 D 0.45 0.32 TX J T Deely City of San Antonio 6181 2 D 0.45 0.32 TX Limestone Houston Lighting & Power 298 LIM1 Da 0.45 0.41 TX Limestone Houston Lighting & Power 298 LIM2 Da 0.45 0.41 TX Martin Lake Texas Utilities Electric Co 6146 1 D 0.45 0.34 TX Martin Lake Texas Utilities Electric Co 6146 2 D 0.45 0.32 TX Martin Lake Texas Utilities Electric Co 6146 3 D 0.45 0.35 TX Monticello Texas Utilities Electric Co 6147 1 0.45 0.29 TX Monticello Texas Utilities Electric Co 6147 2 0.45 0.32 TX Monticello Texas Utilities Electric Co 6147 3 D 0.50 0.23 TX Oklaunion West Texas Utilities Co 127 1 Da 0.50 0.46 TX Pirkey Southwestern Electric Power 7902 1 D 0.50 0.36 TX Sam Seymour Lower Colorado River Auth 6179 1 D 0.45 0.34 TX Sam Seymour Lower Colorado River Auth 6179 2 D 0.45 0.33 TX Sam Seymour Lower Colorado River Auth 6179 3 Da 0.45 0.30 TX San Miguel San Miguel Electric Coop 6183 SM-1 D 0.50 0.40 TX Sandow Texas Utilities Electric Co 6648 4 D 0.45 0.35 TX Tolk Station Southwestern Public Service 6194 171B D 0.45 0.33 TX Tolk Station Southwestern Public Service 6194 172B D 0.45 0.29 
Appendix C-3:Compliance Results for the 275 Early Election Units in 1998

ST Plant Name Operating Utility

ORISCode Boiler NSPS1

Emission

Limit

Actual 19

Emission R

1 New Source Performance Standard subpart

C-3, 8

TX W A Parish Houston Lighting & Power 3470 WAP5 D 0.50 0.33 TX W A Parish Houston Lighting & Power 3470 WAP6 D 0.50 0.32 TX W A Parish Houston Lighting & Power 3470 WAP7 D 0.45 0.41 TX W A Parish Houston Lighting & Power 3470 WAP8 Da 0.45 0.37 TX Welsh Southwestern Electric Power 6139 1 D 0.50 0.33 TX Welsh Southwestern Electric Power 6139 2 D 0.50 0.34 TX Welsh Southwestern Electric Power 6139 3 D 0.50 0.36 UT Bonanza Deseret Generation & Tran 7790 1-1 Da 0.50 0.36 UT Carbon Pacificorp 3644 1 0.45 0.40 UT Carbon Pacificorp 3644 2 0.45 0.42 UT Hunter (Emery) Pacificorp 6165 1 D 0.45 0.40 UT Hunter (Emery) Pacificorp 6165 2 D 0.45 0.41 UT Huntington Pacificorp 8069 1 D 0.45 0.40 UT Intermountain Intermountain Power Agency 6481 1SGA Da 0.50 0.42 UT Intermountain Intermountain Power Agency 6481 2SGA Da 0.50 0.40 VA Chesapeake VEPCO 3803 1 0.45 0.44 VA Chesapeake VEPCO 3803 2 0.45 0.44 VA Chesapeake VEPCO 3803 4 0.45 0.45 VA Chesterfield VEPCO 3797 3 0.45 0.42 VA Chesterfield VEPCO 3797 4 0.45 0.42 VA Glen Lyn Appalachian Power Co 3776 51 0.45 0.40 VA Glen Lyn Appalachian Power Co 3776 52 0.45 0.36 VA Possum Point VEPCO 3804 3 0.45 0.44 VA Potomac River PEPCO 3788 1 0.45 0.42 VA Potomac River PEPCO 3788 2 0.45 0.39 VA Potomac River PEPCO 3788 3 0.45 0.43 VA Potomac River PEPCO 3788 4 0.45 0.40 VA Potomac River PEPCO 3788 5 0.45 0.44 VA Yorktown VEPCO 3809 1 0.45 0.44 VA Yorktown VEPCO 3809 2 0.45 0.44 WA Centralia Pacificorp 3845 BW21 0.45 0.39 WA Centralia Pacificorp 3845 BW22 0.45 0.43 WI Blount Street Madison Gas & Electric Co 3992 8 0.50 0.38 
Appendix C-3:Compliance Results for the 275 Early Election Units in 1998

ST Plant Name Operating Utility

ORISCode Boiler NSPS1

Emission

Limit

Actual 19

Emission R

1 New Source Performance Standard subpart

C-3, 9

WI Blount Street Madison Gas & Electric Co 3992 9 0.50 0.40 WI Columbia Wisconsin Power & Light 8023 1 0.45 0.40 WI Columbia Wisconsin Power & Light 8023 2 D 0.45 0.37 WI Edgewater Wisconsin Power & Light 4050 5 D 0.50 0.23 WV Mountaineer (1301) Appalachian Power Co 6264 1 D 0.50 0.50 WY Dave Johnston Pacificorp 4158 BW41 0.50 0.39 WY Dave Johnston Pacificorp 4158 BW42 0.50 0.40 WY Jim Bridger Pacificorp 8066 BW74 D 0.45 0.39 WY Laramie River Basin Electric Power 6204 1 D 0.50 0.25 WY Laramie River Basin Electric Power 6204 2 D 0.50 0.26 WY Laramie River Basin Electric Power 6204 3 D 0.50 0.27