United States

Environmental Protection

Agency

Office of Air and Radiation

Acid Rain Division (6204J)

EPA-430-R-98-012

August 1998

1997 Compliance Report

Acid Rain Program

 
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 1997, there were 423 units affected by the SO2 provisions of the Acid Rain Program, 187

of which were also affected for NOx, and an additional 351 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 30-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......................................................................................................5

Compliance Results.....................................................................................8

Allowance Market.......................................................................................11

NOX Results

Program......................................................................................................13

Phase I Units...............................................................................................13

Phase I Compliance Results.........................................................................15

Phase II Early Election Units.......................................................................17

Phase II Early Election Compliance Results.................................................18

Monitoring Update................................................................................................. 20

Conclusion............................................................................................................. 22

Appendix A: Phase I Affected And Early Election Units in 1997

Appendix B-1: Table 1 Units Designating Substitution and Compensating Units - 1997

Appendix B-2: List of Phase I Extension Units and 1998 Deductions for Exceeding 1997 Projected 

 Emissions Limitations

Appendix B-3: Emissions and Utilization of Phase I Units, 1996 and 1997

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

Appendix C-1: List of Averaging Plans and Results in 1997

Appendix C-2: Compliance Results for the 265 Phase I NOX Affected Units in 1997

Appendix C-3: Compliance Results for the 272 Early Election Units in 1997
1997 Compliance Report Page 1

TO THE READER:

The 1997 Compliance Report once again announces 100 percent compliance with the Acid Rain

Program, now in its third year of sulfur dioxide (SO2) compliance and its second year of nitrogen oxides

(NOX) compliance. Affected facilities continued to exceed the targets set for both pollutants by the

Clean Air Act Amendments of 1990. The early reductions seen in 1995 and 1996 for SO2 continue,

with affected utility units beating their 1997 target by 23 percent. The overcompliance with the NOX

target also continues, achieving an average emission rate for Phase I units 16 percent below the

compliance rate.

Trading activity in the SO2 arena continues to rise dramatically; the number of private trades between

economically distinct organizations in 1997 is greater than the number of corresponding trades in all

previous years combined. This increasingly active market, coupled with the success of the industry in

exceeding compliance goals, has encouraged EPA to continue in its efforts to support other programs

seeking to implement trading in order to achieve environmental goals at lower costs.

The Acid Rain Program is continually striving to find new ways to improve the efficiency with which it

carries out its mission. For example, despite the addition of compliance determinations for 272 new

Phase II early election units and supplemental determinations of compliance with Phase I extension

provisions for 1997, EPA was able to complete the annual reconciliation process in the same amount of

time as it did for 1996. This faster completion time was facilitated by fewer errors in submission of

emissions data by the sources, which reduced the need for subsequent resubmissions; the improved

quality of these data reports were in turn facilitated by the improvements to the Emissions Tracking

System made by EPA which allowed faster feedback to be provided to sources each quarter. 

I would like to thank those in the industry for their efforts to work in partnership with EPA. We expect

to continue our efforts by making improvements in our rules and procedures, as well as upgrading the

Emissions and Allowance Tracking Systems. Together, we can improve the efficiency of the Acid Rain

Program and realize its significant environmental benefits.

Brian J. McLean, Director

Acid Rain Program
1997 Compliance Report Page 2

1

Four units have been “conditionally” deemed to be in compliance with their NOx requirements, two early

election units and two Table 1 units. The two Table 1 units are awaiting a final determination on their AEL

demonstration period petition, the two early election units are awaiting a change in their permit conditions.

SUMMARY

100 Percent Compliance for both SO2 and NOx in 1997

All 774 boilers and combustion turbines (referred to as “units”) affected by the SO2 and NOx

regulations of the Acid Rain Program in 1997 successfully met their emissions compliance obligations.1

All 423 units subject to SO2 requirements in 1997 held sufficient allowances to cover their

emissions. The 5,480,210 allowances deducted from compliance accounts represent approximately

77 percent of all 1997 allowances issued and 41 percent of all 1995, 1996, and 1997 allowances that

were available for compliance. Almost all of the deducted allowances (5,474,440, or 99.9 percent)

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

All 537 units subject to the NOx requirements in 1997 demonstrated compliance with applicable

annual emission limitations. Of these 537 units, 239 were also subject to SO2 requirements, while

298 units were affected only for NOx (26 Phase I units and 272 Phase II “early election” units). 

1997 SO2 Emissions of Phase I Units were 23 Percent Below Allowable Level

SO2 emissions in 1997 were 1.7 million tons (or 23 percent) below the 7.1 million ton allowable level as

determined by 1997 allowance allocations. Since an additional 6.3 million allowances were carried

over, or banked, from 1996, the overall number of allowances available in 1997 was 13.4 million, of

which affected units exhausted only about 41 percent. Actual emissions for the 423 units participating

in 1997, measured by continuous emission monitoring systems (CEMS), were 5.5 million tons, up less

than 100,000 tons from emissions of the 431 units affected in 1996. 

1997 Phase I Unit NOx Emission Rates 41 Percent Below 1990; NOx Tons 32 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 0.69 pounds of NOx per million Btu of heat input (lb/mmBtu) to an average of 0.40

lbs/mmBtu, 17 percent below the compliance rate of 0.48 lbs/mmBtu for these units. Emission levels

for these units were 409,322 tons (or 32 percent) below 1990 levels.

1997 NOX Emission Rates of Early Election Units Even Lower Than Phase I Units’ 
1997 Compliance Report Page 3

For the 272 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 1997, 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 24 percent between 1990 and 1997, NOx tons increased by only 2 percent.

Monitoring Performance Excellent Once Again

For the third 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 utility units affected by both Phase I and Phase II of the

program.

Accuracy: : 98.4 percent of the installed and tested monitors met the required relative

accuracy standards on the first attempt, while less than two percent needed

appropriate monitor adjustments to meet the standards; SO2 monitors achieved a

median relative accuracy (i.e., deviation from the reference test method) of 3.2

percent; flow monitors, 3.5 percent; and NOx monitors, 3.3 percent. 

 Reliability: SO2 and flow monitors achieved a median reliability of 99.3 and 99.5 percent,

respectively, while NOx monitors achieved a median reliability of 98.8 percent.

SO2 Market Active; Volume of Allowances Transferred Between Distinct Entities in 1997

Exceeds the Total of 1994, 1995, and 1996 Combined 

Activity in the allowance market continued to increase in 1997. The volume of allowances transferred

between unrelated parties in economically significant trades increased from 4.4 million in 1996 to 7.9

million in 1997. More than 80 percent of Phase I and Phase II affected utility companies have already

engaged in at least one private transfer registered in ATS. 

Following the all-time low cost of allowances of $68 at the 1996 allowance auction, prices increased to

$110 in the 1997 auction. Later in 1997, prices dipped again to a low of $88, to finish in 1997 at about

$100. Prices have increased again in the first half of 1998, with the auction price of $117 and market

indices of approximately $190 in June. 
1997 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 Variable Variable

Opt-in 0 7 7 Variable Variable

TOTAL 445 431 423 Variable Variable

NOx Table 1 NA 144 170 171 171

Substitution NA 95 95 95 95

Early-Election NA NA 272 Variable Variable

TOTAL NA 239 537 Variable Variable

This report discusses the process and results of determining compliance for these Phase I affected units. 

Detailed appendices provide information on 1997 emissions and utilization for both SO2 and NOx

affected sources, allowance holdings and deductions for SO2 sources, and explanations of averaging

plans and compliance flexibility and requirements for NOx sources.
1997 Compliance Report Page 5

2During 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.

SO2 PROGRAM

423 Units Underwent Annual Reconciliation for SO2 in 1997

There were 416 affected utility units and seven opt-in units that underwent annual reconciliation in 1997

to determine whether sufficient allowances were held to cover emissions. These 423 units are listed in

Appendix A and include 263 utility units specifically required to participate during Phase I, 153 utility

units not initially required to participate until Phase II, but electing to participate early as part of

multi-unit compliance plans, and seven other units that elected to join as part of the Opt-in Program.

The core 263 utility units, residing at 110 power plants, were selected by Congress in the 1990

Amendments to the Clean Air Act because they were the highest emitting and largest units. These units

emitted 57 percent of all utility emissions in 1985, and had emission rates ranging from 2.5 to 10.2 lbs

of SO2/mmBtu of heat input, with an average of 4.2 lbs/mmBtu. These units are often referred to as

"Table 1 units" because they are officially listed in Table 1 of the allowance allocation regulation, 40

CFR 73.10.

An additional 153 utility units affected in 1997 have been designated by certain Table 1 units to serve

either as substitution or compensating units2. Appendix B-1 delineates the relation of these units to

their Table 1 counterparts. In 1997, there were 152 substitution units and one compensating unit

designated. 

The seven opt-in units that entered the program in July 1996 remain in the program. 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.

In 1997, there were 8 fewer units undergoing annual reconciliation than in 1996, and 22 fewer than in

1995. The change in number of units affected by the Phase I SO2 provisions is due to the entry and exit

of units in accordance with substitution and compensating plans of one or more of the original 263

Table 1 units and the entry of opt-in sources. 

New Requirements for Phase I Extension Units in 1997

Under the Acid Rain Program, certain units applied for and received approval of Phase I Extension
1997 Compliance Report Page 6

3Qualifying technology is defined in 40 CFR 72.2

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

were required to cut their emission by 90 percent using qualifying technology3 by 1997, and “transfer

units” which reassigned their emissions reduction obligations to a control unit. Both kinds of units

received extra SO2 emissions allowances to cover the SO2 they emitted beyond their basic Phase I

allocations during 1995 and 1996. In addition, the control units were given Phase I extension

allowances for 1997, 1998, and 1999. A total of 3.5 million allowances was distributed to all Phase I

extension control and transfer units.

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.

For 1997, all 19 control units demonstrated meeting the 90 percent reduction requirement and,

therefore, did not surrender any 1997 extension allowances. The 1997 tonnage emissions limitation,

though, was exceed by six control units and ten transfer units and resulted in a surrender of a total of

92,768 vintage 1998 allowances. The deduction amounts for each Phase I extension unit are included in

Appendix B-2.

1997 SO2 Emissions Target was 7.1 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 1997, the emissions target established by the program for the 423 participating units was

7.1 million tons. However, the total allowable SO2 emission level in 1997 was actually 13.4 million

tons, consisting of the 7.1 million 1997 allowances granted through the program and an additional 6.3

million allowances carried over, or banked, from 1996.

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 1997 were also made available through the allowance auctions, held annually

since 1993. Other allowances issued in 1997 were from bonus 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. 
1997 Compliance Report Page 7

Exhibit 2

Origin of 1997 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 271,334 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 1,024,178 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 95,882 Opt-in Allowances are provided to units entering the program

voluntarily. 

Small Diesel Allowances 27,578 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.

Conservation Allowances 11,834 Conservation Allowances are awarded to utilities that undertake

efficiency and renewable energy measures prior to their first

compliance year. The allowances come from a special

Conservation and Renewable Energy Reserve set aside when the

initial allowance allocation was made.

TOTAL 1997 ALLOCATION 7,147,464

BANKED 1996 ALLOWANCES 6,288,335 Banked Allowances are those held over from 1995 and 1996

which can be used for compliance in 1997 or any future year.

TOTAL 1997 ALLOWABLE 13,435,799

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.
1997 Compliance Report Page 8

SO2 COMPLIANCE RESULTS

Phase I Units Better 1997 SO2 Allowable Emissions Level by 23 Percent

The Phase I units affected in 1997 emitted at a level approximately 23 percent below 1997 allocations,

as shown in Exhibit 3. Although this percentage is significantly lower than in 1996, it is not due to an

increase in emissions but rather due to a decrease in allocations, primarily due to the much lower

number of Phase I extension allowances allocated for 1997. The Phase I units emitted 5.5 million tons

of SO2, expending only about 41 percent of the 13.4 million allowances available in 1997. Appendix B3 reports the 1997 emission and utilization levels for all Phase I affected units, as well as a comparison

to these levels in 1996 and 1995.

Exhibit 3

Summary of SO2 Emissions versus Allocations

(Millions of Tons)

Relative to 1996, the 263 Table 1 units increased their emissions by less than 10,000 tons, or less than

one percent in 1997, while increasing their utilization by three percent. The 4.8 million tons emitted by

these Table 1 units were still substantially below their 1997 allocation of 5.6 million allowable tons.
1997 Compliance Report Page 9

Just over half of the Table 1 units (52 percent) increased their emissions relative to 1996 by an average

of 3,400 tons. Most of the remaining Table 1 units (44 percent) decreased their emissions from 1996

levels by an average of 3,900 tons. The remaining eight Table 1 units maintained the same zero

emission level of 1996.

In terms of utilization, almost half (46 percent) of Table 1 units decreased their levels by an average of

10 percent, while just over half (51 percent) increased their utilization since 1996 by an average of 27

percent.

Substitution and compensating units in 1997 expended a larger percentage of their annual allocation

than in 1996. In 1997, these 153 units were responsible for emitting approximately 621,000 tons of

SO2, about 60 percent of their 1.04 million allocation. In 1996, 161 substitution and compensating units

emitted approximately 610,000 tons of SO2, or slightly more than half of their allowable level. 

Of the 153 units in 1997, 44 percent increased their emissions relative to 1996 by an average of 1,500

tons, while 30 percent of the units decreased their emissions by an average of 900 tons. The remainder

of the units maintained their status as zero emitters.

Forty two percent of substitution and compensating units increased their utilization between 1996 and

1997, while 34 percent of units experienced a decrease in utilization. The remaining 24 percent of

substitution and compensating units were not utilized again in 1997. 

Opt-in units received 95,882 allowances in 1997 as a reflection of their baseline emissions levels, but

contributed only 77,037 tons to 1997 emission levels. Although this is an increase of approximately

40,000 tons over 1996, the 1997 data represent operations for the entire calendar year of 1997, whereas

in 1996, the opt-in units were only affected for the second half of the year.

Deducting Allowances for Compliance

The total number of allowances deducted in 1997 was 5,480,210 which represents approximately 77

percent of all 1997 allowances issued. Almost all (99.9 percent) of the deducted allowances were for

emissions. Exhibit 4 on the following page displays these allowance deductions, as well as the

remaining bank of 1995, 1996, and 1997 allowances. 

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

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

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

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

surrendered to cover the total 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-3 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.

In 1997, Phase I units had a total of 5,474,440 allowances deducted for emissions. Of the 423 units,

Paradise Unit 3 in Kentucky for the third year in a row surrendered the most allowances for emissions

(173,285), an increase of 18 percent over 1996. Fifty units were not operated at all during the year and 
1997 Compliance Report Page 10

Exhibit 4

 SO2 Allowance Reconciliation Summary

Total Allowances Held in Accounts as of 1/30/98 (1995, 1996, & 1997 Vintages)* 13,435,799

 Table 1 Unit Accounts 7,942,551

 Substitution & Compensating Unit Accounts 1,288,988

 Opt-in Accounts 85,126

 Other Accounts** 4,119,134

1997 Allowances Deducted for Emissions 5,474,440

 Table 1 Unit Accounts 4,774,609

 Substitution & Compensating Unit Accounts 620,794

 Opt-in Unit Accounts 79,037

1997 Allowances Deducted Under Special Phase I Provisions*** 5,770

 Table 1 Unit Accounts 1,733

 Substitution & Compensating Unit Accounts 2,949

 Opt-in Unit Accounts 1,309

Banked Allowances 7,955,368

 Table 1 Unit Accounts 3,166,209

 Substitution & Compensating Unit Accounts 665,245

 Opt-in Unit Accounts 4,780

 Other Accounts** 4,119,134

surrendered no allowances. Half of the units surrendered under 7,000 allowances, while the average

number of allowances deducted at a unit was 12,944.

The remaining 0.1 percent (5,770) of allowance deductions were made for underutilization and controlby-contract, which are explained in detail in Appendix B-4. 

 * The number of allowances held in the Allowance Tracking System (ATS) accounts equals the number of 1997 allowances allocated

(see Exhibit 2) plus the number of 1996 banked allowances. January 30, 1998 represents the Allowance Transfer Deadline, the point

in time at which the 1997 Phase I affected unit accounts are frozen and after which no transfers of 1995,1996, and 1997 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 control-by-contract provisions in 1997 (see Appendix B-4 for a thorough

explanation).
1997 Compliance Report Page 11

SO2 ALLOWANCE MARKET

The flexibility provided by the Acid Rain Program enabled the 423 units affected in 1997 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 423

sources to be in compliance in 1997 and significantly reduced the cost of achieving these emissions

reductions as compared to the cost of a technological mandate. 

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

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

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

initially estimated at $400-1000/ton, but dropped to a low of just $68/ton at the 1996 allowance auction. 

Following this low, however, the price of a current vintage year allowance climbed to $110 in the 1997

auction, after which time it dipped once again into the $88 range, only to finish 1997 at about $100. 

Prices have increased during the first half of 1998, with a March 1998 auction price of $117 and market

indices of approximately $190/ton in June, 1998. 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 two brokerage firms, Emissions Exchange Corporation and Cantor

Fitzgerald Environmental Brokerage Services, and a market survey conducted by Fieldston Publications. 

Exhibit 5
1997 Compliance Report Page 12

Activity in the allowance market created under the Acid Rain Program continued to grow in 1997, with

1,429 transactions moving over 15 million allowances reported to 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

1.9 million in 1995 to 4.4 million in 1996 and to 7.9 million in 1997, as shown in Exhibit 6. The total for

1997 exceeds the total of the three previous years combined. Growth is also evident in the subset of

economically significant transfers representing only those allowances acquired by utilities (rather than all

those exchanged by unrelated parties through the market); volume has increased from 700,000

allowances in 1995 to 1.6 million in 1996 and to 2.8 million in 1997. In addition, more than 80 percent

of the accounts established for affected units under the program have been involved in at least one

private transfer registered in ATS. Almost half of allowances with vintage years 1995 and 1996 have

been involved in at least one transfer as well. To date, approximately 35 percent of 1997 allowances

have been involved in a transfer under the Acid Rain Program. 

Exhibit 6

Volume of SO2 Allowances in Economically Significant Transfers

EPA seeks to minimize transaction costs to parties trading allowances in the market by quickly and

efficiently recording transfers reported to the Agency in ATS. In 1997, EPA processed 89 percent of

allowance transactions within 24 hours of receipt, up slightly from the 1996 rate of 83 percent. Ninetyeight percent were processed within 5 days. These 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.
1997 Compliance Report Page 13

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, 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 1997

In 1997, 265 coal-fired utility units were subject to the Title IV Phase I emission limitations for NOx, an

increase of 26 units from 1996. The 265 Phase I NOx affected units include 170 Table 1 units and 95

substitution units whose owners chose to participate in Phase I as part of an SO2 compliance strategy. 

This group of units (along with one additional unit whose compliance extension expired at the end of

1997) will be 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. 
1997 Compliance Report Page 14

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 93 42 135

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 three 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 heatinput 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.

! Phase I NOx Extensions. Twenty-seven Group 1 boilers affected in Phase I qualified for a Phase

I NOx extension for 1996. All of the extensions expired on December 31, 1996, except for one

that expired on July 31, 1997, and another that expired on December 31, 1997.

Exhibit 8 summarizes the compliance options chosen by Phase I affected NOx units for 1997. As in 1996,

averaging was the most widely chosen compliance option. For 1997, utilities submitted 24 averaging

plans involving 204 Phase I NOx units. For seven plans involving 22 units, the averaging plan was not

necessary to balance compliance among units; all units within the plan met their applicable emission limit

individually. See Appendix C-1: List of Averaging Plans and Results in 1997.
1997 Compliance Report Page 15

4

The analyses in this section focus on these 263 units.

Exhibit 8

Compliance Options Chosen in 1997

Compliance Option Number of Units

Compliance with Standard Emission Limitation 52

Emissions Averaging 204

Alternative Emission Limitation 7

SUBTOTAL 263

Pending Alternative Emission Limitation Petition 1

Pending Alternative Emission Limitation Petition for

Partial Year Compliance

1

Part 76 Phase I NOx Extension 1

TOTAL 266

PHASE I NOX COMPLIANCE RESULTS

EPA has determined that 263 out of the 265 Phase I NOx units met the required emission limit through

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

limitation4. The two other Phase I units are conditionally in compliance pending a decision on their

alternative emission limitation petitions which was pending as of July 1998. The 266th unit will become a

Phase I affected unit in 1998. See Appendix C-2: Compliance Results for the 266 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

Many units emitted at rates well below the emission limits, as shown in Exhibit 9. Utilities operated the

affected group of Phase I NOx boilers at NOx emission rates approximately 16 percent below the

allowable rate in 1997, compared to 18 percent below in 1996.
1997 Compliance Report Page 16

5

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

Compliance Report.

0.76

0.43 0.42

0.52

0.36 0.36

0.00

0.20

0.40

0.60

0.80

1990 1996 1997

NOx Rate 

(lb/mmBtu)

Table 1 Units (168) Substitution Units (95)

1997 Weighted Average

Emission Limitation

(0.48)

Exhibit 9

Percentage Compliance Relative to Allowable Emission Rate in 1997

Percent Below

Applicable Limit

Units Subject to 

Standard Limit

Units Using 

Averaging

Units Subject to 

AEL Demonstration Total

0 - 10% 20 99 4 123

10% - 25% 15 87 2 104

More than 25% 17 18 1 36

Total 52 204 7 263

From 19905 to 1997, the average NOx emission rate of the 263 Phase I units declined by 42 percent (from

0.69 lb/mmBtu to 0.40 lb/mmBtu). As shown in Exhibit 10, on average, both Table 1 and substitution

units were below the average Phase I emission limit of 0.48 lb/mmBtu (the 1997 heat input weighted

average of the applicable limits).

Exhibit 10

Average NOx Emission Rates for 263 Phase 1 Units

NOx Mass Emissions Reduction

Total NOx mass emissions also declined from 1990 to 1997, but not as significantly as the NOx emission

rate. Exhibit 11 illustrates the change in NOx mass emissions from 1990 to 1997 for Table 1 and

substitution units. The Table 1 units exhibited a 36 percent reduction in NOx tons, and the substitution

units showed a 16 percent reduction. For the 263 Phase I units, annual NOx emissions reductions
1997 Compliance Report Page 17

between 1990 and 1997 totaled approximately 409,322 tons, or a 32 percent reduction. However, NOx

mass emissions in 1997 increased slightly from 1996, attributable to greater electrical production, as

evidenced by a five percent increase in heat input. Without further reductions in emissions rates, NOx

emissions would be expected to rise with increased utilization. As in 1996, the lower percentage of

reductions for substitution units is probably attributable to the fact that many of these units were already

lower emitters subject to New Source Performance Standards (NSPS).

Exhibit 11

NOx Mass Emissions for 263 Phase I Units 

997,586

601,162 634,115

287,583

239,437 241,733

0

400,000

800,000

1,200,000

1,600,000

1990 1996 1997

NOx 

Tons

Table 1 Units (168) Substitution Units (95)

PHASE II EARLY ELECTION UNITS

272 Units Were Subject to Early Election Requirements in 1997

Nineteen ninety-seven was the first year in which utilities could choose to use the "Early Election"

compliance option provided in Part 76. Owners and operators of 272 units applied for this option. 

Exhibit12 shows the number of Early Election units by boiler type.

Exhibit 12

Distribution of 1997 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 0.45 300 170 56.7%

Dry Bottom Wall-fired 0.50 314 102 32.5%

Total 614 272 44.3%
1997 Compliance Report Page 18

PHASE II EARLY ELECTION COMPLIANCE RESULTS

For 1997, EPA determined that 270 units complied with the Phase I, Group 1 emission limitations and

have continued eligibility for Early Election in 1998 through 2007. An additional two units subject to

Early Election complied with the Phase I, Group 1 emission limit, however, their compliance is pending,

while their permit is being reviewed. See Appendix C-3: Compliance Results for the 272 Early Election

Units in 1997.

NOx Emission Rate Reduction

In 1997, many Early Election units emitted at rates well below the applicable emission limit, as shown in

Exhibit 13. Utilities operated dry-bottom wall-fired boilers at NOx emission levels approximately 23

percent below the limit of 0.50 lb/mmBtu and tangentially fired boilers approximately 18 percent below

the limit of 0.45 lb/mmBtu. 

Exhibit 13

Percentage Compliance Relative to Emission Limits

Percent Below Applicable 

Emission Limitation Early Election Units

0 - 10% 94

10 - 25% 112

More than 25% 66

Total 272

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

1990 to 0.38 lb/mmBtu in 1997. This decline is less dramatic than the decline at Phase I NOx units

because 51 percent of the Early Election units are newer units already subject to the NSPS NOx emission

limits. The overall NOx emission rate for these units is comparable to the average rate of 0.40 lb/mmBtu

for all Phase I NOx units. 

Exhibit 14 summarizes the NOx emission rate reductions from 1990 to 1997 by boiler type for the 262

Early Election units which were operating in 1990.
1997 Compliance Report Page 19

0.44

0.37

0.47

0.38

0.00

0.20

0.40

0.60

0.80

1990 1997 1990 1997

NOx Rate 

(lb/mmBtu)

 Dry-Bottom Wall-Fired Boilers 

 Emission Limit (0.50)

Tangentially-Fired Boilers

Emission Limit (0.45)

Exhibit 14

Average NOx Emission Rate for 262 Early Election Units

NOx Mass Emissions Reduction

The total NOx mass emissions from the operating Early Election units increased by 23,887 tons (or 

2 percent) from 1990 to 1997, reflecting an increase in utilization (see Exhibit 15). For the 262 Early

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

24 percent.

Exhibit 15

NOx Mass Emissions for 262 Early Election Units

724,231

575,634 581,843

741,909

0

400,000

800,000

1,200,000

1,600,000

1990 1997

NOx 

Tons

Dry-Bottom 

Wall-Fired 

Boilers (100)

T-Fired 

Boilers (162)
1997 Compliance Report Page 20

SO2 AND NOx MONITORING IN 1997

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 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 1997. 

Exhibit 16

1997 Relative Accuracy Test Audit (RATA) Results

SO2 Concentration Volumetric Flow Rate NOx Rate

Mean Relative Accuracy 3.9% 4.2% 4.0%

Median Relative Accuracy 3.2% 3.5% 3.3%

Percent Meeting Relative Accuracy

Standard

97% 99% 97%

Another metric used to determine the effectiveness of a CEMS is the percentage of hours that a
1997 Compliance Report Page 21

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 1997 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 17

1997 CEMS Availability

Parameter Median % Availability at End of 1997

Coal-Fired Units Oil and Gas Units

SO2 99.3 98.3

Flow 99.6 98.7

NOx 99.1 97.7
1997 Compliance Report Page 22

6 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.

CONCLUSION

Both the Acid Rain Program’s rate-based approach to NOx reduction and cap-and-trade approach to SO2

reduction have been very successful. In 1997, all 502 Phase I affected utility units not only met their

compliance goals, but exceeded them, achieving an overall reduction of 409,322 tons of NOx from 1990

levels despite an increase in generation, and maintaining the extraordinary reductions of more than 5

million tons of SO2 from 1980 levels, first achieved in 1995. Additionally, the 272 Phase II units newly

affected for NOx in 1997 under the early election program had increased emissions of only two percent

since 1990, while their utilization increased by 24 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 19956. 

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,

and 23 percent of 1997 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 have been very

successful in 1997. 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. 
APPENDIX A: PHASE I AFFECTED (T) AND EARLY ELECTION (E) UNITS IN 1997

 

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

A, 1

AL Charles R Lowman 2 E

 3 E

AL Colbert 1 T T

 2 T T

 3 T T

 4 T T

 5 T T

AL E C Gaston 1 T T

 2 T T

 3 T T

 4 T T

 5 T T

AL Gadsden 1 T T

 2 T T

AR Flint Creek 1 E

AR Independence 1 E

 2 E 

AR White Bluff 1 E

 2 E

AZ Apache 2 E

 3 E

AZ Cholla 1 E

 2 E

 3 E

 4 E

AZ Coronado U1B E

 U2B E

AZ Navajo 1 E

 2 E

 3 E

AZ Springerville 1 E

 2 E

CO Craig C1 E

 C2 E 

 C3 E 

CO Comanche 1 E

 2 E

CO Cherokee 3 E

 4 E

CO Pawnee 1 E

CO Rawhide 101 E

CO Ray D Nixon 1 E

CO Valmont 5 E

CT Bridgeport Harbor BHB3 E

FL Big Bend BB01 T

 BB02 T

 BB03 T

 BB04 T T

FL C D McIntosh 3 E

FL Crist 4 T T

 5 T T

 6 T T

 7 T T

FL Crystal River 2 E

 4 E

 5 E

FL Deerhaven B2 E

FL St Johns River 1 E

 2 E

FL Scholz 1 T T

 2 T T

FL Seminole 1 E

 2 E

GA Arkwright 1 T T

 2 T T

 3 T T

 4 T T

GA Bowen 1BLR T T

 2BLR T T

 3BLR T T

 4BLR T T
APPENDIX A: PHASE I AFFECTED (T) AND EARLY ELECTION (E) UNITS IN 1997

 

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

A, 2

GA Hammond 1 T T

 2 T T

 3 T T

 4 T T

GA Harllee Branch 1 T

 2 T T

 3 T

 4 T

GA Jack Mcdonough MB1 T T

 MB2 T T

 GA Kraft 1 T T

 2 T T

 3 T T

 GA Mcintosh 1 T T

 GA Mitchell 3 T T

 GA Scherer 3 T

 4 E

 GA Wansley 1 T T

 2 T T

 GA Yates Y1BR T T

 Y2BR T T

 Y3BR T T

 Y4BR T T

 Y5BR T T

 Y6BR T T

 Y7BR T T

 IA Ames 7 E

 8 E

 IA Burlington 1 T T

 IA Council Bluffs 1 E

 2 E

 3 E

 IA Des Moines 11 T

 IA George Neal North 1 T

 2 E

 3 E

 IA George Neal South 4 E

 IA Lansing 4 E

 IA Louisa 101 E

 IA Milton L Kapp 2 T T

 IA Ottumwa 1 E

 IA Prairie Creek 4 T T

 IA Riverside 9 T T

 IL Baldwin 1 T

 2 T

 3 T T

 IL Coffeen 1 T

 2 T

 IL Collins 1 T

 2 T

 3 T

 IL Crawford 7 E

 8 E

 IL Dallman 33 E

 IL Fisk 19 E

 IL Grand Tower 7 T T

 8 T T

 9 T T

 IL Havana 1 T

 2 T

 3 T

 4 T

 5 T

 6 T

 7 T

 8 T

IL Hennepin 2 T T

IL Hutsonville 5 T T

 6 T T
APPENDIX A: PHASE I AFFECTED (T) AND EARLY ELECTION (E) UNITS IN 1997

 

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

A, 3

IL Joppa Steam 1 T T

 2 T T

 3 T T

 4 T T

 5 T T

 6 T T

 IL Kincaid 1 T

 2 T

IL Meredosia 01 T T

 02 T T

 03 T T

 04 T T

 05 T T

 06 T

IL Newton 1 T T

 2 T T

IL Vermilion 1 T T

 2 T T

 IL Waukegan 7 E

 8 E

 IL Will County 3 E

 4 E

 IL Wood River 1 T

 IN A B Brown 1 E

 2 E

 IN Bailly 7 T

 8 T

 IN Breed 1 T

IN Cayuga 1 T T

 2 T T

 IN Clifty Creek 1 T

 2 T

 3 T

 4 T

 5 T

 6 T

 IN Dean H Mitchell 4 E

 5 E

 6 E

 11 E

IN Elmer W Stout 50 T T

 60 T T

 70 T T

 IN F B Culley 2 T T

 3 T T

 IN Frank E Ratts 1SG1 T T

 2SG1 T T

 IN Gibson 1 T T

 2 T T

 3 T T

 4 T T

 IN H T Pritchard 3 T

 4 T

 5 T T

 6 T T

 IN Merom 1SG1 E

 2SG1 E

 IN Michigan City 12 T

 IN Petersburg 1 T T

 2 T T

 3 T

 4 T

 IN R M Schahfer 15 E

 17 E

 18 E

 IN R Gallagher 1 T T

 2 T T

 3 T T

 4 T T

 IN Rockport MB1 E

 MB2 E

 IN State Line 3 E

 IN Tanners Creek U4 T
APPENDIX A: PHASE I AFFECTED (T) AND EARLY ELECTION (E) UNITS IN 1997

 

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

A, 4

 IN Wabash River 1 T T

 2 T T

 3 T T

 5 T T

 6 T T

 IN Warrick 1 T

 2 T

 3 T

 4 T

 IN Whitewater Valley 1 E

 2 E

 KS La Cygne 1 T

 2 T

 KS Nearman Creek 1 E

KS Quindaro 2 T T

 KS Riverton 39 E

 40 E

 

 KY Cane Run 4 E

 5 E

 6 E

 KY Coleman C1 T T

 C2 T T

 C3 T T

KY Cooper 1 T T

 2 T T

 KY D B Wilson W1 E 

KY E W Brown 1 T T

 2 T T

 3 T T

KY East Bend 2 T T

KY Elmer Smith 1 T

 2 T T

KY Ghent 1 T T

KY Green River 5 T T

 KY H L Spurlock 1 T T

 KY Hmp&L Station 2 H1 T T

 H2 T T

KY Mill Creek 1 E

 2 E

 3 E

 4 E

 KY Paradise 3 T

KY R D Green G1 T T

 G2 T T

 KY Shawnee 10 T

KY Trimble County 1 E

 LA Big Cajun 2 2B1 E

 2B2 E

 2B3 E

LA Dolet Hills 1 E

LA R S Nelson 6 E 

 LA Rodemacher 2 E

 MA Brayton Point 2 T

MA Mount Tom 1 T

MD C P Crane 1 T

 2 T

MD Chalk Point 1 T T

 2 T T

 3 T

 4 T

 MD Morgantown 1 T T

 2 T T

 MD R P Smith 9 T T

 11 T T

 MI B C Cobb 4 T E

 5 E

 MI Dan E Karn 1 T

 2 T
APPENDIX A: PHASE I AFFECTED (T) AND EARLY ELECTION (E) UNITS IN 1997

 

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

A, 5

 MI J B Sims 3 E

MI J C Weadock 7 T E

 8 T E

 MI J H Campbell 1 T T

 2 T

 3 T

 MI J R Whiting 1 E

 2 T

 3 T E

 MI Presque Isle 7 E 

 8 E

 9 E

 MN Clay Boswell 3 E

 MN High Bridge 3 T T

 4 T T

 5 T T

 6 T T

 

 MN Hoot Lake 2 E

 MN Sherburne County 1 T T

 2 T T

 MO Asbury 1 T

 MO Hawthorn 5 T T

 MO Iatan 1 T

 MO James River 3 T T

 4 T T

 5 T T

 MO Labadie 1 T T

 2 T T

 3 T T

 4 T T

 MO Meramec 1 T T

 2 T T

 3 T T

 4 T T

 

 MO Montrose 1 T T

 2 T T

 3 T T

 MO New Madrid 1 T

 2 T

 MO Rush Island 1 T T

 2 T T

 MO Sibley 1 T

 2 T

 3 T

 MO Sioux 1 T

 2 T

 MO Sikeston 1 E 

 MO Southwest 1 T T

 MO Thomas Hill MB1 T

 MB2 T

 MB3 T T

 MS Jack Watson 4 T T

 5 T T

 MS R D Morrow 1 T T

 2 T T

 MS Victor J Daniel Jr 1 T

 2 T

 MT Colstrip 1 E

 2 E

 3 E

 4 E

 MT Lewis & Clark B1 E

 NC Buck 5 E

 6 E

 7 E

 8 E

 9 E

 NC Cliffside 1 E

 2 E

 3 E

 4 E

 5 

E

 

 NC Dan River 1 E

 2 E
APPENDIX A: PHASE I AFFECTED (T) AND EARLY ELECTION (E) UNITS IN 1997

 

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

A, 6

 3 E NC G G Allen 1 E

 2 E

 3 E

 4 E

 5 E

 NC Marshall 1 E

 2 E

 3 E

 4 E

 NC Riverbend 7 E

 8 E

 9 E

 10 E

 ND Antelope Valley B1 E

 B2 E

 ND Leland Olds 1 E

 ND Stanton 10 E

 NE Gerald Gentleman 1 E

 2 E

 NE Gerald Whelan 1 E

 NE Nebraska City 1 E

 NE North Omaha 4 E

 NE Platte 1 E

 NH Merrimack 1 T

 2 T

 NJ B L England 1 T

 2 T

 NM Escalante 1 E

 NV Mohave 1 E

 2 E

 NV North Valmy 1 E

 2 E

 NV Reid Gardner 4 E

NY C R Huntley 67 E

 68 E
APPENDIX A: PHASE I AFFECTED (T) AND EARLY ELECTION (E) UNITS IN 1997

 

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

A, 7

 NY Dunkirk 1 E

 2 T E

 3 T T

 4 T T

 NY Greenidge 6 T T

 NY Kintigh 1 E

 NY Milliken 1 T T

 2 T T

NY Northport 1 T

 2 T

 3 T

 4 T

 NY Oswego 4 T 

 5 T

 6 T

 NY Port Jefferson 3 T

 4 T

 NY Roseton 1 T

 2 T

 NY S A Carlson 9 E

 10 E

 11 E

 12 E

 OH Acme 13 T

 14 T 

 15 

 T

 16 T

 91 T

 92 T

 

 OH Ashtabula 7 T T

 8 T

 9 T

 10 T

 11 T

 OH Avon Lake 9 T

 10 T

 11 T

 12 T
APPENDIX A: PHASE I AFFECTED (T) AND EARLY ELECTION (E) UNITS IN 1997

 

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

A, 8

 OH Bay Shore 1 T

 2 T

 3 T

 4 T

 OH Cardinal 1 T

 2 T

 OH Conesville 1 T

 2 T

 3 T T

 4 T T

 5 E

 6 E

 OH Eastlake 1 T T

 2 T T

 3 T T

 4 T T

 5 T

 OH Edgewater 11 T

 12 T

 13 T T

 OH Gen J M Gavin 1 T

 2 T

 OH Gorge 25 T T

 26 T T

 OH J M Stuart 1 T

 2 T

 3 T

 4 T

 OH Kyger Creek 1 T

 2 T

 3 T

 4 T

 5 T

OH Lake Shore 18 T 

 91 T 

 92 T 

 93 T 

 94 T

 OH Miami Fort 5-1 T 

 5-2 T

 6 T T

 7 T

OH Muskingum River 1 T

 2 T

 3 T

 4 T

 5 T

OH Niles 1 T

 2 T

OH Picway 9 T T

OH Poston 1 T

 2 T

 3 T

 OH R E Burger 1 T

 2 T

 3 T

 4 T

 5 T

 6 T

 7 T T

 8 T T

OH Toronto 9 T

 10 T T

 11 T T

OH W H Sammis 5 T T

 6 T T

 7 T

 OH W H Zimmer 1 E

OH Walter C Beckjord 5 T T

 6 T T

 OK Muskogee 4 E

 5 E

 6 E

 OK Northeastern 3313 E

 3314 E

 OK Sooner 1 E

 2 E

 OR Boardman 1SG 

E

 PA Armstrong 1 T T

 2 T T
APPENDIX A: PHASE I AFFECTED (T) AND EARLY ELECTION (E) UNITS IN 1997

 

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

A, 9

 

 PA Bruce Mansfield 1 T T

 2 T T

 3 E

 PA Brunner Island 1 T T

 2 T T

 3 T T

 PA Cheswick 1 T T

 PA Conemaugh 1 T T

 2 T T

 PA Cromby 1 E

 PA Eddystone 1 E

 2 E

 PA Hatfield's Ferry 1 T

 2 T

 3 T

 PA Homer City 1 E

 2 E

 3 E

 PA Keystone 1 E

 2 E

 PA Martins Creek 1 T T

 2 T T

 3 T

 4 T

 PA Mitchell 33 T T

 PA Montour 1 E

 2 E

 PA New Castle 1 T T

 2 T T

 3 E

 4 E

 5 E

 PA Portland 1 T T

 2 T T

 PA Shawville 1 T T

 2 T T

 3 T T

 4 T T

 PA Sunbury 3 T T

 4 T T

 PA Titus 1 E

 2 E

 3 E

 SC Cross 1

 E

 2 E

 SC W S Lee 1 E

 2 E

 3 E

 

 TN Allen 1 T

 2 T

 3 T

 TN Cumberland 1 T

 2 T

 TN DuPont JVD1 T 

 Johnsonville JVD2 T

 JVD3 T

 JVD4 T

 TN Gallatin 1 T T

 2 T T

 3 T T

 4 T T

 TN John Sevier 1 E

 2 E

 3 E

 4 E

 TN Johnsonville 1 T T

 2 T T

 3 T T

 4 T T

 5 T T

 6 T T

 7 T T

 8 T T

 9 T T

 10 T T

TX Big Brown 1 E
APPENDIX A: PHASE I AFFECTED (T) AND EARLY ELECTION (E) UNITS IN 1997

 

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

A, 10

 2 E

 TX Coleto Creek 1 E

 TX Gibbons Creek 1 E

TX Harrington 061B E

 062B E

 063B E

 TX J K Spruce BLR1 E

 TX J T Deely 1 E

 2 E

TX Limestone LIM1 E

 LIM2 E

 TX Martin Lake 1 E

 2 E

 3 E

TX Monticello 1 E

 2 E

 3 E

 TX Oklaunion 1 E

 TX Pirkey 1 E

 TX Sam Seymour 1 E

 2 E

 3 

E

 TX San Miguel SM-1 E

 TX Sandow 4 E

 TX Tolk 171B E

 172B E

 TX W A Parish WAP5 E

 WAP6 E

 WAP7 E

 WAP8 E

 TX Welsh 1 E

 2 E

 3 E 

 UT Bonanza 1-1 E

 UT Carbon 1 E

 2 E

 UT Gadsby 3 T

 UT Hunter 1 E

 2 E

 UT Huntington 1 E

 UT Intermountain 1SGA E

 2SGA E

 VA Chesapeake 1 E

 2 E

 4 E

 VA Chesterfield 3 E

 4 E

 VA Glen Lyn 51 E

 52 E

 VA Possum Point 3 E

VA Potomac River 1 E

 2 E

 3 E

 4 E

 5 E

 VA Yorktown 1 E

 2 E

 WA Centralia BW21 E

 BW22 E 

WI Alma B4 T T

 B5 T T

 WI Blount Street 8 E

 9 E

 WI Columbia 1 E

 2 E

 WI Edgewater 3 T

 4 T
APPENDIX A: PHASE I AFFECTED (T) AND EARLY ELECTION (E) UNITS IN 1997

 

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

A, 11

 5 E

WI Genoa 1 T T

WI J P Madgett B1 T T

WI Nelson Dewey 1 T

 2 T

 WI North Oak Creek 1 T

 2 T

 3 T

 4 T

 WI Port Washington 1 T

 2 T

 3 T

 4 T

 5 T

WI Pulliam 5 T 

 6 T

 7 T T

 8 T T

WI Rock River 1 T 

 2 T

WI South Oak Creek 5 T T

 6 T T

 7 T T

 8 T T

 

 WI Valley 1 T

 2 T

 3 T

 4 T

 WI Weston 1 T T

 2 T T

 3 T

 WV Albright 1 T T

 2 T T

 3 T T

 WV Fort Martin 1 T T

 2 T

 WV Harrison 1 T T 

 2 

 T T 3 

 T T

 WV Kammer 1 T

 2 T

 3 T

 WV Mitchell 1 T T

 2 T T

 WV Mountaineer 1 E

 WV Mt Storm 1 T T

 2* T 

 3 T T

 WV Pleasants 1 T

 2 T

 WV Rivesville 7 T

 8 T

 WV Willow Island 1 T

 2 T

 WY Dave Johnston BW41 E

 BW42 E

 WY Jim Bridger BW71 T

 BW72 T

 BW73 T

 BW74 E

 WY Laramie River 1 E

 2 E

 3 E

 WY Wyodak BW91 T

* NOx extension granted to Mt Storm Unit 2 through

December 31, 1997.
B-2, 1

APPENDIX B-1:

Table 1 Units Designating Substitution and Compensating Units - 1997

Substitution Units

Table 1 Units Substitution Units

State Plant Name Units State Plant Name Units

AL EC Gaston 5 AL Gadsden 1,2

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

FL Crist 7 FL Crist 4,5

FL Scholz 1,2

GA Bowen 1BLR GA Harllee Branch 1

GA Bowen 2BLR GA Harllee Branch 2

GA Bowen 3BLR GA Harllee Branch 3

GA Bowen 4BLR GA Harllee Branch 4

GA Hammond 1 GA Arkwright 1

GA Hammond 2 GA Arkwright 2

GA Hammond 3 GA Arkwright 3

GA Hammond 4 GA Arkwright 4

GA Jack Mcdonough MB2 GA Mitchell 3

GA Yates Y2BR GA Kraft 1

GA Yates Y3BR GA Kraft 2

GA Yates Y4BR GA Kraft 3

GA Yates Y5BR GA McIntosh 1

IL Baldwin 3 IL Havana 1,2,3,4,5,6,7,8

IL Kincaid 1,2 IL Collins 1,2,3

IL Meredosia 5 IL Meredosia 1,2,3,4,6

IL Hutsonville 5,6

IL Newton 1,2

IL Grand Tower 7,8

IL Vermilion 2 IL Vermilion 1

IN Petersburg 1,2 IN H T Pritchard 5
B-2, 2

APPENDIX B-1:

Table 1 Units Designating Substitution and Compensating Units - 1997

Substitution Units

Table 1 Units Substitution Units

State Plant Name Units State Plant Name Units

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

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

MD Chalk Point 1,2 MD Chalk Point 4

MD Morgantown 1,2 MD Chalk Point 3

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

MI J R Whiting 2,3

MI JH Campbell 3

MI JC Weadock 7,8

MI BC Cobb 4

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 1,2,3,4

MO Rush Island 1,2

MO Montrose 1,2,3 MO Hawthorn 5

MO Sioux 1,2 KS La Cygne 1

MO Sibley 3 MO Sibley 1,2

MO Thomas Hill MB1, MB2 MO Thomas Hill MB3

NH Merrimack 1,2 MA Mount Tom 1

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

NY Roseton 1,2

NY Dunkirk 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
B-2, 3

APPENDIX B-1:

Table 1 Units Designating Substitution and Compensating Units - 1997

Substitution Units

Table 1 Units Substitution Units

State Plant Name Units State Plant Name Units

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

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

Compensating Units

Table 1 Units Compensating Units

State Plant Name Units State Plant Name Units

OH Edgewater 13 MA Brayton Point 2
 APPENDIX B-2: List of Phase I Extension Units and 1998 Deductions for Exceeding 1997 Projected Emissions 

Limitations

State Plant Name Unit ID

Ph I Ext 

Type

1998 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 5609

IN Michigan City 12 TRANSFER 3236

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 250

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 630

KY Hmp&L Station 2 H2 CONTROL 942

KY Paradise 3 TRANSFER 0

MD C P Crane 1 TRANSFER 0

MD Chalk Point 1 TRANSFER 0

MD Morgantown 1 TRANSFER 1863

MD Morgantown 2 TRANSFER 0

NJ B L England 1 TRANSFER 0

NJ B L England 2 CONTROL 0

OH Cardinal 1 TRANSFER 10670

OH Conesville 1 TRANSFER 2871

OH Conesville 3 TRANSFER 4424

OH Eastlake 5 TRANSFER 0

OH Gen J M Gavin 1 CONTROL 5379

OH Gen J M Gavin 2 CONTROL 4902

OH Muskingum River 1 TRANSFER 14921

OH Muskingum River 2 TRANSFER 3096

OH Muskingum River 3 TRANSFER 12198

OH Muskingum River 4 TRANSFER 14559

OH Niles 1 TRANSFER 0

OH Niles 2 TRANSFER 0

OH Picway 9 TRANSFER 7218

OH R E Burger 5 TRANSFER 0

OH R E Burger 6 TRANSFER 0

OH R E Burger 7 TRANSFER 0

OH R E Burger 8 TRANSFER 0

PA Armstrong 1 TRANSFER 0

PA Brunner Island 2 TRANSFER 0

PA Brunner Island 3 TRANSFER 0

PA Conemaugh 1 CONTROL 0

PA Conemaugh 2 CONTROL 0

PA Hatfield's Ferry 1 TRANSFER 0

PA Hatfield's Ferry 2 TRANSFER 0

PA Hatfield's Ferry 3 TRANSFER 0

PA Portland 1 TRANSFER 0

PA Portland 2 TRANSFER 0

PA Sunbury 3 TRANSFER 0

PA Sunbury 4 TRANSFER 0

TN Cumberland 1 CONTROL 0

TN Cumberland 2 CONTROL 0
 APPENDIX B-2: List of Phase I Extension Units and 1998 Deductions for Exceeding 1997 Projected Emissions 

Limitations

State Plant Name Unit ID

Ph I Ext 

Type

1998 Allowance 

Deduction

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
APPENDIX B-3: EMISSIONS AND UTILIZATION OF PHASE 1 UNITS, 1996 AND 1997

1996 1997 Percent Change, 1996-1997

SO2 Utilization SO2 Utilization SO2 Utilization

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

AL Colbert CSCO14 (1, 2, 3, 4) 31,939 27,220 -14.78%

AL Colbert 1 Table1 12,952,183 10,745,711 -17.04%

AL Colbert 2 Table1 12,618,216 12,048,491 -4.52%

AL Colbert 3 Table1 10,114,184 9,359,699 -7.46%

AL Colbert 4 Table1 13,855,269 11,770,490 -15.05%

AL Colbert 5 Table1 58,218 34,058,704 50,803 27,875,666 -12.74% -18.15%

AL E C Gaston CS0CAN (1, 2) 22,028 24,949 13.26%

AL E C Gaston 1 Table1 15,064,260 14,950,877 -0.75%

AL E C Gaston 2 Table1 16,306,916 16,144,807 -0.99%

AL E C Gaston CS0CBN (3, 4) 19,812 26,165 32.07%

AL E C Gaston 3 Table1 14,032,114 17,580,910 25.29%

AL E C Gaston 4 Table1 14,192,836 16,180,310 14.00%

AL E C Gaston 5 Table1 33,819 48,089,378 36,094 46,377,835 6.73% -3.56%

AL Gadsden 1 Substitution 4,893 3,518,404 4,716 3,257,292 -3.62% -7.42%

AL Gadsden 2 Substitution 5,168 3,649,976 4,876 3,258,590 -5.65% -10.72%

FL Big Bend CS001 (BB01, BB02) 76,818 82,191 6.99%

FL Big Bend BB01 Table1 31,111,381 25,060,591 -19.45%

FL Big Bend BB02 Table1 31,794,469 30,800,835 -3.13%

FL Big Bend XS23 (BB03, BB04) 19,081 20,303 6.40%

FL Big Bend BB03 Table1 28,490,272 26,885,523 -5.63%

FL Big Bend BB04 Substitution 35,141,092 37,274,636 6.07%

FL Crist 4 Substitution 2,513 3,215,872 2,563 3,014,961 1.99% -6.25%

FL Crist 5 Substitution 2,566 3,291,052 4,354 5,324,877 69.68% 61.80%

FL Crist 6 Table1 13,304 16,798,233 10,243 12,828,682 -23.01% -23.63%

FL Crist 7 Table1 14,853 17,764,345 19,563 23,238,171 31.71% 30.81%

FL Scholz 1 Substitution 2,735 1,099,257 1,280 840,579 -53.20% -23.53%

FL Scholz 2 Substitution 3,186 1,316,280 2,112 1,337,456 -33.71% 1.61%

GA Arkwright CS001 (1, 2, 3, 4) 4,386 3,431 -21.77%

GA Arkwright 1 Substitution 815,186 595,763 -26.92%

GA Arkwright 2 Substitution 754,577 884,920 17.27%

GA Arkwright 3 Substitution 920,206 919,471 -0.08%

GA Arkwright 4 Substitution 850,114 701,745 -17.45%

GA Bowen 1BLR Table1 34,032 44,244,090 37,241 49,977,072 9.43% 12.96%

GA Bowen 2BLR Table1 36,655 47,089,666 33,675 45,321,466 -8.13% -3.75%

GA Bowen 3BLR Table1 46,269 61,120,578 40,828 54,811,544 -11.76% -10.32%

GA Bowen 4BLR Table1 40,205 52,430,313 42,319 57,170,903 5.26% 9.04%

GA Hammond CS001 (1, 2, 3) 7,246 8,609 18.81%

GA Hammond 1 Table1 3,515,633 3,940,166 12.08%

GA Hammond 2 Table1 2,751,274 3,355,443 21.96%

GA Hammond 3 Table1 3,572,759 4,809,927 34.63%

GA Hammond 4 Table1 14,364 19,191,000 16,571 23,714,698 15.36% 23.57%

GA Harllee Branch CS001 (1, 2) 26,616 29,845 12.13%

GA Harllee Branch 1 Substitution 14,360,313 13,643,892 -4.99%

GA Harllee Branch 2 Substitution 14,456,249 13,727,469 -5.04%

GA Harllee Branch CS002 (3, 4) 39,409 53,136 34.83%

GA Harllee Branch 3 Substitution 19,090,017 25,801,742 35.16%

B-3,1
APPENDIX B-3: EMISSIONS AND UTILIZATION OF PHASE 1 UNITS, 1996 AND 1997

1996 1997 Percent Change, 1996-1997

SO2 Utilization SO2 Utilization SO2 Utilization

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

GA Harllee Branch 4 Substitution 25,267,007 25,840,817 2.27%

GA Jack Mcdonough CS001 (MB1, MB2) 18,544 28,284 52.52%

GA Jack Mcdonough MB1 Table1 14,011,717 17,391,180 24.12%

GA Jack Mcdonough MB2 Table1 13,696,390 18,039,198 31.71%

GA Kraft CS001 (1, 2, 3, 4) 4,658 7,267 56.01%

GA Kraft 1 Substitution 1,626,008 1,485,281 -8.65%

GA Kraft 2 Substitution 1,220,370 1,775,138 45.46%

GA Kraft 3 Substitution 2,376,381 4,273,319 79.82%

GA Mcintosh 1 Substitution 5,713 6,698,411 6,175 7,719,743 8.09% 15.25%

GA Mitchell 3 Substitution 4,129 3,956,533 3,892 4,404,128 -5.74% 11.31%

GA Wansley 1 Table1 33,612 40,844,610 34,105 45,956,580 1.47% 12.52%

GA Wansley 2 Table1 37,059 44,775,798 32,258 45,215,913 -12.96% 0.98%

GA Yates Y1BR Table1 103 2,858,072 130 2,562,462 26.21% -10.34%

GA Yates CS001 (Y2BR, Y3BR) 4,869 6,412 31.69%

GA Yates Y2BR Table1 3,418,865 3,568,288 4.37%

GA Yates Y3BR Table1 3,189,297 3,782,679 18.61%

GA Yates CS002 (Y4BR, Y5BR) 5,211 8,923 71.23%

GA Yates Y4BR Table1 3,775,583 5,505,970 45.83%

GA Yates Y5BR Table1 3,086,657 4,525,391 46.61%

GA Yates Y6BR Table1 7,139 11,140,080 9,393 12,553,519 31.57% 12.69%

GA Yates Y7BR Table1 6,786 10,667,714 9,702 12,915,696 42.97% 21.07%

IA Burlington 1 Table1 6,309 9,611,935 6,352 10,287,375 0.68% 7.03%

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

IA George Neal North 1 Table1 3,782 9,453,477 4,040 9,719,336 6.82% 2.81%

IA Milton L Kapp 2 Table1 5,989 11,236,532 4,839 10,867,684 -19.20% -3.28%

IA Prairie Creek 4 Table1 2,744 8,290,105 2,985 8,488,312 8.78% 2.39%

IA Riverside 9 Table1 2,285 5,487,073 2,545 6,955,832 11.38% 26.77%

IL Baldwin 1 Table1 92,492 35,993,704 88,439 34,346,752 -4.38% -4.58%

IL Baldwin 2 Table1 75,793 29,324,128 92,284 35,355,084 21.76% 20.57%

IL Baldwin 3 Table1 105,553 40,432,952 95,312 37,180,092 -9.70% -8.05%

IL Coffeen CS0001 (1, 2) 43,755 47,756 9.14%

IL Coffeen 1 Table1 16,654,324 13,363,732 -19.76%

IL Coffeen 2 Table1 31,814,222 31,126,083 -2.16%

IL Collins CS1230 (1, 2, 3) 1,237 734 -40.66%

IL Collins 1 Substitution 6,755,310 11,265,975 66.77%

IL Collins 2 Substitution 6,510,067 9,640,762 48.09%

IL Collins 3 Substitution 9,007,079 12,954,183 43.82%

IL Grand Tower 7 Substitution 3,271 1,402,802 3,606 1,414,896 10.24% 0.86%

IL Grand Tower 8 Substitution 2,686 1,190,947 3,733 1,511,250 38.98% 26.89%

B-3,2
APPENDIX B-3: EMISSIONS AND UTILIZATION OF PHASE 1 UNITS, 1996 AND 1997

1996 1997 Percent Change, 1996-1997

SO2 Utilization SO2 Utilization SO2 Utilization

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

IL Grand Tower 9 Table1 13,596 5,945,488 18,586 7,209,130 36.70% 21.25%

IL Havana XS18 (1, 2, 3, 4, 5, 6, 7, 8) 0 0 0.00%

IL Havana 1 Substitution 0 0 0.00%

IL Havana 2 Substitution 0 0 0.00%

IL Havana 3 Substitution 0 0 0.00%

IL Havana 4 Substitution 0 0 0.00%

IL Havana 5 Substitution 0 0 0.00%

IL Havana 6 Substitution 0 0 0.00%

IL Havana 7 Substitution 0 0 0.00%

IL Havana 8 Substitution 0 0 0.00%

IL Hennepin 2 Table1 39,842 15,675,990 38,878 14,943,169 -2.42% -4.67%

IL Hutsonville 5 Substitution 10,772 4,959,359 8,640 3,962,435 -19.79% -20.10%

IL Hutsonville 6 Substitution 8,529 3,814,018 10,982 4,920,046 28.76% 29.00%

IL Joppa Steam CS1 (1, 2) 8,572 7,731 -9.81%

IL Joppa Steam 1 Table1 14,960,182 15,784,056 5.51%

IL Joppa Steam 2 Table1 15,969,238 13,883,968 -13.06%

IL Joppa Steam CS2 (3, 4) 8,071 7,998 -0.90%

IL Joppa Steam 3 Table1 15,215,573 14,698,413 -3.40%

IL Joppa Steam 4 Table1 13,102,754 15,562,767 18.77%

IL Joppa Steam CS3 (5, 6) 8,644 8,472 -1.99%

IL Joppa Steam 5 Table1 15,574,434 16,251,487 4.35%

IL Joppa Steam 6 Table1 14,937,071 15,991,784 7.06%

IL Kincaid CS0102 (1, 2) 20,051 41,096 104.96%

IL Kincaid 1 Table1 20,133,483 18,383,480 -8.69%

IL Kincaid 2 Table1 21,671,782 22,185,732 2.37%

IL Meredosia CS0001 (1, 2, 3, 4) 6,672 11,912 78.54%

IL Meredosia 1 Substitution 1,044,625 1,374,433 31.57%

IL Meredosia 2 Substitution 708,893 1,491,596 110.41%

IL Meredosia 3 Substitution 664,115 1,085,073 63.39%

IL Meredosia 4 Substitution 903,356 1,254,116 38.83%

IL Meredosia 5 Table1 15,943 11,667,552 15,950 10,034,553 0.04% -14.00%

IL Meredosia 6 Substitution 112 373,709 268 861,578 139.29% 130.55%

IL Newton 1 Substitution 11,148 27,174,200 16,698 8,356,418 49.78% -69.25%

IL Newton 2 Substitution 15,404 32,173,480 13,619 30,265,558 -11.59% -5.93%

IL Vermilion CS3 (1, 2) 579 6,208 972.19%

IL Vermilion 1 Substitution 358,330 1,488,706 315.46%

IL Vermilion 2 Table1 743,988 2,826,121 279.86%

IL Wood River 1 Substitution 0 0 0 513,068 0.00% n/a

IN Bailly XS12 (7, 8) 3,835 4,736 23.49%

IN Bailly 7 Table1 12,840,429 12,242,636 -4.66%

IN Bailly 8 Table1 18,413,238 19,485,943 5.83%

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

B-3,3
APPENDIX B-3: EMISSIONS AND UTILIZATION OF PHASE 1 UNITS, 1996 AND 1997

1996 1997 Percent Change, 1996-1997

SO2 Utilization SO2 Utilization SO2 Utilization

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

IN Cayuga 1 Table1 38,676 31,117,238 56,992 36,475,622 47.36% 17.22%

IN Cayuga 2 Table1 32,134 24,405,552 51,796 33,321,734 61.19% 36.53%

IN Clifty Creek CS001 (1, 2, 3) 50,661 44,612 -11.94%

IN Clifty Creek 1 Table1 16,465,964 15,465,093 -6.08%

IN Clifty Creek 2 Table1 15,821,604 13,905,955 -12.11%

IN Clifty Creek 3 Table1 16,401,939 15,588,922 -4.96%

IN Clifty Creek CS002 (4, 5, 6) 53,668 48,844 -8.99%

IN Clifty Creek 4 Table1 16,332,747 15,077,344 -7.69%

IN Clifty Creek 5 Table1 18,078,609 14,905,050 -17.55%

IN Clifty Creek 6 Table1 16,547,688 14,827,092 -10.40%

IN Elmer W Stout 50 Table1 6,045 5,588,803 7,444 6,831,371 23.14% 22.23%

IN Elmer W Stout 60 Table1 5,466 4,806,792 6,561 5,794,145 20.03% 20.54%

IN Elmer W Stout 70 Table1 26,764 24,589,328 22,717 20,926,892 -15.12% -14.89%

IN F B Culley XS23 (2, 3) 4,800 5,152 7.33%

IN F B Culley 2 Table1 5,328,808 6,571,635 23.32%

IN F B Culley 3 Table1 20,119,291 19,032,117 -5.40%

IN Frank E Ratts 1SG1 Table1 5,284 4,590,729 8,566 7,431,668 62.11% 61.88%

IN Frank E Ratts 2SG1 Table1 8,066 7,114,275 7,989 6,728,905 -0.95% -5.42%

IN Gibson CS0003 (1, 2) 91,546 79,183 -13.50%

IN Gibson 1 Table1 37,712,577 34,509,324 -8.49%

IN Gibson 2 Table1 41,393,737 36,456,884 -11.93%

IN Gibson XS34 (3, 4) 44,266 49,170 11.08%

IN Gibson 3 Table1 30,798,399 35,455,094 15.12%

IN Gibson 4 Table1 37,063,085 47,452,516 28.03%

IN H T Pritchard CS596 (5, 6) 7,068 8,909 26.05%

IN H T Pritchard 5 Substitution 1,463,618 2,270,877 55.16%

IN H T Pritchard 6 Table1 5,275,111 6,791,206 28.74%

IN Michigan City 12 Table1 14,841 30,794,272 15,262 25,071,593 2.84% -18.58%

IN Petersburg 1 Table1 10,473 17,644,936 2,893 17,617,335 -72.38% -0.16%

IN Petersburg 2 Table1 16,002 32,737,948 4,162 32,198,117 -73.99% -1.65%

IN R Gallagher CS0001 (1, 2) 21,609 25,662 18.76%

IN R Gallagher 1 Table1 6,645,958 7,671,999 15.44%

IN R Gallagher 2 Table1 8,185,232 8,015,384 -2.08%

IN R Gallagher CS0002 (3, 4) 28,826 21,183 -26.51%

IN R Gallagher 3 Table1 11,064,458 6,067,619 -45.16%

IN R Gallagher 4 Table1 9,937,363 5,817,989 -41.45%

IN Tanners Creek U4 Table1 59,876 30,441,214 61,344 31,794,760 2.45% 4.45%

IN Wabash River 1 Table1 4,197 5,111,474 1,051 7,893,969 -74.96% 54.44%

IN Wabash River CS0005 (2, 3, 5, 6) 38,986 37,577 -3.61%

IN Wabash River 2 Table1 4,532,020 4,391,103 -3.11%

IN Wabash River 3 Table1 4,199,125 3,873,572 -7.75%

IN Wabash River 5 Table1 3,972,597 4,755,001 19.70%

IN Wabash River 6 Table1 17,273,741 17,074,386 -1.15%

B-3,4
APPENDIX B-3: EMISSIONS AND UTILIZATION OF PHASE 1 UNITS, 1996 AND 1997

1996 1997 Percent Change, 1996-1997

SO2 Utilization SO2 Utilization SO2 Utilization

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

IN Warrick XS123 (1, 2, 3) 37,290 79,037 111.95%

IN Warrick 1 Opt-In 6,195,697 11,713,016 89.05%

IN Warrick 2 Opt-In 4,496,464 12,777,383 184.17%

IN Warrick 3 Opt-In 6,377,241 12,080,812 89.44%

IN Warrick 4 Table1 55,629 26,106,280 39,864 22,244,140 -28.34% -14.79%

KS La Cygne 1 Substitution 6,372 44,868,034 6,927 43,169,137 8.71% -3.79%

KS Quindaro 2 Table1 1,715 1,535,354 4,052 7,372,206 136.27% 380.16%

KY Coleman C1 Table1 17,749 10,119,011 15,985 10,496,532 -9.94% 3.73%

KY Coleman C2 Table1 19,919 11,620,382 18,600 12,638,043 -6.62% 8.76%

KY Coleman C3 Table1 19,488 11,302,035 16,037 11,091,506 -17.71% -1.86%

KY Cooper CS1 (1, 2) 16,652 15,818 -5.01%

KY Cooper 1 Table1 6,203,553 6,128,337 -1.21%

KY Cooper 2 Table1 11,866,456 11,663,764 -1.71%

KY E W Brown 1 Table1 5,500 5,585,611 5,869 5,534,775 6.71% -0.91%

KY E W Brown CS003 (2, 3) 33,012 30,538 -7.49%

KY E W Brown 2 Table1 9,847,964 10,048,618 2.04%

KY E W Brown 3 Table1 25,069,168 20,628,855 -17.71%

KY East Bend 2 Substitution 11,023 43,733,535 13,083 50,645,676 18.69% 15.81%

KY Elmer Smith XS12 (1, 2) 6,280 7,688 22.42%

KY Elmer Smith 1 Table1 8,264,788 11,998,464 45.18%

KY Elmer Smith 2 Table1 19,624,228 20,955,232 6.78%

KY Ghent 1 Table1 7,484 38,126,562 7,399 38,733,307 -1.14% 1.59%

KY Green River 5 Table1 10,192 4,951,922 12,409 5,782,136 21.75% 16.77%

KY H L Spurlock 1 Table1 13,334 19,356,664 15,669 23,080,348 17.51% 19.24%

KY Hmp&L Station 2 H1 Table1 2,315 12,528,434 2,142 11,602,514 -7.47% -7.39%

KY Hmp&L Station 2 H2 Table1 3,578 13,374,978 2,482 12,675,842 -30.63% -5.23%

KY Paradise 3 Table1 146,291 60,987,316 173,285 72,721,248 18.45% 19.24%

KY R D Green G1 Substitution 1,085 18,663,054 1,004 15,541,123 -7.47% -16.73%

KY R D Green G2 Substitution 2,314 16,982,755 1,323 18,062,324 -42.83% 6.36%

KY Shawnee 10 Table1 2,399 9,307,313 2,204 8,930,212 -8.13% -4.05%

MA Brayton Point 2 Compensating 9,479 17,544,316 10,646 18,916,857 12.31% 7.82%

MA Mount Tom 1 Substitution 7,314 9,908,995 9,742 11,867,279 33.20% 19.76%

MD C P Crane 1 Table1 15,581 12,760,058 12,740 9,725,873 -18.23% -23.78%

MD C P Crane 2 Table1 13,163 10,904,815 17,050 13,359,231 29.53% 22.51%

MD Chalk Point CSE12 (1, 2) 37,211 39,789 6.93%

MD Chalk Point 1 Table1 19,675,719 17,952,950 -8.76%

B-3,5
APPENDIX B-3: EMISSIONS AND UTILIZATION OF PHASE 1 UNITS, 1996 AND 1997

1996 1997 Percent Change, 1996-1997

SO2 Utilization SO2 Utilization SO2 Utilization

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

MD Chalk Point 2 Table1 16,341,786 21,531,764 31.76%

MD Chalk Point 3 Substitution 2,678 4,153,249 2,716 7,631,900 1.42% 83.76%

MD Chalk Point 4 Substitution 1,354 6,556,094 1,155 5,790,004 -14.70% -11.69%

MD Morgantown 1 Table1 37,236 37,010,782 39,650 38,101,385 6.48% 2.95%

MD Morgantown 2 Table1 35,542 35,650,179 33,341 31,834,220 -6.19% -10.70%

MD R P Smith 9 Substitution 78 107,596 71 92,709 -8.97% -13.84%

MD R P Smith 11 Substitution 2,069 2,833,072 2,264 2,986,412 9.42% 5.41%

MI B C Cobb 4 Substitution 6,336 11,310,884 3,979 6,805,495 -37.20% -39.83%

MI Dan E Karn 1 Substitution 9,765 16,478,448 8,807 14,730,605 -9.81% -10.61%

MI Dan E Karn 2 Substitution 9,506 15,850,441 9,694 16,458,054 1.98% 3.83%

MI J C Weadock CS0009 (7, 8) 10,792 10,679 -1.05%

MI J C Weadock 7 Substitution 8,551,701 6,903,489 -19.27%

MI J C Weadock 8 Substitution 9,538,250 12,153,154 27.41%

MI J H Campbell CS0009 (1, 2) 22,771 21,219 -6.82%

MI J H Campbell 1 Table1 15,942,587 15,183,312 -4.76%

MI J H Campbell 2 Table1 20,946,592 19,817,269 -5.39%

MI J H Campbell 3 Substitution 22,141 47,025,128 23,853 49,783,254 7.73% 5.87%

MI J R Whiting 2 Substitution 4,433 7,084,353 3,558 5,626,938 -19.74% -20.57%

MI J R Whiting 3 Substitution 4,236 6,515,893 4,801 7,534,265 13.34% 15.63%

MN High Bridge CS0001 (3, 4, 5, 6) 3,768 3,848 2.12%

MN High Bridge 3 Substitution 1,397,090 1,150,622 -17.64%

MN High Bridge 4 Substitution 1,915,234 1,616,997 -15.57%

MN High Bridge 5 Substitution 5,087,413 3,694,447 -27.38%

MN High Bridge 6 Table1 9,292,112 10,898,522 17.29%

MN Sherburne County CS1 (1, 2) 10,156 9,132 -10.08%

MN Sherburne County 1 Substitution 51,389,952 50,979,544 -0.80%

MN Sherburne County 2 Substitution 51,477,248 44,659,663 -13.24%

MO Asbury 1 Table1 6,339 11,502,268 9,236 14,205,505 45.70% 23.50%

MO Hawthorn 5 Substitution 8,352 26,458,409 9,297 25,785,864 11.31% -2.54%

MO James River 3 Substitution 2,358 2,206,094 1,164 2,276,282 -50.64% 3.18%

MO James River 4 Substitution 4,874 3,885,157 1,780 3,692,173 -63.48% -4.97%

MO James River 5 Table1 8,513 7,562,737 3,633 6,726,246 -57.32% -11.06%

MO Labadie 1 Table1 11,681 37,988,343 12,452 30,729,514 6.60% -19.11%

MO Labadie 2 Table1 6,899 20,875,392 15,063 35,276,040 118.34% 68.98%

MO Labadie 3 Table1 51,536 42,373,060 12,635 36,859,037 -75.48% -13.01%

MO Labadie 4 Table1 36,790 31,934,417 13,777 38,871,905 -62.55% 21.72%

MO Meramec 1 Substitution 3,344 3,684,584 3,147 4,756,769 -5.89% 29.10%

MO Meramec 2 Substitution 3,522 4,040,199 3,388 5,293,610 -3.80% 31.02%

MO Meramec 3 Substitution 5,682 6,226,032 3,364 4,832,568 -40.80% -22.38%

MO Meramec 4 Substitution 4,678 5,282,678 7,040 10,263,395 50.49% 94.28%

B-3,6
APPENDIX B-3: EMISSIONS AND UTILIZATION OF PHASE 1 UNITS, 1996 AND 1997

1996 1997 Percent Change, 1996-1997

SO2 Utilization SO2 Utilization SO2 Utilization

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

MO Montrose 1 Table1 2,877 11,154,264 2,705 10,856,432 -5.98% -2.67%

MO Montrose CS023 (2, 3) 5,431 6,684 23.07%

MO Montrose 2 Table1 10,700,341 11,916,991 11.37%

MO Montrose 3 Table1 9,451,260 12,520,698 32.48%

MO New Madrid 1 Table1 8,855 37,130,588 8,924 37,657,244 0.78% 1.42%

MO New Madrid 2 Table1 8,007 38,456,072 10,474 48,200,332 30.81% 25.34%

MO Rush Island 1 Substitution 13,225 37,060,698 13,484 39,221,199 1.96% 5.83%

MO Rush Island 2 Substitution 14,044 39,943,130 11,659 33,936,175 -16.98% -15.04%

MO Sibley CS0001 (1, 2, 3) 17,893 19,839 10.88%

MO Sibley 1 Substitution 3,323,704 3,298,131 -0.77%

MO Sibley 2 Substitution 3,278,399 3,238,192 -1.23%

MO Sibley 3 Table1 25,052,823 23,606,317 -5.77%

MO Sioux 1 Table1 22,358 16,705,724 30,140 26,885,257 34.81% 60.93%

MO Sioux 2 Table1 34,038 26,575,398 24,968 23,482,964 -26.65% -11.64%

MO Southwest 1 Substitution 3,066 11,742,780 3,785 14,063,350 23.45% 19.76%

MO Thomas Hill MB1 Table1 2,934 13,624,236 3,382 14,948,531 15.27% 9.72%

MO Thomas Hill MB2 Table1 4,685 22,154,212 4,978 22,396,264 6.25% 1.09%

MO Thomas Hill MB3 Substitution 9,798 45,296,444 11,224 48,569,132 14.55% 7.23%

MS Jack Watson 4 Table1 19,627 14,560,545 11,749 13,197,197 -40.14% -9.36%

MS Jack Watson 5 Table1 43,588 32,937,887 30,551 33,634,910 -29.91% 2.12%

MS R D Morrow 1 Substitution 4,847 15,620,857 5,072 14,735,176 4.64% -5.67%

MS R D Morrow 2 Substitution 3,749 12,152,295 4,255 13,281,477 13.50% 9.29%

NH Merrimack 1 Table1 10,606 7,621,232 13,509 10,134,559 27.37% 32.98%

NH Merrimack 2 Table1 24,037 19,712,188 26,144 24,340,602 8.77% 23.48%

NJ B L England 1 Table1 18,568 9,042,302 15,485 7,573,153 -16.60% -16.25%

NJ B L England 2 Table1 1,752 11,703,690 1,787 9,896,490 2.00% -15.44%

NY Dunkirk 2 Substitution 10,711 7,118,127 8,265 5,266,461 -22.84% -26.01%

NY Dunkirk CS0003 (3, 4) 31,867 34,072 6.92%

NY Dunkirk 3 Table1 10,792,925 10,571,064 -2.06%

NY Dunkirk 4 Table1 10,116,478 11,521,991 13.89%

NY Greenidge 6 Table1 7,144 5,512,986 8,126 7,315,437 13.75% 32.69%

NY Milliken XS12 (1, 2) 4,471 5,620 25.70%

NY Milliken 1 Table1 10,957,583 10,772,403 -1.69%

NY Milliken 2 Table1 11,668,817 11,167,395 -4.30%

NY Northport 1 Table1 6,060 11,054,751 4,868 8,862,375 -19.67% -19.83%

NY Northport 2 Table1 3,484 17,346,236 2,661 20,781,446 -23.62% 19.80%

NY Northport 3 Table1 4,649 8,524,632 4,279 7,753,803 -7.96% -9.04%

NY Northport 4 Substitution 1,384 16,800,166 822 20,283,682 -40.61% 20.74%

NY Oswego 4 Substitution 0 0 0 0 0.00% 0.00%

NY Oswego 5 Substitution 0 0 0 0 0.00% 0.00%

B-3,7
APPENDIX B-3: EMISSIONS AND UTILIZATION OF PHASE 1 UNITS, 1996 AND 1997

1996 1997 Percent Change, 1996-1997

SO2 Utilization SO2 Utilization SO2 Utilization

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

NY Oswego 6 Substitution 772 3,242,998 1,080 5,955,023 39.90% 83.63%

NY Port Jefferson 3 Table1 2,835 5,475,689 1,890 10,691,389 -33.33% 95.25%

NY Port Jefferson 4 Table1 4,499 8,003,758 1,602 7,149,114 -64.39% -10.68%

NY Roseton 1 Substitution 2,903 6,148,402 4,380 9,526,581 50.88% 54.94%

NY Roseton 2 Substitution 4,021 7,670,038 7,132 16,206,427 77.37% 111.30%

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

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

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

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

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

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

OH Ashtabula 7 Table1 41,910 12,131,030 39,662 12,618,530 -5.36% 4.02%

OH Ashtabula CS1 (8, 9, 10, 11) 25,409 6,942 -72.68%

OH Ashtabula 8 Substitution 1,841,817 0 -100.00%

OH Ashtabula 9 Substitution 1,608,432 0 -100.00%

OH Ashtabula 10 Substitution 2,174,929 191,965 -91.17%

OH Ashtabula 11 Substitution 2,343,541 2,020,623 -13.78%

OH Avon Lake 9 Substitution 1,231 1,685,434 483 597,938 -60.76% -64.52%

OH Avon Lake 10 Substitution 3,668 5,121,816 4,274 4,816,566 16.52% -5.96%

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

OH Avon Lake 12 Table1 27,863 34,561,596 28,037 32,607,684 0.62% -5.65%

OH Bay Shore CS5 (1, 2, 3, 4) 25,025 13,874 -44.56%

OH Bay Shore 1 Substitution 7,693,884 6,545,978 -14.92%

OH Bay Shore 2 Substitution 6,622,437 7,024,540 6.07%

OH Bay Shore 3 Substitution 7,582,696 7,316,921 -3.51%

OH Bay Shore 4 Substitution 10,498,676 10,813,196 3.00%

OH Cardinal 1 Table1 76,138 29,017,768 84,875 30,461,782 11.48% 4.98%

OH Cardinal 2 Table1 28,212 26,408,584 58,818 36,443,680 108.49% 38.00%

OH Conesville CS012 (1, 2) 25,264 31,975 26.56%

OH Conesville 1 Table1 5,267,264 7,169,706 36.12%

OH Conesville 2 Table1 5,867,919 7,275,241 23.98%

OH Conesville 3 Table1 12,794 5,872,821 16,424 7,352,729 28.37% 25.20%

OH Conesville 4 Table1 58,778 27,390,004 83,428 37,503,728 41.94% 36.92%

OH Eastlake 1 Table1 13,095 6,729,324 16,379 7,958,930 25.08% 18.27%

OH Eastlake 2 Table1 13,779 7,530,250 15,487 7,503,532 12.40% -0.35%

OH Eastlake 3 Table1 10,599 5,833,256 16,084 8,015,486 51.75% 37.41%

OH Eastlake 4 Table1 22,538 11,184,656 26,322 13,078,361 16.79% 16.93%

OH Eastlake 5 Table1 60,719 31,917,980 53,952 27,418,308 -11.14% -14.10%

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

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

OH Edgewater 13 Table1 4 169,446 3 190,520 -25.00% 12.44%

OH Gen J M Gavin 1 Table1 28,370 85,368,952 16,854 86,726,768 -40.59% 1.59%

OH Gen J M Gavin 2 Table1 40,672 100,099,832 16,812 74,801,544 -58.66% -25.27%

B-3,8
APPENDIX B-3: EMISSIONS AND UTILIZATION OF PHASE 1 UNITS, 1996 AND 1997

1996 1997 Percent Change, 1996-1997

SO2 Utilization SO2 Utilization SO2 Utilization

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

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

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

OH J M Stuart 1 Substitution 22,910 32,856,554 23,885 33,042,560 4.26% 0.57%

OH J M Stuart 2 Substitution 28,054 39,776,416 28,883 40,245,244 2.96% 1.18%

OH J M Stuart 3 Substitution 25,957 36,913,980 25,127 35,157,140 -3.20% -4.76%

OH J M Stuart 4 Substitution 22,226 31,602,492 26,949 37,297,652 21.25% 18.02%

OH Kyger Creek CS001 (1, 2, 3, 4, 5) 123,599 111,419 -9.85%

OH Kyger Creek 1 Table1 15,541,682 14,525,068 -6.54%

OH Kyger Creek 2 Table1 15,701,555 15,156,232 -3.47%

OH Kyger Creek 3 Table1 15,148,702 15,150,482 0.01%

OH Kyger Creek 4 Table1 14,375,389 14,638,612 1.83%

OH Kyger Creek 5 Table1 16,381,780 14,960,636 -8.68%

OH Lake Shore 18 Substitution 1,433 2,396,829 497 1,692,121 -65.32% -29.40%

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

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

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

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

OH Miami Fort 6 Table1 12,392,706 7,661,698 -38.18%

OH Miami Fort 7 Table1 38,985 38,049,581 38,666 36,213,342 -0.82% -4.83%

OH Miami Fort CS056 (5-1, 5-2, 6) 14,421 10,087 -30.05%

OH Miami Fort 5-1 Table1 516,801 876,111 69.53%

OH Miami Fort 5-2 Table1 516,801 876,111 69.53%

OH Muskingum River CS014 (1, 2, 3, 4) 160,368 161,924 0.97%

OH Muskingum River 1 Table1 9,743,860 12,198,445 25.19%

OH Muskingum River 2 Table1 10,890,512 9,313,687 -14.48%

OH Muskingum River 3 Table1 11,872,478 11,202,854 -5.64%

OH Muskingum River 4 Table1 11,380,074 11,861,307 4.23%

OH Muskingum River 5 Table1 20,223 36,993,688 21,872 37,710,912 8.15% 1.94%

OH Niles XS12 (1, 2) 22,485 13,340 -40.67%

OH Niles 1 Table1 7,986,488 7,712,996 -3.42%

OH Niles 2 Table1 5,619,661 3,337,159 -40.62%

OH Picway 9 Table1 15,071 5,014,683 16,843 5,797,157 11.76% 15.60%

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

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

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

OH R E Burger CS0001 (1, 2, 3, 4, 5, 6, 7, 8) 62,557 46,842 -25.12%

OH R E Burger 1 Substitution 0 0 0.00%

OH R E Burger 2 Substitution 0 0 0.00%

OH R E Burger 3 Substitution 0 0 0.00%

OH R E Burger 4 Substitution 0 0 0.00%

OH R E Burger 5 Table1 342,333 754,982 120.54%

OH R E Burger 6 Table1 345,590 648,775 87.73%

OH R E Burger 7 Table1 12,358,365 10,903,432 -11.77%

OH R E Burger 8 Table1 10,058,514 10,116,964 0.58%

B-3,9
APPENDIX B-3: EMISSIONS AND UTILIZATION OF PHASE 1 UNITS, 1996 AND 1997

1996 1997 Percent Change, 1996-1997

SO2 Utilization SO2 Utilization SO2 Utilization

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

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

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

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

OH W H Sammis 5 Table1 12,247 17,229,437 16,619 20,677,232 35.70% 20.01%

OH W H Sammis 6 Table1 30,444 40,507,621 33,154 38,089,788 8.90% -5.97%

OH W H Sammis 7 Table1 27,966 39,173,092 30,208 34,854,765 8.02% -11.02%

OH Walter C Beckjord 5 Table1 22,761 15,965,398 14,542 12,225,260 -36.11% -23.43%

OH Walter C Beckjord 6 Table1 40,041 27,366,092 33,099 27,984,274 -17.34% 2.26%

PA Armstrong 1 Table1 16,496 11,760,419 16,282 10,871,651 -1.30% -7.56%

PA Armstrong 2 Table1 15,654 10,843,803 16,847 11,549,498 7.62% 6.51%

PA Bruce Mansfield 1 Substitution 5,831 39,049,744 6,555 50,690,148 12.42% 29.81%

PA Bruce Mansfield 2 Substitution 8,159 51,758,064 7,123 43,678,116 -12.70% -15.61%

PA Brunner Island CS102 (1, 2) 47,771 44,391 -7.08%

PA Brunner Island 1 Table1 19,038,246 16,560,069 -13.02%

PA Brunner Island 2 Table1 21,075,806 21,563,393 2.31%

PA Brunner Island 3 Table1 44,832 39,299,942 52,349 45,583,894 16.77% 15.99%

PA Cheswick 1 Table1 39,980 32,374,384 47,510 37,412,616 18.83% 15.56%

PA Conemaugh 1 Table1 3,376 56,341,839 3,754 66,299,762 11.20% 17.67%

PA Conemaugh 2 Table1 3,732 60,156,610 3,502 61,034,531 -6.16% 1.46%

PA Hatfield's Ferry XS123 (1, 2, 3) 153,413 138,630 -9.64%

PA Hatfield's Ferry 1 Table1 32,091,132 24,642,421 -23.21%

PA Hatfield's Ferry 2 Table1 33,885,414 29,327,176 -13.45%

PA Hatfield's Ferry 3 Table1 27,107,067 35,212,528 29.90%

PA Martins Creek CS102 (1, 2) 24,601 23,661 -3.82%

PA Martins Creek 1 Table1 10,422,634 9,668,016 -7.24%

PA Martins Creek 2 Table1 7,831,516 9,896,340 26.37%

PA Martins Creek 3 Substitution 2,442 5,348,032 2,082 6,918,551 -14.74% 29.37%

PA Martins Creek 4 Substitution 3,016 8,813,199 1,938 5,638,557 -35.74% -36.02%

PA Mitchell 33 Substitution 728 9,346,753 1,080 16,667,369 48.35% 78.32%

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

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

PA Portland 1 Table1 11,963 8,004,960 11,574 7,648,014 -3.25% -4.46%

PA Portland 2 Table1 13,820 9,654,232 17,463 11,972,331 26.36% 24.01%

PA Shawville 1 Table1 10,587 7,071,835 15,230 9,672,852 43.86% 36.78%

PA Shawville 2 Table1 13,474 8,841,290 15,609 9,861,149 15.85% 11.54%

PA Shawville CS1 (3, 4) 29,884 33,064 10.64%

PA Shawville 3 Table1 12,231,908 10,382,892 -15.12%

PA Shawville 4 Table1 9,337,793 12,363,361 32.40%

PA Sunbury 3 Table1 9,511 7,316,803 11,343 8,209,041 19.26% 12.19%

PA Sunbury 4 Table1 10,939 8,495,968 11,326 8,102,198 3.54% -4.63%

B-3,10
APPENDIX B-3: EMISSIONS AND UTILIZATION OF PHASE 1 UNITS, 1996 AND 1997

1996 1997 Percent Change, 1996-1997

SO2 Utilization SO2 Utilization SO2 Utilization

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

TN Allen 1 Table1 5,434 13,232,597 6,754 14,847,074 24.29% 12.20%

TN Allen 2 Table1 6,503 15,751,898 7,134 16,492,487 9.70% 4.70%

TN Allen 3 Table1 8,395 13,330,030 7,436 17,656,804 -11.42% 32.46%

TN Cumberland 1 Table1 9,524 88,223,696 9,846 111,236,832 3.38% 26.08%

TN Cumberland 2 Table1 13,252 121,294,176 11,122 118,698,432 -16.07% -2.14%

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

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

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

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

TN Gallatin CSGA12 (1, 2) 55,363 50,974 -7.93%

TN Gallatin 1 Table1 14,169,010 14,146,293 -0.16%

TN Gallatin 2 Table1 15,977,846 13,928,512 -12.83%

TN Gallatin CSGA34 (3, 4) 61,303 66,129 7.87%

TN Gallatin 3 Table1 15,888,894 17,014,207 7.08%

TN Gallatin 4 Table1 18,810,130 18,173,564 -3.38%

TN Johnsonville CSJO10 (1, 2, 3, 4, 5, 6, 7, 8, 9, 10) 126,367 115,938 -8.25%

TN Johnsonville 1 Table1 8,771,161 6,385,030 -27.20%

TN Johnsonville 2 Table1 8,608,948 8,774,006 1.92%

TN Johnsonville 3 Table1 9,183,864 8,605,129 -6.30%

TN Johnsonville 4 Table1 8,805,822 8,448,481 -4.06%

TN Johnsonville 5 Table1 5,801,129 7,847,835 35.28%

TN Johnsonville 6 Table1 8,424,067 6,274,393 -25.52%

TN Johnsonville 7 Table1 10,200,693 8,278,704 -18.84%

TN Johnsonville 8 Table1 10,405,425 9,340,449 -10.23%

TN Johnsonville 9 Table1 7,736,863 9,054,961 17.04%

TN Johnsonville 10 Table1 9,778,394 6,274,673 -35.83%

WI Alma CS1 (B4, B5) 3,471 5,608 61.57%

WI Alma B4 Substitution 1,924,740 2,637,034 37.01%

WI Alma B5 Substitution 2,887,317 3,645,037 26.24%

WI Edgewater 3 Substitution 1,482 4,283,009 1,620 4,010,042 9.31% -6.37%

WI Edgewater 4 Table1 7,378 21,529,980 7,968 19,448,932 8.00% -9.67%

WI Genoa 1 Table1 11,420 17,924,364 12,750 23,336,894 11.65% 30.20%

WI J P Madgett B1 Substitution 4,145 15,667,498 4,946 21,777,568 19.32% 39.00%

WI Nelson Dewey CS1 (1, 2) 3,836 6,092 58.81%

WI Nelson Dewey 1 Table1 6,313,485 8,239,503 30.51%

WI Nelson Dewey 2 Table1 6,231,595 8,457,749 35.72%

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

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

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

WI North Oak Creek 4 Table1 0 0 0 0 0.00% 0.00%

WI Pulliam CS56 (5, 6) 1,518 2,141 41.04%

WI Pulliam 5 Substitution 2,476,389 3,268,887 32.00%

WI Pulliam 6 Substitution 3,796,526 5,354,200 41.03%

WI Pulliam 7 Substitution 1,574 6,789,476 1,540 6,492,200 -2.16% -4.38%

B-3,11
APPENDIX B-3: EMISSIONS AND UTILIZATION OF PHASE 1 UNITS, 1996 AND 1997

1996 1997 Percent Change, 1996-1997

SO2 Utilization SO2 Utilization SO2 Utilization

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

WI Pulliam 8 Table1 2,445 10,388,203 2,264 9,850,126 -7.40% -5.18%

WI Rock River 1 Substitution 1,337 4,420,448 1,560 4,227,957 16.68% -4.35%

WI Rock River 2 Substitution 1,389 4,396,844 1,776 4,871,904 27.86% 10.80%

WI South Oak Creek CS3 (5, 6) 13,543 15,452 14.10%

WI South Oak Creek 5 Table1 14,710,533 15,182,914 3.21%

WI South Oak Creek 6 Table1 9,735,973 9,504,521 -2.38%

WI South Oak Creek CS4 (7, 8) 20,718 25,934 25.18%

WI South Oak Creek 7 Table1 18,264,686 22,009,580 20.50%

WI South Oak Creek 8 Table1 18,247,312 19,063,307 4.47%

WI Weston 1 Substitution 1,106 3,536,812 1,318 4,399,791 19.17% 24.40%

WI Weston 2 Substitution 2,021 6,567,751 1,678 5,695,054 -16.97% -13.29%

WV Albright 1 Substitution 1,449 1,190,327 1,578 1,269,279 8.90% 6.63%

WV Albright 2 Substitution 1,962 1,675,656 1,682 1,333,070 -14.27% -20.44%

WV Albright 3 Table1 9,246 7,663,974 9,380 7,411,488 1.45% -3.29%

WV Fort Martin 1 Table1 33,684 26,435,504 42,733 36,022,017 26.86% 36.26%

WV Fort Martin 2 Table1 37,468 29,454,119 44,413 37,187,816 18.54% 26.26%

WV Harrison XS123 (1, 2, 3) 16,469 6,298 -61.76%

WV Harrison 1 Table1 50,422,229 48,646,367 -3.52%

WV Harrison 2 Table1 49,485,012 48,426,987 -2.14%

WV Harrison 3 Table1 46,729,368 45,939,810 -1.69%

WV Kammer CS013 (1, 2, 3) 119,369 126,273 5.78%

WV Kammer 1 Table1 15,233,808 13,727,107 -9.89%

WV Kammer 2 Table1 12,862,993 15,078,749 17.23%

WV Kammer 3 Table1 14,005,666 17,379,095 24.09%

WV Mitchell CS012 (1, 2) 53,152 57,239 7.69%

WV Mitchell 1 Table1 47,955,776 40,025,964 -16.54%

WV Mitchell 2 Table1 34,334,844 50,581,435 47.32%

WV Mt Storm CS0 (1, 2) 107,211 92,716 -13.52%

WV Mt Storm 1 Table1 40,588,560 35,476,403 -12.60%

WV Mt Storm 2 Table1 43,397,872 36,446,948 -16.02%

WV Mt Storm 3 Table1 5,096 28,675,658 4,052 45,013,972 -20.49% 56.98%

WV Rivesville 7 Substitution 233 287,932 235 299,093 0.86% 3.88%

WV Rivesville 8 Substitution 1,037 1,232,614 1,234 1,531,972 19.00% 24.29%

WV Willow Island 1 Substitution 1,872 1,841,991 1,790 1,713,256 -4.38% -6.99%

WV Willow Island 2 Substitution 6,739 7,224,854 8,067 8,554,928 19.71% 18.41%

NOTES: (a) Identifies the affected unit as listed in Table 1, or as a substitution, compensating, or opt-in unit.

B-3,12
APPENDIX B-4: EMISSIONS AND ALLOWANCE HOLDINGS OF PHASE 1 UNITS

SO2 SO2 1997 Held in Allowances Deducted Under Allowances

Emissions Emissions Allowances Unit Accounts Deducted for Special Phase I Carried Over

State Plant Name Stack/Unit ID Unit Type (a) 1996 (b) 1997(b) Allocated (c) as of 1/30/98 Emissions (d) Provisions to 1998

AL Colbert CSCO14 (1, 2, 3, 4) 31,939 27,220

AL Colbert 1 Table1 13,213 14,781 6,417 8,364

AL Colbert 2 Table1 14,907 20,654 7,515 13,139

AL Colbert 3 Table1 14,995 19,207 5,927 13,280

AL Colbert 4 Table1 15,005 20,849 7,361 13,488

AL Colbert 5 Table1 58,218 50,803 36,202 55,883 50,803 5,080

AL E C Gaston CS0CAN (1, 2) 22,028 24,949

AL E C Gaston 1 Table1 17,624 20,277 11,996 8,281

AL E C Gaston 2 Table1 18,052 21,191 12,953 8,238

AL E C Gaston CS0CBN (3, 4) 19,812 26,165

AL E C Gaston 3 Table1 17,828 19,849 13,625 6,224

AL E C Gaston 4 Table1 18,773 25,106 12,540 12,566

AL E C Gaston 5 Table1 33,819 36,094 58,265 39,407 36,094 3,313

AL Gadsden 1 Substitution 4,893 4,716 5,158 6,303 4,716 1,587

AL Gadsden 2 Substitution 5,168 4,876 5,374 6,911 4,876 2,035

FL Big Bend CS001 (BB01, BB02) 76,818 82,191

FL Big Bend BB01 Table1 27,662 38,367 36,986 1,381

FL Big Bend BB02 Table1 26,387 47,216 45,205 2,011

FL Big Bend XS23 (BB03, BB04) 19,081 20,303

FL Big Bend BB03 Table1 26,036 40,281 14,212 26,069

FL Big Bend BB04 Substitution 6,400 10,488 6,091 4,397

FL Crist 4 Substitution 2,513 2,563 9,953 23,497 2,563 20,934

FL Crist 5 Substitution 2,566 4,354 9,374 22,485 4,354 18,131

FL Crist 6 Table1 13,304 10,243 18,695 29,645 10,243 19,402

FL Crist 7 Table1 14,853 19,563 30,846 33,239 19,563 13,676

FL Scholz 1 Substitution 2,735 1,280 8,282 20,024 1,280 18,744

FL Scholz 2 Substitution 3,186 2,112 8,572 19,969 2,112 17,857

GA Arkwright CS001 (1, 2, 3, 4) 4,386 3,431

GA Arkwright 1 Substitution 2,437 2,437 858 1,579

GA Arkwright 2 Substitution 2,240 2,240 858 1,382

GA Arkwright 3 Substitution 3,944 3,944 858 3,086

GA Arkwright 4 Substitution 3,159 3,159 857 2,302

GA Bowen 1BLR Table1 34,032 37,241 54,838 40,784 37,241 3,543

GA Bowen 2BLR Table1 36,655 33,675 53,329 65,469 33,675 31,794

GA Bowen 3BLR Table1 46,269 40,828 69,862 87,459 40,828 46,631

GA Bowen 4BLR Table1 40,205 42,319 69,852 89,372 42,319 47,053

GA Hammond CS001 (1, 2, 3) 7,246 8,609

GA Hammond 1 Table1 8,549 8,549 2,870 5,679

GA Hammond 2 Table1 8,977 8,977 2,870 6,107

GA Hammond 3 Table1 8,676 8,676 2,869 5,807

GA Hammond 4 Table1 14,364 16,571 36,650 60,946 16,571 44,375

GA Harllee Branch CS001 (1, 2) 26,616 29,845

GA Harllee Branch 1 Substitution 19,221 30,640 14,923 15,717

GA Harllee Branch 2 Substitution 22,735 41,182 14,922 26,260

GA Harllee Branch CS002 (3, 4) 39,409 53,136

GA Harllee Branch 3 Substitution 31,280 47,122 26,568 20,554

GA Harllee Branch 4 Substitution 31,042 46,406 26,568 19,838

GA Jack Mcdonough CS001 (MB1, MB2) 18,544 28,284

GA Jack Mcdonough MB1 Table1 19,386 38,772 14,142 24,630

GA Jack Mcdonough MB2 Table1 20,058 40,116 14,142 25,974

GA Kraft CS001 (1, 2, 3, 4) 4,658 7,267

GA Kraft 1 Substitution 2,265 4,293 1,433 2,860

GA Kraft 2 Substitution 2,137 4,369 1,712 2,657

GA Kraft 3 Substitution 4,121 7,305 4,122 3,183

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

SO2 SO2 1997 Held in Allowances Deducted Under Allowances

Emissions Emissions Allowances Unit Accounts Deducted for Special Phase I Carried Over

State Plant Name Stack/Unit ID Unit Type (a) 1996 (b) 1997(b) Allocated (c) as of 1/30/98 Emissions (d) Provisions to 1998

GA Mcintosh 1 Substitution 5,713 6,175 7,146 10,261 6,175 4,086

GA Mitchell 3 Substitution 4,129 3,892 10,792 21,584 3,892 17,692

GA Wansley 1 Table1 33,612 34,105 68,908 86,728 34,105 52,623

GA Wansley 2 Table1 37,059 32,258 63,708 79,977 32,258 47,719

GA Yates Y1BR Table1 103 130 9,533 14,234 130 14,104

GA Yates CS001 (Y2BR, Y3BR) 4,869 6,412

GA Yates Y2BR Table1 6,855 13,710 3,206 10,504

GA Yates Y3BR Table1 6,767 13,534 3,206 10,328

GA Yates CS002 (Y4BR, Y5BR) 5,211 8,923

GA Yates Y4BR Table1 8,676 17,352 4,462 12,890

GA Yates Y5BR Table1 9,162 18,324 4,461 13,863

GA Yates Y6BR Table1 7,139 9,393 24,108 48,216 9,393 38,823

GA Yates Y7BR Table1 6,786 9,702 20,915 41,830 9,702 32,128

IA Burlington 1 Table1 6,309 6,352 10,428 15,660 6,352 9,308

IA Des Moines 11 Table1 0 0 2,259 0 0 0

IA George Neal North 1 Table1 3,782 4,040 2,571 8,296 4,040 4,256

IA Milton L Kapp 2 Table1 5,989 4,839 13,437 26,872 4,839 201 (e) 21,832

IA Prairie Creek 4 Table1 2,744 2,985 7,965 15,578 2,985 12,593

IA Riverside 9 Table1 2,285 2,545 3,885 7,542 2,545 4,997

IL Baldwin 1 Table1 92,492 88,439 46,052 92,821 88,439 4,382

IL Baldwin 2 Table1 75,793 92,284 48,695 95,044 92,284 53 (e) 2,707

IL Baldwin 3 Table1 105,553 95,312 46,644 97,851 95,312 2,539

IL Coffeen CS0001 (1, 2) 43,755 47,756

IL Coffeen 1 Table1 12,925 15,509 15,364 145

IL Coffeen 2 Table1 39,102 35,360 32,392 2,968

IL Collins CS1230 (1, 2, 3) 1,237 734

IL Collins 1 Substitution 1,217 3,203 245 2,958

IL Collins 2 Substitution 1,050 2,642 245 2,397

IL Collins 3 Substitution 1,856 5,080 244 4,836

IL Grand Tower 7 Substitution 3,271 3,606 1,068 3,690 3,606 84

IL Grand Tower 8 Substitution 2,686 3,733 1,015 3,892 3,733 159

IL Grand Tower 9 Table1 13,596 18,586 6,479 18,802 18,586 216

IL Havana XS18 (1, 2, 3, 4, 5, 6, 7, 8) 0 0

IL Havana 1 Substitution 34 350 0 23 (e) 327

IL Havana 2 Substitution 43 43 0 30 (e) 13

IL Havana 3 Substitution 34 34 0 23 (e) 11

IL Havana 4 Substitution 34 34 0 23 (e) 11

IL Havana 5 Substitution 34 34 0 23 (e) 11

IL Havana 6 Substitution 34 34 0 23 (e) 11

IL Havana 7 Substitution 34 34 0 23 (e) 11

IL Havana 8 Substitution 34 34 0 23 (e) 11

IL Hennepin 2 Table1 39,842 38,878 20,182 41,466 38,878 1,624

IL Hutsonville 5 Substitution 10,772 8,640 9,661 8,721 8,640 81

IL Hutsonville 6 Substitution 8,529 10,982 9,837 11,062 10,982 80

IL Joppa Steam CS1 (1, 2) 8,572 7,731

IL Joppa Steam 1 Table1 12,259 28,446 3,865 24,581

IL Joppa Steam 2 Table1 10,487 23,130 3,866 19,264

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

SO2 SO2 1997 Held in Allowances Deducted Under Allowances

Emissions Emissions Allowances Unit Accounts Deducted for Special Phase I Carried Over

State Plant Name Stack/Unit ID Unit Type (a) 1996 (b) 1997(b) Allocated (c) as of 1/30/98 Emissions (d) Provisions to 1998

IL Joppa Steam CS2 (3, 4) 8,071 7,998

IL Joppa Steam 3 Table1 11,947 27,960 3,999 23,961

IL Joppa Steam 4 Table1 11,061 25,301 3,999 21,302

IL Joppa Steam CS3 (5, 6) 8,644 8,472

IL Joppa Steam 5 Table1 11,119 22,952 4,236 18,716

IL Joppa Steam 6 Table1 10,341 20,618 4,236 16,382

IL Kincaid CS0102 (1, 2) 20,051 41,096

IL Kincaid 1 Table1 34,564 33,564 20,548 13,016

IL Kincaid 2 Table1 37,063 37,063 20,548 16,515

IL Meredosia CS0001 (1, 2, 3, 4) 6,672 11,912

IL Meredosia 1 Substitution 1,245 3,310 3,129 181

IL Meredosia 2 Substitution 1,355 3,660 3,392 268

IL Meredosia 3 Substitution 1,173 2,746 2,478 268

IL Meredosia 4 Substitution 1,078 3,143 2,913 230

IL Meredosia 5 Table1 15,943 15,950 15,227 16,328 15,950 378

IL Meredosia 6 Substitution 112 268 44 407 268 139

IL Newton 1 Substitution 11,148 16,698 14,599 16,928 16,698 230

IL Newton 2 Substitution 15,404 13,619 6,346 14,495 13,619 876

IL Vermilion CS3 (1, 2) 579 6,208

IL Vermilion 1 Substitution 12,972 16,086 2,173 1147 (e) 12,766

IL Vermilion 2 Table1 9,735 19,122 4,035 1258 (e) 13,829

IL Wood River 1 Substitution 0 0 0 12 0 12

IN Bailly XS12 (7, 8) 3,835 4,736

IN Bailly 7 Table1 15,981 5,840 1,610 4,230

IN Bailly 8 Table1 21,592 19,550 3,126 16,424

IN Breed 1 Table1 0 0 20,280 53,390 0 53,390

IN Cayuga 1 Table1 38,676 56,992 36,581 72,517 56,992 15,525

IN Cayuga 2 Table1 32,134 51,796 37,415 66,877 51,796 15,081

IN Clifty Creek CS001 (1, 2, 3) 50,661 44,612

IN Clifty Creek 1 Table1 19,620 22,350 14,871 7,479

IN Clifty Creek 2 Table1 19,289 19,254 14,871 4,383

IN Clifty Creek 3 Table1 19,873 19,886 14,870 5,016

IN Clifty Creek CS002 (4, 5, 6) 53,668 48,844

IN Clifty Creek 4 Table1 19,552 20,761 16,281 4,480

IN Clifty Creek 5 Table1 18,851 19,418 16,281 3,137

IN Clifty Creek 6 Table1 19,844 25,512 16,282 9,230

IN Elmer W Stout 50 Table1 6,045 7,444 4,253 7,703 7,444 259

IN Elmer W Stout 60 Table1 5,466 6,561 5,229 6,872 6,561 311

IN Elmer W Stout 70 Table1 26,764 22,717 25,883 23,548 22,717 831

IN F B Culley XS23 (2, 3) 4,800 5,152

IN F B Culley 2 Table1 4,703 6,760 5,152 1,608

IN F B Culley 3 Table1 18,603 24,264 0 24,264

IN Frank E Ratts 1SG1 Table1 5,284 8,566 9,131 13,798 8,566 5,232

IN Frank E Ratts 2SG1 Table1 8,066 7,989 9,296 10,708 7,989 2,719

IN Gibson CS0003 (1, 2) 91,546 79,183

IN Gibson 1 Table1 44,288 51,581 38,879 12,702

IN Gibson 2 Table1 44,956 53,347 40,304 13,043

IN Gibson XS34 (3, 4) 44,266 49,170

IN Gibson 3 Table1 45,033 54,897 39,798 15,099

IN Gibson 4 Table1 44,200 48,392 9,372 39,020

IN H T Pritchard CS596 (5, 6) 7,068 8,909

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

SO2 SO2 1997 Held in Allowances Deducted Under Allowances

Emissions Emissions Allowances Unit Accounts Deducted for Special Phase I Carried Over

State Plant Name Stack/Unit ID Unit Type (a) 1996 (b) 1997(b) Allocated (c) as of 1/30/98 Emissions (d) Provisions to 1998

IN H T Pritchard 5 Substitution 1,458 2,347 2,254 93

IN H T Pritchard 6 Table1 6,325 6,889 6,655 234

IN Michigan City 12 Table1 14,841 15,262 25,553 76,494 15,262 61,232

IN Petersburg 1 Table1 10,473 2,893 18,011 3,134 2,893 241

IN Petersburg 2 Table1 16,002 4,162 35,496 4,382 4,162 220

IN R Gallagher CS0001 (1, 2) 21,609 25,662

IN R Gallagher 1 Table1 7,115 16,595 12,543 4,052

IN R Gallagher 2 Table1 7,980 16,509 13,119 3,390

IN R Gallagher CS0002 (3, 4) 28,826 21,183

IN R Gallagher 3 Table1 7,159 13,659 10,842 2,817

IN R Gallagher 4 Table1 8,386 13,136 10,341 2,795

IN Tanners Creek U4 Table1 59,876 61,344 27,209 142,970 61,344 81,626

IN Wabash River 1 Table1 4,197 1,051 5,502 3,801 1,051 2,750

IN Wabash River CS0005 (2, 3, 5, 6) 38,986 37,577

IN Wabash River 2 Table1 3,135 6,116 5,439 677

IN Wabash River 3 Table1 4,111 6,445 4,847 1,598

IN Wabash River 5 Table1 4,023 7,800 5,995 1,805

IN Wabash River 6 Table1 13,462 24,302 21,296 3,006

IN Warrick XS123 (1, 2, 3) 37,290 79,037

IN Warrick 1 Opt-In 30,372 27,472 25,917 1,555

IN Warrick 2 Opt-In 30,732 31,793 27,571 1309 (e) 2,913

IN Warrick 3 Opt-In 27,668 25,861 25,549 312

IN Warrick 4 Table1 55,629 39,864 29,577 40,358 39,864 494

KS La Cygne 1 Substitution 6,372 6,927 23,489 7,208 6,927 281

KS Quindaro 2 Table1 1,715 4,052 4,109 6,637 4,052 2,585

KY Coleman C1 Table1 17,749 15,985 10,954 16,398 15,985 413

KY Coleman C2 Table1 19,919 18,600 12,502 19,084 18,600 484

KY Coleman C3 Table1 19,488 16,037 12,015 16,456 16,037 419

KY Cooper CS1 (1, 2) 16,652 15,818

KY Cooper 1 Table1 7,254 10,199 5,220 4,979

KY Cooper 2 Table1 14,917 21,273 10,598 10,675

KY E W Brown 1 Table1 5,500 5,869 6,923 21,757 5,869 15,888

KY E W Brown CS003 (2, 3) 33,012 30,538

KY E W Brown 2 Table1 10,623 33,787 9,975 23,812

KY E W Brown 3 Table1 25,413 81,493 20,563 60,930

KY East Bend 2 Substitution 11,023 13,083 17,447 18,735 13,083 5,652

KY Elmer Smith XS12 (1, 2) 6,280 7,688

KY Elmer Smith 1 Table1 6,348 2,400 2,306 94

KY Elmer Smith 2 Table1 14,031 5,600 5,382 218

KY Ghent 1 Table1 7,484 7,399 33,701 85,270 7,399 77,871

KY Green River 5 Table1 10,192 12,409 7,614 26,598 12,409 14,189

KY H L Spurlock 1 Table1 13,334 15,669 22,181 39,852 15,669 24,183

KY Hmp&L Station 2 H1 Table1 2,315 2,142 17,887 9,441 2,142 7,299

KY Hmp&L Station 2 H2 Table1 3,578 2,482 17,053 7,957 2,482 5,475

KY Paradise 3 Table1 146,291 173,285 57,613 277,612 173,285 104,327

KY R D Green G1 Substitution 1,085 1,004 5,041 9,658 1,004 8,654

KY R D Green G2 Substitution 2,314 1,323 5,827 11,170 1,323 9,847

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

SO2 SO2 1997 Held in Allowances Deducted Under Allowances

Emissions Emissions Allowances Unit Accounts Deducted for Special Phase I Carried Over

State Plant Name Stack/Unit ID Unit Type (a) 1996 (b) 1997(b) Allocated (c) as of 1/30/98 Emissions (d) Provisions to 1998

KY Shawnee 10 Table1 2,399 2,204 9,902 10,354 2,204 8,150

MA Brayton Point 2 Compensating 9,479 10,646 15,838 24,783 10,646 14,137

MA Mount Tom 1 Substitution 7,314 9,742 10,708 13,955 9,742 4,213

MD C P Crane 1 Table1 15,581 12,740 10,058 54,893 12,740 42,153

MD C P Crane 2 Table1 13,163 17,050 8,987 19,952 17,050 221 (f) 2,681

MD Chalk Point CSE12 (1, 2) 37,211 39,789

MD Chalk Point 1 Table1 21,333 21,486 18,091 3,395

MD Chalk Point 2 Table1 23,690 26,261 21,698 4,563

MD Chalk Point 3 Substitution 2,678 2,716 9,000 12,716 2,716 10,000

MD Chalk Point 4 Substitution 1,354 1,155 1,519 3,675 1,155 2,520

MD Morgantown 1 Table1 37,236 39,650 34,332 47,580 39,650 7,930

MD Morgantown 2 Table1 35,542 33,341 37,467 40,009 33,341 6,668

MD R P Smith 9 Substitution 78 71 386 74 71 3

MD R P Smith 11 Substitution 2,069 2,264 3,128 2,378 2,264 114

MI B C Cobb 4 Substitution 6,336 3,979 5,325 5,482 3,979 1,503

MI Dan E Karn 1 Substitution 9,765 8,807 10,151 9,778 8,807 971

MI Dan E Karn 2 Substitution 9,506 9,694 10,984 10,662 9,694 968

MI J C Weadock CS0009 (7, 8) 10,792 10,679

MI J C Weadock 7 Substitution 5,473 4,256 3,868 388

MI J C Weadock 8 Substitution 5,451 7,491 6,811 680

MI J H Campbell CS0009 (1, 2) 22,771 21,219

MI J H Campbell 1 Table1 18,773 10,138 9,205 933

MI J H Campbell 2 Table1 22,453 13,231 12,014 1,217

MI J H Campbell 3 Substitution 22,141 23,853 25,847 27,743 23,853 3,890

MI J R Whiting 2 Substitution 4,433 3,558 4,304 4,562 3,558 1,004

MI J R Whiting 3 Substitution 4,236 4,801 5,498 5,911 4,801 1,110

MN High Bridge CS0001 (3, 4, 5, 6) 3,768 3,848

MN High Bridge 3 Substitution 299 3,303 253 3,050

MN High Bridge 4 Substitution 242 2,060 356 1,704

MN High Bridge 5 Substitution 410 3,310 829 2,481

MN High Bridge 6 Table1 4,158 9,040 2,410 6,630

MN Sherburne County CS1 (1, 2) 10,156 9,132

MN Sherburne County 1 Substitution 4,681 15,837 4,869 10,968

MN Sherburne County 2 Substitution 4,727 15,778 4,263 11,515

MO Asbury 1 Table1 6,339 9,236 15,764 31,176 9,236 21,940

MO Hawthorn 5 Substitution 8,352 9,297 6,927 9,427 9,297 130

MO James River 3 Substitution 2,358 1,164 2,536 5,038 1,164 3,874

MO James River 4 Substitution 4,874 1,780 4,304 5,120 1,780 3,340

MO James River 5 Table1 8,513 3,633 4,722 4,599 3,633 966

MO Labadie 1 Table1 11,681 12,452 39,055 40,163 12,452 27,711

MO Labadie 2 Table1 6,899 15,063 36,718 44,300 15,063 29,237

MO Labadie 3 Table1 51,536 12,635 39,249 44,436 12,635 31,801

MO Labadie 4 Table1 36,790 13,777 34,994 38,669 13,777 24,892

MO Meramec 1 Substitution 3,344 3,147 1,816 4,202 3,147 1,055

MO Meramec 2 Substitution 3,522 3,388 1,948 4,313 3,388 925

MO Meramec 3 Substitution 5,682 3,364 4,166 4,714 3,364 1,350

MO Meramec 4 Substitution 4,678 7,040 4,507 8,982 7,040 1,942

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

SO2 SO2 1997 Held in Allowances Deducted Under Allowances

Emissions Emissions Allowances Unit Accounts Deducted for Special Phase I Carried Over

State Plant Name Stack/Unit ID Unit Type (a) 1996 (b) 1997(b) Allocated (c) as of 1/30/98 Emissions (d) Provisions to 1998

MO Montrose 1 Table1 2,877 2,705 7,196 2,840 2,705 135

MO Montrose CS023 (2, 3) 5,431 6,684

MO Montrose 2 Table1 7,984 3,370 3,262 108

MO Montrose 3 Table1 9,824 3,560 3,422 138

MO New Madrid 1 Table1 8,855 8,924 27,497 27,497 8,924 18,573

MO New Madrid 2 Table1 8,007 10,474 31,625 28,625 10,474 18,151

MO Rush Island 1 Substitution 13,225 13,484 26,935 46,168 13,484 32,684

MO Rush Island 2 Substitution 14,044 11,659 30,146 54,185 11,659 42,526

MO Sibley CS0001 (1, 2, 3) 17,893 19,839

MO Sibley 1 Substitution 2,782 5,120 2,381 2,739

MO Sibley 2 Substitution 3,332 6,749 2,381 4,368

MO Sibley 3 Table1 15,170 22,034 15,077 6,957

MO Sioux 1 Table1 22,358 30,140 21,976 36,270 30,140 6,130

MO Sioux 2 Table1 34,038 24,968 23,067 30,484 24,968 5,516

MO Southwest 1 Substitution 3,066 3,785 3,906 4,540 3,785 755

MO Thomas Hill MB1 Table1 2,934 3,382 9,980 4,480 3,382 1,098

MO Thomas Hill MB2 Table1 4,685 4,978 18,880 14,380 4,978 9,402

MO Thomas Hill MB3 Substitution 9,798 11,224 14,011 14,011 11,224 2,787

MS Jack Watson 4 Table1 19,627 11,749 17,439 19,887 11,749 8,138

MS Jack Watson 5 Table1 43,588 30,551 35,734 39,161 30,551 8,610

MS R D Morrow 1 Substitution 4,847 5,072 4,571 5,794 5,072 722

MS R D Morrow 2 Substitution 3,749 4,255 5,002 6,864 4,255 2,609

NH Merrimack 1 Table1 10,606 13,509 9,922 14,544 13,509 1,035

NH Merrimack 2 Table1 24,037 26,144 21,421 26,770 26,144 626

NJ B L England 1 Table1 18,568 15,485 8,822 15,822 15,485 337

NJ B L England 2 Table1 1,752 1,787 14,886 4,412 1,787 2,625

NY Dunkirk 2 Substitution 10,711 8,265 9,414 9,414 8,265 1,149

NY Dunkirk CS0003 (3, 4) 31,867 34,072

NY Dunkirk 3 Table1 12,268 33,216 16,355 16,861

NY Dunkirk 4 Table1 13,690 22,319 17,717 4,602

NY Greenidge 6 Table1 7,144 8,126 7,342 18,058 8,126 9,932

NY Milliken XS12 (1, 2) 4,471 5,620

NY Milliken 1 Table1 10,876 18,271 2,891 15,380

NY Milliken 2 Table1 12,083 17,378 2,729 14,649

NY Northport 1 Table1 6,060 4,868 19,289 14,832 4,868 9,964

NY Northport 2 Table1 3,484 2,661 23,476 7,403 2,661 4,742

NY Northport 3 Table1 4,649 4,279 25,783 15,612 4,279 11,333

NY Northport 4 Substitution 1,384 822 5,516 10,103 822 9,281

NY Oswego 4 Substitution 0 0 371 1,121 0 1,121

NY Oswego 5 Substitution 0 0 12,365 12,365 0 12,365

NY Oswego 6 Substitution 772 1,080 4,499 7,437 1,080 6,357

NY Port Jefferson 3 Table1 2,835 1,890 10,194 6,602 1,890 4,712

NY Port Jefferson 4 Table1 4,499 1,602 12,006 9,607 1,602 8,005

NY Roseton 1 Substitution 2,903 4,380 19,147 19,147 4,380 1435 (e) 13,332

NY Roseton 2 Substitution 4,021 7,132 16,872 16,872 7,132 176 (e) 9,564

OH Acme 13 Substitution 0 0 0 0 0 0

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

SO2 SO2 1997 Held in Allowances Deducted Under Allowances

Emissions Emissions Allowances Unit Accounts Deducted for Special Phase I Carried Over

State Plant Name Stack/Unit ID Unit Type (a) 1996 (b) 1997(b) Allocated (c) as of 1/30/98 Emissions (d) Provisions to 1998

OH Acme 14 Substitution 0 0 12 0 0 0

OH Acme 15 Substitution 0 0 16 0 0 0

OH Acme 16 Substitution 0 0 1,930 0 0 0

OH Acme 91 Substitution 0 0 740 0 0 0

OH Acme 92 Substitution 0 0 662 0 0 0

OH Ashtabula 7 Table1 41,910 39,662 18,351 42,659 39,662 2,997

OH Ashtabula CS1 (8, 9, 10, 11) 25,409 6,942

OH Ashtabula 8 Substitution 10,753 0 0 0

OH Ashtabula 9 Substitution 9,173 0 0 0

OH Ashtabula 10 Substitution 8,275 5,902 5,345 557

OH Ashtabula 11 Substitution 8,706 1,790 1,597 193

OH Avon Lake 9 Substitution 1,231 483 8,763 584 483 101

OH Avon Lake 10 Substitution 3,668 4,274 7,879 4,622 4,274 348

OH Avon Lake 11 Table1 0 0 12,771 0 0 0

OH Avon Lake 12 Table1 27,863 28,037 33,413 31,037 28,037 3,000

OH Bay Shore CS5 (1, 2, 3, 4) 25,025 13,874

OH Bay Shore 1 Substitution 7,414 3,267 3,052 215

OH Bay Shore 2 Substitution 6,957 3,066 2,775 291

OH Bay Shore 3 Substitution 7,585 3,343 3,052 291

OH Bay Shore 4 Substitution 12,481 5,500 4,995 505

OH Cardinal 1 Table1 76,138 84,875 37,568 89,119 84,875 4,244

OH Cardinal 2 Table1 28,212 58,818 42,008 77,183 58,818 18,365

OH Conesville CS012 (1, 2) 25,264 31,975

OH Conesville 1 Table1 4,615 24,980 15,888 9,092

OH Conesville 2 Table1 5,360 16,891 16,087 804

OH Conesville 3 Table1 12,794 16,424 6,029 17,245 16,424 821

OH Conesville 4 Table1 58,778 83,428 53,463 86,181 83,428 2,753

OH Eastlake 1 Table1 13,095 16,379 8,551 18,020 16,379 1,641

OH Eastlake 2 Table1 13,779 15,487 9,471 17,036 15,487 1,549

OH Eastlake 3 Table1 10,599 16,084 10,984 17,799 16,084 1,715

OH Eastlake 4 Table1 22,538 26,322 15,906 28,978 26,322 2,656

OH Eastlake 5 Table1 60,719 53,952 37,349 57,618 53,952 3,666

OH Edgewater 11 Substitution 0 0 1,062 0 0 0

OH Edgewater 12 Substitution 0 0 1,145 0 0 0

OH Edgewater 13 Table1 4 3 5,536 200 3 197

OH Gen J M Gavin 1 Table1 28,370 16,854 113,172 17,639 16,854 785

OH Gen J M Gavin 2 Table1 40,672 16,812 115,070 31,425 16,812 14,613

OH Gorge 25 Substitution 0 0 2,503 0 0 0

OH Gorge 26 Substitution 0 0 2,791 0 0 0

OH J M Stuart 1 Substitution 22,910 23,885 41,189 41,878 23,885 17,993

OH J M Stuart 2 Substitution 28,054 28,883 39,041 36,006 28,883 7,123

OH J M Stuart 3 Substitution 25,957 25,127 38,712 35,618 25,127 10,491

OH J M Stuart 4 Substitution 22,226 26,949 40,925 40,293 26,949 13,344

OH Kyger Creek CS001 (1, 2, 3, 4, 5) 123,599 111,419

OH Kyger Creek 1 Table1 18,773 22,783 22,284 499

OH Kyger Creek 2 Table1 18,072 22,783 22,284 499

OH Kyger Creek 3 Table1 17,439 22,783 22,284 499

OH Kyger Creek 4 Table1 18,218 22,783 22,284 499

OH Kyger Creek 5 Table1 18,247 22,783 22,283 500

OH Lake Shore 18 Substitution 1,433 497 4,508 598 497 101

OH Lake Shore 91 Substitution 0 0 44 0 0 0

OH Lake Shore 92 Substitution 0 0 80 0 0 0

OH Lake Shore 93 Substitution 0 0 62 0 0 0

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

SO2 SO2 1997 Held in Allowances Deducted Under Allowances

Emissions Emissions Allowances Unit Accounts Deducted for Special Phase I Carried Over

State Plant Name Stack/Unit ID Unit Type (a) 1996 (b) 1997(b) Allocated (c) as of 1/30/98 Emissions (d) Provisions to 1998

OH Lake Shore 94 Substitution 0 0 102 0 0 0

OH Miami Fort 6 Table1 12,475 11,815 8,076 3,739

OH Miami Fort 7 Table1 38,985 38,666 42,216 49,193 38,666 10,527

OH Miami Fort CS056 (5-1, 5-2, 6) 14,421 10,087

OH Miami Fort 5-1 Table1 417 1,213 1,006 207

OH Miami Fort 5-2 Table1 417 1,211 1,005 206

OH Muskingum River CS014 (1, 2, 3, 4) 160,368 161,924

OH Muskingum River 1 Table1 16,312 46,605 44,386 2,219

OH Muskingum River 2 Table1 15,533 35,307 33,626 1,681

OH Muskingum River 3 Table1 15,293 43,001 40,953 2,048

OH Muskingum River 4 Table1 12,914 45,107 42,959 2,148

OH Muskingum River 5 Table1 20,223 21,872 44,364 98,221 21,872 76,349

OH Niles XS12 (1, 2) 22,485 13,340

OH Niles 1 Table1 7,608 7,608 5,415 2,193

OH Niles 2 Table1 9,975 9,975 7,925 2,050

OH Picway 9 Table1 15,071 16,843 5,404 17,684 16,843 841

OH Poston 1 Substitution 0 0 0 3,797 0 3,797

OH Poston 2 Substitution 0 0 0 3,542 0 3,542

OH Poston 3 Substitution 0 0 0 4,642 0 4,642

OH R E Burger CS0001 (1, 2, 3, 4, 5, 6, 7, 8) 62,557 46,842

OH R E Burger 1 Substitution 2,820 0 0 0

OH R E Burger 2 Substitution 2,751 0 0 0

OH R E Burger 3 Substitution 2,891 0 0 0

OH R E Burger 4 Substitution 2,956 0 0 0

OH R E Burger 5 Table1 3,371 2,300 1,282 1,018

OH R E Burger 6 Table1 3,371 2,100 1,040 1,060

OH R E Burger 7 Table1 11,818 25,818 23,052 2,766

OH R E Burger 8 Table1 13,626 24,000 21,468 2,532

OH Toronto 9 Substitution 0 0 5,315 0 0 0

OH Toronto 10 Substitution 0 0 9,505 0 0 0

OH Toronto 11 Substitution 0 0 10,274 0 0 0

OH W H Sammis 5 Table1 12,247 16,619 26,496 21,500 16,619 4,881

OH W H Sammis 6 Table1 30,444 33,154 43,773 38,000 33,154 4,846

OH W H Sammis 7 Table1 27,966 30,208 47,380 76,730 30,208 46,522

OH Walter C Beckjord 5 Table1 22,761 14,542 9,811 19,394 14,542 4,852

OH Walter C Beckjord 6 Table1 40,041 33,099 25,235 37,080 33,099 3,981

PA Armstrong 1 Table1 16,496 16,282 14,031 17,096 16,282 814

PA Armstrong 2 Table1 15,654 16,847 15,024 17,689 16,847 842

PA Bruce Mansfield 1 Substitution 5,831 6,555 10,510 17,963 6,555 11,408

PA Bruce Mansfield 2 Substitution 8,159 7,123 11,537 18,848 7,123 11,581

PA Brunner Island CS102 (1, 2) 47,771 44,391

PA Brunner Island 1 Table1 27,030 39,615 19,283 20,332

PA Brunner Island 2 Table1 30,282 46,901 25,108 21,793

PA Brunner Island 3 Table1 44,832 52,349 52,404 92,661 52,349 40,312

PA Cheswick 1 Table1 39,980 47,510 38,139 52,542 47,510 5,032

PA Conemaugh 1 Table1 3,376 3,754 81,450 17,623 3,754 13,869

PA Conemaugh 2 Table1 3,732 3,502 91,666 17,253 3,502 13,751

PA Hatfield's Ferry XS123 (1, 2, 3) 153,413 138,630

PA Hatfield's Ferry 1 Table1 36,835 39,840 37,943 1,897

PA Hatfield's Ferry 2 Table1 36,338 48,042 45,754 2,288

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

SO2 SO2 1997 Held in Allowances Deducted Under Allowances

Emissions Emissions Allowances Unit Accounts Deducted for Special Phase I Carried Over

State Plant Name Stack/Unit ID Unit Type (a) 1996 (b) 1997(b) Allocated (c) as of 1/30/98 Emissions (d) Provisions to 1998

PA Hatfield's Ferry 3 Table1 39,210 57,679 54,933 2,746

PA Martins Creek CS102 (1, 2) 24,601 23,661

PA Martins Creek 1 Table1 12,327 27,556 11,693 15,863

PA Martins Creek 2 Table1 12,483 27,288 11,968 15,320

PA Martins Creek 3 Substitution 2,442 2,082 12,553 22,664 2,082 20,582

PA Martins Creek 4 Substitution 3,016 1,938 11,548 20,080 1,938 18,142

PA Mitchell 33 Substitution 728 1,080 1,101 1,134 1,080 54

PA New Castle 1 Substitution 0 0 1,367 0 0 0

PA New Castle 2 Substitution 0 0 1,520 0 0 0

PA Portland 1 Table1 11,963 11,574 5,784 45,304 11,574 33,730

PA Portland 2 Table1 13,820 17,463 9,961 18,090 17,463 627

PA Shawville 1 Table1 10,587 15,230 10,048 16,180 15,230 950

PA Shawville 2 Table1 13,474 15,609 10,048 16,584 15,609 975

PA Shawville CS1 (3, 4) 29,884 33,064

PA Shawville 3 Table1 13,846 15,978 15,029 949

PA Shawville 4 Table1 13,700 19,165 18,035 1,130

PA Sunbury 3 Table1 9,511 11,343 8,530 25,511 11,343 14,168

PA Sunbury 4 Table1 10,939 11,326 11,149 24,324 11,326 12,998

TN Allen 1 Table1 5,434 6,754 14,917 17,029 6,754 10,275

TN Allen 2 Table1 6,503 7,134 16,329 18,410 7,134 11,276

TN Allen 3 Table1 8,395 7,436 15,258 21,518 7,436 14,082

TN Cumberland 1 Table1 9,524 9,846 114,325 163,284 9,846 153,438

TN Cumberland 2 Table1 13,252 11,122 126,157 155,249 11,122 144,127

TN DuPont Johnsonville JVD1 Opt-In 0 0 1,778 0 0 0

TN DuPont Johnsonville JVD2 Opt-In 0 0 1,778 0 0 0

TN DuPont Johnsonville JVD3 Opt-In 0 0 1,777 0 0 0

TN DuPont Johnsonville JVD4 Opt-In 0 0 1,777 0 0 0

TN Gallatin CSGA12 (1, 2) 55,363 50,974

TN Gallatin 1 Table1 17,400 28,217 25,663 2,554

TN Gallatin 2 Table1 16,855 27,854 25,311 2,543

TN Gallatin CSGA34 (3, 4) 61,303 66,129

TN Gallatin 3 Table1 19,493 35,426 32,201 3,225

TN Gallatin 4 Table1 20,701 37,316 33,928 3,388

TN Johnsonville CSJO10 (1, 2, 3, 4, 5, 6, 7, 8, 9, 10) 126,367 115,938

TN Johnsonville 1 Table1 7,585 12,916 9,317 3,599

TN Johnsonville 2 Table1 7,828 16,724 12,803 3,921

TN Johnsonville 3 Table1 8,189 16,522 12,597 3,925

TN Johnsonville 4 Table1 7,780 16,227 12,329 3,898

TN Johnsonville 5 Table1 8,023 12,637 11,488 1,149

TN Johnsonville 6 Table1 7,682 10,676 9,158 1,518

TN Johnsonville 7 Table1 8,744 13,397 12,178 1,219

TN Johnsonville 8 Table1 8,471 15,010 13,644 1,366

TN Johnsonville 9 Table1 6,894 14,612 13,284 1,328

TN Johnsonville 10 Table1 7,351 10,056 9,140 916

WI Alma CS1 (B4, B5) 3,471 5,608

WI Alma B4 Substitution 2,207 9,299 2,804 6,495

WI Alma B5 Substitution 3,624 16,817 2,804 14,013

WI Edgewater 3 Substitution 1,482 1,620 4,493 10,831 1,620 9,211

WI Edgewater 4 Table1 7,378 7,968 24,099 14,583 7,968 6,615

WI Genoa 1 Table1 11,420 12,750 22,103 25,776 12,750 13,026

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

SO2 SO2 1997 Held in Allowances Deducted Under Allowances

Emissions Emissions Allowances Unit Accounts Deducted for Special Phase I Carried Over

State Plant Name Stack/Unit ID Unit Type (a) 1996 (b) 1997(b) Allocated (c) as of 1/30/98 Emissions (d) Provisions to 1998

WI J P Madgett B1 Substitution 4,145 4,946 6,407 10,240 4,946 5,294

WI Nelson Dewey CS1 (1, 2) 3,836 6,092

WI Nelson Dewey 1 Table1 5,852 8,736 2,998 5,738

WI Nelson Dewey 2 Table1 6,504 10,369 3,094 7,275

WI North Oak Creek 1 Table1 0 0 5,083 0 0 0

WI North Oak Creek 2 Table1 0 0 5,005 0 0 0

WI North Oak Creek 3 Table1 0 0 5,229 0 0 0

WI North Oak Creek 4 Table1 0 0 6,154 0 0 0

WI Pulliam CS56 (5, 6) 1,518 2,141

WI Pulliam 5 Substitution 2,097 980 814 166

WI Pulliam 6 Substitution 2,844 1,590 1,327 263

WI Pulliam 7 Substitution 1,574 1,540 7,317 1,800 1,540 260

WI Pulliam 8 Table1 2,445 2,264 7,312 2,700 2,264 436

WI Rock River 1 Substitution 1,337 1,560 5,398 13,220 1,560 11,660

WI Rock River 2 Substitution 1,389 1,776 4,034 9,279 1,776 7,503

WI South Oak Creek CS3 (5, 6) 13,543 15,452

WI South Oak Creek 5 Table1 9,416 10,453 9,503 950

WI South Oak Creek 6 Table1 11,723 6,544 5,949 595

WI South Oak Creek CS4 (7, 8) 20,718 25,934

WI South Oak Creek 7 Table1 15,754 15,287 13,897 1,390

WI South Oak Creek 8 Table1 15,375 13,241 12,037 1,204

WI Weston 1 Substitution 1,106 1,318 1,579 1,773 1,318 455

WI Weston 2 Substitution 2,021 1,678 3,580 2,000 1,678 322

WV Albright 1 Substitution 1,449 1,578 4,831 1,657 1,578 79

WV Albright 2 Substitution 1,962 1,682 5,024 1,766 1,682 84

WV Albright 3 Table1 9,246 9,380 11,684 9,849 9,380 469

WV Fort Martin 1 Table1 33,684 42,733 40,496 44,870 42,733 2,137

WV Fort Martin 2 Table1 37,468 44,413 40,116 46,634 44,413 2,221

WV Harrison XS123 (1, 2, 3) 16,469 6,298

WV Harrison 1 Table1 68,078 2,262 2,156 106

WV Harrison 2 Table1 64,488 2,243 2,136 107

WV Harrison 3 Table1 57,730 2,106 2,006 100

WV Kammer CS013 (1, 2, 3) 119,369 126,273

WV Kammer 1 Table1 18,247 39,647 37,758 1,889

WV Kammer 2 Table1 18,948 43,421 41,353 2,068

WV Kammer 3 Table1 16,932 49,520 47,162 2,358

WV Mitchell CS012 (1, 2) 53,152 57,239

WV Mitchell 1 Table1 42,823 75,177 25,390 49,787

WV Mitchell 2 Table1 44,312 75,957 31,849 44,108

WV Mt Storm CS0 (1, 2) 107,211 92,716

WV Mt Storm 1 Table1 42,570 65,008 46,358 18,650

WV Mt Storm 2 Table1 34,644 54,923 46,358 8,565

WV Mt Storm 3 Table1 5,096 4,052 56,589 115,845 4,052 111,793

WV Rivesville 7 Substitution 233 235 1,009 247 235 12

WV Rivesville 8 Substitution 1,037 1,234 3,059 1,296 1,234 62

WV Willow Island 1 Substitution 1,872 1,790 1,855 3,735 1,790 1,945

WV Willow Island 2 Substitution 6,739 8,067 7,765 8,470 8,067 403

NOTES:

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

SO2 SO2 1997 Held in Allowances Deducted Under Allowances

Emissions Emissions Allowances Unit Accounts Deducted for Special Phase I Carried Over

State Plant Name Stack/Unit ID Unit Type (a) 1996 (b) 1997(b) Allocated (c) as of 1/30/98 Emissions (d) Provisions to 1998

(a) Identifies the affected unit as listed in Table 1, or as a substitution, compensating, or opt-in unit.

(b) Both 1996 and 1997 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 1997 emissions for units that are not connected to a common stack. For units sharing a common stack, an apportionment was 

 made either by the unit or by EPA to divide up the stack's emissions among the units sharing the stack. 

(e) Deducted due to underutilization provisions. There is no effective SO2 emissions cap during Phase I for units not affected by the

Acid Rain Program until Phase II. Therefore, if underutilization were not taken into account, Phase I units could potentially shift their generation

responsibilities to Phase II units without surrendering allowances for the additional emissions resulting at those units. To ensure that allowances are

surrendered in this instance, each Phase I unit must explain any underutilization during Phase I (1995-1999). Any Phase I unit that had a lower

heat input in 1996 than the average heat input during the 1985-87 baseline years (i.e., was utilized less) must surrender allowances unless it explains

this decrease by shifts in generation to sulfur-free generators (e.g., hydroelectric or nuclear generators), energy conservation, improved unit efficiency,

overutilization at other Phase I units in the dispatch system, utilization of compensating units, or a decrease in dispatch system sales. If the reasons

for the underutilization do not fall into one or more of these categories, then it is presumed that the Phase I unit shifted generation to sulfur-emitting 

Phase II units and the Phase I unit has to surrender allowances. The amount of allowances surrendered is based on the amount of unexplained 

underutilization and the emission rates of the Phase II units.

(f) Deduction due to control-by-contract provisions. A Table I unit is allowed to designate a Phase II unit as a substitution unit only if both units are

under the control of the same owner or operator. A Table I unit must show a certain level of ownership interest and/or share a common operator with

the substitution unit, or have a contract between the owners and operators of the units that demonstrates a certain level of control of the substitution

unit (control-by-contract) by the Table I unit's owners and operators. This contract, among other things, is required to contain a commitment to reduce

the emissions rate at the substitution unit designated under ths provision by 30 percent or more. If the substitution unit fails to meet this reduction, it is

not subject to an enforcement action, but the Phase I unit that designated it must surrender allowances to cover the additional emissions released by

the substitution unit.

B-4, 11
APPENDIX C

Appendix C-1: List of Averaging Plans and Results in 1997

Appendix C-2: Compliance Results for the 265 NOx Affected Units in 1997

Appendix C-3: Compliance Results for the 272 Early Election Units in 1997
Appendix C-1: List of Averaging Plans and Results in 1997

C-1, 1

Operating Utility ORIS Code Plant Name, State and Units Plan Limit Plan Rate

Alabama Power Co

26 E C Gaston AL 1-5

0.48 0.44

7 Gadsden AL 1-2

CIPSCO 862 Grand Tower IL 07-09 0.46 0.43 863 Hutsonville IL 05, 06

864 Meredosia IL 01-05

6017 Newton IL 1, 2

Dairyland Power Coop

4140 Alma WI B4, B5

0.48 0.45

4143 Genoa WI 1

4271 J P Madgett WI B1

East Kentucky Power Coop 1384 Cooper KY 1, 2 0.50 0.40

Georgia Power Co

699 Arkwright GA 1-4

0.46 0.44

703 Bowen GA 1BLR - 4BLR

708 Hammond GA 1-4

709 Harllee Branch GA 2

710 Jack Mcdonough GA MB1, MB2

733 Kraft GA 1-3

6124 Mcintosh GA 1

727 Mitchell GA 3

6257 Scherer GA 3

6052 Wansley GA 1, 2

728 Yates GA Y1BR - Y7BR

GPU 3113 Portland PA 1, 2 0.45 0.37
Appendix C-1: List of Averaging Plans and Results in 1997

Operating Utility ORIS Code Plant Name, State and Units Plan Limit Plan Rate

C-1, 2

Gulf Power Co

641 Crist FL 4-7

0.48 0.42

2049 Jack Watson MS 4, 5

642 Scholz FL1, 2

6073 Victor J Daniel Jr MS 1, 2

Hoosier Energy 1043 Frank E Ratts IN 1SG1, 2SG1 0.50 0.49

IES Utilities, Inc. 1104 Burlington IA 1 0.47 0.29

1073 Prairie Creek IA 4

Illinois Power Co

889 Baldwin IL 3

0.45 0.38

892 Hennepin IL 2

897 Vermilion IL 1, 2

Indianapolis Power & Light 990 Elmer W Stout IN 50, 60, 70 0.45 0.34

991 H T Pritchard IN 3-6

994 Petersburg IN 1-4

Kentucky Utilities Company

1355 E W Brown KY 1-3

1356 Ghent KY 1 0.46 0.42

1357 Green River KY 5

Monongahela Power Co

3942 Albright WV 1-3

0.49 0.45

3178 Armstrong PA 1, 2

3944 Harrison WV 1-3

3943 Fort Martin WV 1

3181 Mitchell PA 33

6004 Pleasants PA 1, 2

1570 R P Smith PA 9, 11
Appendix C-1: List of Averaging Plans and Results in 1997

Operating Utility ORIS Code Plant Name, State and Units Plan Limit Plan Rate

C-1, 3

NYSEG

2527 Greenidge NY 6

0.45 0.40

2535 Milliken NY 1, 2

Northern States Power Co

1912 High Bridge MN 3-6

0.46 0.33

6090 Sherburne County MN 1, 2

Ohio Edison Co

6094 Bruce Mansfield PA 1, 2

0.50 0.43

2857 Edgewater OH 13

2858 Gorge OH 25, 26

3138 New Castle PA 1, 2

2867 Toronto OH 10, 11

2864 R E Burger OH 7, 8 

2866 W H Sammis OH 5, 6

PP&L

3140 Brunner Island PA 1-3

0.47 0.41

3148 Martins Creek PA 1, 2

3152 Sunbury PA 3, 4

PSI Energy, Inc. 1001 Cayuga IN 1, 2 0.48 0.43

6018 East Bend 2

6113 Gibson IN 1-4

2832 Miami Fort OH 6

1008 R Gallagher IN 1-4

1010 Wabash River IN 2, 3, 5, 6

2830 Walter C Beckjord 5, 6

South Mississippi Elec Power 6061 R D Morrow MS 1, 2 0.50 0.45
Appendix C-1: List of Averaging Plans and Results in 1997

Operating Utility ORIS Code Plant Name, State and Units Plan Limit Plan Rate

C-1, 4

Springfield City of (MO)

2161 James River MO 3-5

0.50 0.45

6195 Southwest MO 1

TVA

47 Colbert AL 1-5

0.47 0.44

3403 Gallatin TN 1-4

3406 Johnsonville TN 1-10

Union Electric Co

2103 Labadie MO 1-4

0.45 0.24

2104 Meramec MO 1-4

6155 Rush Island MO 1, 2

Wisconsin Electric Power

4040 Port Washington WI 1-4

0.48 0.36

4041 South Oak Creek WI 5-8

4042 Valley WI 1-4

Wisconsin Public Service Corp

4072 Pulliam WI 7, 8

0.47 0.36

4078 Weston WI 1-3
Appendix C-2: Compliance Results for the 265 Phase I NOx

 Affected Units in 1997

C-2, 1

1997

ST Plant Name Operating Utility

ORIS

Code Boiler Compliance Approach

Emission

Limit

Actual

Emission

Rate

AEL or 

Avg. Plan

Limit

Actual

Avg. Plan

Rate

1990

Emission

Rate

Change

from 1990

to 1997

AL Colbert TVA 47 1 Averaging Plan 0.50 0.46 0.47 0.44 0.80 -43%

AL Colbert TVA 47 2 Averaging Plan 0.50 0.46 0.47 0.44 0.67 -31%

AL Colbert TVA 47 3 Averaging Plan 0.50 0.46 0.47 0.44 0.83 -45%

AL Colbert TVA 47 4 Averaging Plan 0.50 0.46 0.47 0.44 0.86 -47%

AL Colbert TVA 47 5 Averaging Plan 0.50 0.40 0.47 0.44 0.78 -49%

AL E C Gaston Alabama Power Co 26 1 Averaging Plan 0.50 0.43 0.48 0.44 0.90 -52%

AL E C Gaston Alabama Power Co 26 2 Averaging Plan 0.50 0.43 0.48 0.44 0.78 -45%

AL E C Gaston Alabama Power Co 26 3 Averaging Plan 0.50 0.42 0.48 0.44 0.80 -48%

AL E C Gaston Alabama Power Co 26 4 Averaging Plan 0.50 0.42 0.48 0.44 0.80 -48%

AL E C Gaston Alabama Power Co 26 5 Averaging Plan 0.45 0.42 0.48 0.44 0.78 -46%

AL Gadsden Alabama Power Co 7 1 Averaging Plan 0.45 0.64 0.48 0.44 0.51 25%

AL Gadsden Alabama Power Co 7 2 Averaging Plan 0.45 0.68 0.48 0.44 0.56 21%

FL Big Bend Tampa Electric Co 645 BB04 Standard Limitation 0.45 0.41 0.46 -11%

FL Crist Gulf Power Co 641 4 Averaging Plan 0.45 0.52 0.48 0.42 0.43 21%

FL Crist Gulf Power Co 641 5 Averaging Plan 0.45 0.59 0.48 0.42 0.49 20%

FL Crist Gulf Power Co 641 6 Averaging Plan 0.50 0.45 0.48 0.42 1.04 -57%

FL Crist Gulf Power Co 641 7 Averaging Plan 0.50 0.44 0.48 0.42 1.16 -62%

FL Scholz Gulf Power Co 642 1 Averaging Plan 0.50 0.67 0.48 0.42 0.69 -3%

FL Scholz Gulf Power Co 642 2 Averaging Plan 0.50 0.77 0.48 0.42 0.80 -4%

GA Arkwright Georgia Power Co 699 1 Averaging Plan 0.45 0.77 0.46 0.44 0.90 -14%

GA Arkwright Georgia Power Co 699 2 Averaging Plan 0.45 0.77 0.46 0.44 0.90 -14%

GA Arkwright Georgia Power Co 699 3 Averaging Plan 0.50 0.77 0.46 0.44 0.90 -14%

GA Arkwright Georgia Power Co 699 4 Averaging Plan 0.50 0.77 0.46 0.44 0.90 -14%

GA Bowen Georgia Power Co 703 1BLR Averaging Plan 0.45 0.43 0.46 0.44 0.67 -36%

GA Bowen Georgia Power Co 703 2BLR Averaging Plan 0.45 0.44 0.46 0.44 0.65 -32%

GA Bowen Georgia Power Co 703 3BLR Averaging Plan 0.45 0.43 0.46 0.44 0.56 -23%

GA Bowen Georgia Power Co 703 4BLR Averaging Plan 0.45 0.42 0.46 0.44 0.58 -28%

GA Hammond Georgia Power Co 708 1 Averaging Plan 0.50 0.83 0.46 0.44 0.84 -1%

GA Hammond Georgia Power Co 708 2 Averaging Plan 0.50 0.83 0.46 0.44 0.84 -1%

GA Hammond Georgia Power Co 708 3 Averaging Plan 0.50 0.83 0.46 0.44 0.84 -1%

GA Hammond Georgia Power Co 708 4 Averaging Plan 0.50 0.46 0.46 0.44 1.20 -62%

GA Harllee Branch Georgia Power Co 709 2 Averaging Plan 0.50 0.72 0.46 0.44 0.99 -27%
Appendix C-2: Compliance Results for the 265 Phase I NOx

 Affected Units in 1997

1997

ST Plant Name Operating Utility

ORIS

Code Boiler Compliance Approach

Emission

Limit

Actual

Emission

Rate

AEL or 

Avg. Plan

Limit

Actual

Avg. Plan

Rate

1990

Emission

Rate

Change

from 1990

to 1997

C-2, 2

GA Jack McDonough Georgia Power Co 710 MB1 Averaging Plan 0.45 0.42 0.46 0.44 0.66 -36%

GA Jack McDonough Georgia Power Co 710 MB2 Averaging Plan 0.45 0.42 0.46 0.44 0.60 -30%

GA Kraft Savannah Electric & Power 733 1 Averaging Plan 0.45 0.62 0.46 0.44 0.40 55%

GA Kraft Savannah Electric & Power 733 2 Averaging Plan 0.45 0.62 0.46 0.44 0.40 55%

GA Kraft Savannah Electric & Power 733 3 Averaging Plan 0.45 0.62 0.46 0.44 0.40 55%

GA Mcintosh Savannah Electric & Power 6124 1 Averaging Plan 0.50 0.86 0.46 0.44 0.83 4%

GA Mitchell Georgia Power Co 727 3 Averaging Plan 0.45 0.62 0.46 0.44 0.61 2%

GA Scherer Georgia Power Co 6257 3 Averaging Plan 0.45 0.30 0.46 0.44 0.20 50%

GA Wansley Georgia Power Co 6052 1 Averaging Plan 0.45 0.41 0.46 0.44 0.73 -44%

GA Wansley Georgia Power Co 6052 2 Averaging Plan 0.45 0.41 0.46 0.44 0.67 -39%

GA Yates Georgia Power Co 728 Y1BR Averaging Plan 0.45 0.45 0.46 0.44 0.56 -20%

GA Yates Georgia Power Co 728 Y2BR Averaging Plan 0.45 0.48 0.46 0.44 0.62 -23%

GA Yates Georgia Power Co 728 Y3BR Averaging Plan 0.45 0.48 0.46 0.44 0.62 -23%

GA Yates Georgia Power Co 728 Y4BR Averaging Plan 0.45 0.39 0.46 0.44 0.56 -30%

GA Yates Georgia Power Co 728 Y5BR Averaging Plan 0.45 0.39 0.46 0.44 0.65 -40%

GA Yates Georgia Power Co 728 Y6BR Averaging Plan 0.45 0.33 0.46 0.44 0.67 -51%

GA Yates Georgia Power Co 728 Y7BR Averaging Plan 0.45 0.31 0.46 0.44 0.61 -49%

IA Burlington IES Utilities, Inc. 1104 1 Averaging Plan 0.45 0.29 0.47 0.29 0.63 -54%

IA Milton L Kapp Interstate Power Co 1048 2 Standard Limitation 0.45 0.35 0.80 -56%

IA Prairie Creek IES Utilities, Inc. 1073 4 Averaging Plan 0.50 0.29 0.47 0.29 1.05 -72%

IA Riverside MidAmerican Energy Company 1081 9 Standard Limitation 0.45 0.36 0.82 -56%

IL Baldwin Illinois Power Co 889 3 Averaging Plan 0.45 0.33 0.45 0.38 0.67 -51%

IL Grand Tower Cipsco 862 7 Averaging Plan 0.50 0.73 0.46 0.43 0.78 -6%

IL Grand Tower Cipsco 862 8 Averaging Plan 0.50 0.76 0.46 0.43 0.96 -21%

IL Grand Tower Cipsco 862 9 Averaging Plan 0.50 0.61 0.46 0.43 0.64 -5%

IL Hennepin Illinois Power Co 892 2 Averaging Plan 0.45 0.49 0.45 0.38 0.59 -17%

IL Hutsonville Cipsco 863 5 Averaging Plan 0.45 0.53 0.46 0.43 0.70 -24%

IL Hutsonville Cipsco 863 6 Averaging Plan 0.45 0.54 0.46 0.43 0.67 -19%

IL Joppa Steam Electric Energy Inc 887 1 Standard Limitation 0.45 0.28 0.56 -50%

IL Joppa Steam Electric Energy Inc 887 2 Standard Limitation 0.45 0.28 0.56 -50%

IL Joppa Steam Electric Energy Inc 887 3 Standard Limitation 0.45 0.26 0.56 -54%

IL Joppa Steam Electric Energy Inc 887 4 Standard Limitation 0.45 0.26 0.56 -54%
Appendix C-2: Compliance Results for the 265 Phase I NOx

 Affected Units in 1997

1997

ST Plant Name Operating Utility

ORIS

Code Boiler Compliance Approach

Emission

Limit

Actual

Emission

Rate

AEL or 

Avg. Plan

Limit

Actual

Avg. Plan

Rate

1990

Emission

Rate

Change

from 1990

to 1997

C-2, 3

IL Joppa Steam Electric Energy Inc 887 5 Standard Limitation 0.45 0.24 0.56 -57%

IL Joppa Steam Electric Energy Inc 887 6 Standard Limitation 0.45 0.24 0.56 -57%

IL Meredosia Cipsco 864 1 Averaging Plan 0.45 0.50 0.46 0.43 0.50 0%

IL Meredosia Cipsco 864 2 Averaging Plan 0.45 0.50 0.46 0.43 0.50 0%

IL Meredosia Cipsco 864 3 Averaging Plan 0.45 0.50 0.46 0.43 0.50 0%

IL Meredosia Cipsco 864 4 Averaging Plan 0.45 0.50 0.46 0.43 0.50 0%

IL Meredosia Cipsco 864 5 Averaging Plan 0.45 0.69 0.46 0.43 0.67 3%

IL Newton Cipsco 6017 1 Averaging Plan 0.45 0.29 0.46 0.43 0.47 -38%

IL Newton Cipsco 6017 2 Averaging Plan 0.45 0.38 0.46 0.43 0.39 -3%

IL Vermilion Illinois Power Co 897 1 Averaging Plan 0.45 0.42 0.45 0.38 0.94 -55%

IL Vermilion Illinois Power Co 897 2 Averaging Plan 0.45 0.42 0.74 -43%

IN Cayuga PSI Energy, Inc. 1001 1 Averaging Plan 0.45 0.32 0.48 0.43 0.42 -24%

IN Cayuga PSI Energy, Inc. 1001 2 Averaging Plan 0.45 0.34 0.48 0.43 0.47 -28%

IN Elmer W Stout Indianapolis Power & Light 990 50 Averaging Plan 0.45 0.35 0.45 0.34 0.63 -44%

IN Elmer W Stout Indianapolis Power & Light 990 60 Averaging Plan 0.45 0.38 0.45 0.34 0.65 -42%

IN Elmer W Stout Indianapolis Power & Light 990 70 Averaging Plan 0.45 0.32 0.45 0.34 0.71 -55%

IN F B Culley Southern Indiana Gas & Elec 1012 2 Standard Limitation 0.50 0.47 1.05 -55%

IN F B Culley Southern Indiana Gas & Elec 1012 3 Standard Limitation 0.50 0.47 1.23 -62%

IN Frank E Ratts Hoosier Energy 1043 1SG1 Averaging Plan 0.50 0.49 0.50 0.49 1.08 -55%

IN Frank E Ratts Hoosier Energy 1043 2SG1 Averaging Plan 0.50 0.48 0.50 0.49 1.09 -56%

IN Gibson PSI Energy, Inc. 6113 1 Averaging Plan 0.50 0.52 0.48 0.43 1.03 -50%

IN Gibson PSI Energy, Inc. 6113 2 Averaging Plan 0.50 0.52 0.48 0.43 1.12 -54%

IN Gibson PSI Energy, Inc. 6113 3 Averaging Plan 0.50 0.43 0.48 0.43 0.52 -17%

IN Gibson PSI Energy, Inc. 6113 4 Averaging Plan 0.50 0.42 0.48 0.43 0.66 -36%

IN H T Pritchard Indianapolis Power & Light 991 3 Averaging Plan 0.45 0.69 0.45 0.34 0.74 -7%

IN H T Pritchard Indianapolis Power & Light 991 4 Averaging Plan 0.45 0.69 0.45 0.34 0.74 -7%

IN H T Pritchard Indianapolis Power & Light 991 5 Averaging Plan 0.45 0.36 0.45 0.34 0.67 -46%

IN H T Pritchard Indianapolis Power & Light 991 6 Averaging Plan 0.45 0.36 0.45 0.34 0.47 -23%

IN Petersburg Indianapolis Power & Light 994 1 Averaging Plan 0.45 0.26 0.45 0.34 0.56 -54%

IN Petersburg Indianapolis Power & Light 994 2 Averaging Plan 0.45 0.33 0.45 0.34 0.63 -48%

IN Petersburg Indianapolis Power & Light 994 3 Averaging Plan 0.45 0.33 0.45 0.34 0.37 -11%

IN Petersburg Indianapolis Power & Light 994 4 Averaging Plan 0.45 0.36 0.45 0.34 0.37 -3%
Appendix C-2: Compliance Results for the 265 Phase I NOx

 Affected Units in 1997

1997

ST Plant Name Operating Utility

ORIS

Code Boiler Compliance Approach

Emission

Limit

Actual

Emission

Rate

AEL or 

Avg. Plan

Limit

Actual

Avg. Plan

Rate

1990

Emission

Rate

Change

from 1990

to 1997

C-2, 4

IN R Gallagher PSI Energy, Inc. 1008 1 Averaging Plan 0.50 0.43 0.48 0.43 0.74 -42%

IN R Gallagher PSI Energy, Inc. 1008 2 Averaging Plan 0.50 0.43 0.48 0.43 0.95 -55%

IN R Gallagher PSI Energy, Inc. 1008 3 Averaging Plan 0.50 0.40 0.48 0.43 0.95 -58%

IN R Gallagher PSI Energy, Inc. 1008 4 Averaging Plan 0.50 0.40 0.48 0.43 0.95 -58%

IN Wabash River PSI Energy, Inc. 1010 1 Standard Limitation 0.50 0.15 0.52 -71%

IN Wabash River PSI Energy, Inc. 1010 2 Averaging Plan 0.50 0.58 0.48 0.43 0.95 -39%

IN Wabash River PSI Energy, Inc. 1010 3 Averaging Plan 0.50 0.59 0.48 0.43 0.92 -36%

IN Wabash River PSI Energy, Inc. 1010 5 Averaging Plan 0.50 0.48 0.48 0.43 0.85 -44%

IN Wabash River PSI Energy, Inc. 1010 6 Averaging Plan 0.45 0.40 0.48 0.43 0.37 8%

KS La Cygne Kansas City Power & Light 1241 2 Standard Limitation 0.50 0.34 0.29 17%

KS Quindaro Board of Public Util,ks City 1295 2 Standard Limitation 0.50 0.34 0.64 -47%

KY Coleman Big Rivers Electric 1381 C1 Standard Limitation 0.50 0.46 1.41 -67%

KY Coleman Big Rivers Electric 1381 C2 Standard Limitation 0.50 0.46 1.29 -64%

KY Coleman Big Rivers Electric 1381 C3 Standard Limitation 0.50 0.48 1.14 -58%

KY Cooper East Kentucky Power Coop 1384 1 Averaging Plan 0.50 0.40 0.50 0.40 0.90 -56%

KY Cooper East Kentucky Power Coop 1384 2 Averaging Plan 0.50 0.40 0.50 0.40 0.90 -56%

KY E W Brown Kentucky Utilities Co 1355 1 Averaging Plan 0.50 0.48 0.46 0.42 1.00 -52%

KY E W Brown Kentucky Utilities Co 1355 2 Averaging Plan 0.45 0.42 0.46 0.42 0.59 -29%

KY E W Brown Kentucky Utilities Co 1355 3 Averaging Plan 0.45 0.42 0.46 0.42 0.57 -26%

KY East Bend Cincinnati Gas & Electric Co 6018 2 Averaging Plan 0.50 0.40 0.48 0.43 0.31 29%

KY Elmer Smith Owensboro City of 1374 2 Standard Limitation 0.45 0.43 0.86 -50%

KY Ghent Kentucky Utilities Co 1356 1 Averaging Plan 0.45 0.41 0.46 0.42 0.56 -27%

KY Green River Kentucky Utilities Co 1357 5 Averaging Plan 0.50 0.40 0.46 0.42 0.84 -52%

KY H L Spurlock East Kentucky Power Coop 6041 1 Standard Limitation 0.50 0.44 0.90 -51%

KY HMP&L Station 2 Big Rivers Electric 1382 H1 Standard Limitation 0.50 0.48 1.34 -64%

KY HMP&L Station 2 Big Rivers Electric 1382 H2 Standard Limitation 0.50 0.46 1.34 -66%

KY R D Green Big Rivers Electric 6639 G1 Standard Limitation 0.50 0.38 0.41 -7%

KY R D Green Big Rivers Electric 6639 G2 Standard Limitation 0.50 0.46 0.45 2%

MD Chalk Point Pepco 1571 1 AEL Demonstration 0.50 0.65 0.86 1.35 -52%

MD Chalk Point Pepco 1571 2 AEL Demonstration 0.50 0.65 1.20 1.35 -52%

MD Morgantown Pepco 1573 1 AEL Demonstration 0.45 0.63 0.70 0.95 -34%

MD Morgantown Pepco 1573 2 AEL Demonstration 0.45 0.64 0.70 0.95 -33%
Appendix C-2: Compliance Results for the 265 Phase I NOx

 Affected Units in 1997

1997

ST Plant Name Operating Utility

ORIS

Code Boiler Compliance Approach

Emission

Limit

Actual

Emission

Rate

AEL or 

Avg. Plan

Limit

Actual

Avg. Plan

Rate

1990

Emission

Rate

Change

from 1990

to 1997

C-2, 5

MD R P Smith Potomac Edison Co 1570 9 Averaging Plan 0.50 0.67 0.49 0.45 0.87 -23%

MD R P Smith Potomac Edison Co 1570 11 Averaging Plan 0.45 0.43 0.49 0.45 0.78 -45%

MI J H Campbell Consumers Energy Co 1710 1 AEL Demonstration 0.45 0.48 0.55 0.69 -30%

MN High Bridge Northern States Power Co 1912 3 Averaging Plan 0.50 0.63 0.46 0.33 0.48 31%

MN High Bridge Northern States Power Co 1912 4 Averaging Plan 0.50 0.63 0.46 0.33 0.48 31%

MN High Bridge Northern States Power Co 1912 5 Averaging Plan 0.50 0.63 0.46 0.33 0.48 31%

MN High Bridge Northern States Power Co 1912 6 Averaging Plan 0.50 0.63 0.46 0.33 0.48 31%

MN Sherburne County Northern States Power Co 6090 1 Averaging Plan 0.45 0.27 0.46 0.33 0.45 -40%

MN Sherburne County Northern States Power Co 6090 2 Averaging Plan 0.45 0.27 0.46 0.33 0.45 -40%

MO Hawthorn Kansas City Power & Light 2079 5 Standard Limitation 0.45 0.37 0.36 3%

MO Iatan Kansas City Power & Light 6065 1 Standard Limitation 0.50 0.29 0.31 -6%

MO James River Springfield City of (MO) 2161 3 Averaging Plan 0.50 0.55 0.50 0.45 1.02 -46%

MO James River Springfield City of (MO) 2161 4 Averaging Plan 0.50 0.62 0.50 0.45 0.87 -29%

MO James River Springfield City of (MO) 2161 5 Averaging Plan 0.50 0.58 0.50 0.45 0.93 -38%

MO Labadie Union Electric Co 2103 1 Averaging Plan 0.45 0.22 0.45 0.24 0.62 -65%

MO Labadie Union Electric Co 2103 2 Averaging Plan 0.45 0.25 0.45 0.24 0.62 -60%

MO Labadie Union Electric Co 2103 3 Averaging Plan 0.45 0.22 0.45 0.24 0.62 -65%

MO Labadie Union Electric Co 2103 4 Averaging Plan 0.45 0.21 0.45 0.24 0.62 -66%

MO Meramec Union Electric Co 2104 1 Averaging Plan 0.45 0.67 0.45 0.24 0.82 -18%

MO Meramec Union Electric Co 2104 2 Averaging Plan 0.45 0.53 0.45 0.24 0.63 -16%

MO Meramec Union Electric Co 2104 3 Averaging Plan 0.50 0.61 0.45 0.24 0.96 -36%

MO Meramec Union Electric Co 2104 4 Averaging Plan 0.50 0.33 0.45 0.24 1.17 -72%

MO Montrose Kansas City Power & Light 2080 1 Standard Limitation 0.45 0.32 0.32 0%

MO Montrose Kansas City Power & Light 2080 2 Standard Limitation 0.45 0.38 0.34 12%

MO Montrose Kansas City Power & Light 2080 3 Standard Limitation 0.45 0.38 0.34 12%

MO Rush Island Union Electric Co 6155 1 Averaging Plan 0.45 0.20 0.45 0.24 0.63 -68%

MO Rush Island Union Electric Co 6155 2 Averaging Plan 0.45 0.18 0.45 0.24 0.63 -71%

MO Southwest Springfield City of (MO) 6195 1 Averaging Plan 0.50 0.33 0.50 0.45 0.47 -30%

MO Thomas Hill Associated Electric Coop Inc 2168 MB3 Standard Limitation 0.50 0.28 0.31 -10%

MS Jack Watson Mississippi Power Co 2049 4 Averaging Plan 0.50 0.49 0.48 0.42 1.10 -55%

MS Jack Watson Mississippi Power Co 2049 5 Averaging Plan 0.50 0.64 0.48 0.42 1.22 -48%

MS R D Morrow South Mississippi El Pwr 6061 1 Averaging Plan 0.50 0.43 0.50 0.45 0.42 2%
Appendix C-2: Compliance Results for the 265 Phase I NOx

 Affected Units in 1997

1997

ST Plant Name Operating Utility

ORIS

Code Boiler Compliance Approach

Emission

Limit

Actual

Emission

Rate

AEL or 

Avg. Plan

Limit

Actual

Avg. Plan

Rate

1990

Emission

Rate

Change

from 1990

to 1997

C-2, 6

MS R D Morrow South Mississippi El Pwr 6061 2 Averaging Plan 0.50 0.48 0.50 0.45 0.43 12%

MS Victor J Daniel Jr Mississippi Power Co 6073 1 Averaging Plan 0.45 0.28 0.48 0.42 0.27 4%

MS Victor J Daniel Jr Mississippi Power Co 6073 2 Averaging Plan 0.45 0.26 0.48 0.42 0.28 -7%

NY Dunkirk Niagara Mohawk Power Corp 2554 3 Standard Limitation 0.45 0.32 0.48 -33%

NY Dunkirk Niagara Mohawk Power Corp 2554 4 Standard Limitation 0.45 0.32 0.48 -33%

NY Greenidge Nyseg 2527 6 Averaging Plan 0.45 0.50 0.45 0.40 0.55 -9%

NY Milliken Nyseg 2535 1 Averaging Plan 0.45 0.36 0.45 0.40 0.66 -45%

NY Milliken Nyseg 2535 2 Averaging Plan 0.45 0.36 0.45 0.40 0.59 -39%

OH Ashtabula Cleveland Electric Illum 2835 7 Standard Limitation 0.45 0.41 0.61 -33%

OH Conesville Columbus Southern Power 2840 3 Standard Limitation 0.50 0.45 0.93 -52%

OH Conesville Columbus Southern Power 2840 4 Standard Limitation 0.45 0.42 0.55 -24%

OH Eastlake Cleveland Electric Illum 2837 1 Standard Limitation 0.45 0.42 0.49 -14%

OH Eastlake Cleveland Electric Illum 2837 2 Standard Limitation 0.45 0.38 0.68 -44%

OH Eastlake Cleveland Electric Illum 2837 3 Standard Limitation 0.45 0.41 0.54 -24%

OH Eastlake Cleveland Electric Illum 2837 4 Standard Limitation 0.45 0.35 0.51 -31%

OH Edgewater Ohio Edison Co 2857 13 Averaging Plan 0.50 0.17 0.50 0.43 0.87 -80%

OH Gorge Ohio Edison Co 2858 25 Averaging Plan 0.50 Not Oper. 0.50 0.43 0.00

OH Gorge Ohio Edison Co 2858 26 Averaging Plan 0.50 Not Oper. 0.50 0.43 0.00

OH Miami Fort Cincinnati Gas & Electric Co 2832 6 Averaging Plan 0.45 0.59 0.48 0.43 0.73 -19%

OH Picway Columbus Southern Power 2843 9 Standard Limitation 0.50 0.40 0.87 -54%

OH R E Burger Ohio Edison Co 2864 7 Averaging Plan 0.50 0.79 0.50 0.43 0.66 20%

OH R E Burger Ohio Edison Co 2864 8 Averaging Plan 0.50 0.77 0.50 0.43 0.72 7%

OH Toronto Ohio Edison Co 2867 10 Averaging Plan 0.50 Not Oper. 0.50 0.43 0.00

OH Toronto Ohio Edison Co 2867 11 Averaging Plan 0.50 Not Oper. 0.50 0.43 0.00

OH W H Sammis Ohio Edison Co 2866 5 Averaging Plan 0.50 0.45 0.50 0.43 0.52 -13%

OH W H Sammis Ohio Edison Co 2866 6 Averaging Plan 0.50 0.38 0.50 0.43 1.10 -65%

OH Walter C Beckjord Cincinnati Gas & Electric Co 2830 5 Averaging Plan 0.45 0.45 0.48 0.43 0.72 -38%

OH Walter C Beckjord Cincinnati Gas & Electric Co 2830 6 Averaging Plan 0.45 0.42 0.48 0.43 0.71 -41%

PA Armstrong West Penn Power Co 3178 1 Averaging Plan 0.50 0.36 0.49 0.45 0.90 -60%

PA Armstrong West Penn Power Co 3178 2 Averaging Plan 0.50 0.36 0.49 0.45 1.04 -65%

PA Bruce Mansfield Ohio Edison Co 6094 1 Averaging Plan 0.50 0.35 0.50 0.43 0.98 -64%

PA Bruce Mansfield Ohio Edison co 6094 2 Averaging Plan 0.50 0.37 0.50 0.43 1.13 -67%
Appendix C-2: Compliance Results for the 265 Phase I NOx

 Affected Units in 1997

1997

ST Plant Name Operating Utility

ORIS

Code Boiler Compliance Approach

Emission

Limit

Actual

Emission

Rate

AEL or 

Avg. Plan

Limit

Actual

Avg. Plan

Rate

1990

Emission

Rate

Change

from 1990

to 1997

C-2, 7

PA Brunner Island PP&L 3140 1 Averaging Plan 0.45 0.37 0.47 0.41 0.65 -43%

PA Brunner Island PP&L 3140 2 Averaging Plan 0.45 0.37 0.47 0.41 0.71 -48%

PA Brunner Island PP&L 3140 3 Averaging Plan 0.45 0.42 0.47 0.41 0.83 -49%

PA Cheswick Duquesne Light co 8226 1 Standard Limitation 0.45 0.41 0.71 -42%

PA Conemaugh GPU 3118 1 Standard Limitation 0.45 0.39 0.65 -40%

PA Conemaugh GPU 3118 2 Standard Limitation 0.45 0.38 0.71 -46%

PA Martins Creek PP&L 3148 1 Averaging Plan 0.50 0.45 0.47 0.41 1.03 -56%

PA Martins Creek PP&L 3148 2 Averaging Plan 0.50 0.45 0.47 0.41 0.93 -52%

PA Mitchell West Penn Power Co 3181 33 Averaging Plan 0.45 0.39 0.49 0.45 0.68 -43%

PA New Castle Ohio Edison Co 3138 1 Averaging Plan 0.50 Not Oper. 0.50 0.43 0.00

PA New Castle Ohio Edison Co 3138 2 Averaging Plan 0.50 Not Oper. 0.50 0.43 0.00

PA Portland GPU 3113 1 Averaging Plan 0.45 0.30 0.45 0.37 0.46 -35%

PA Portland GPU 3113 2 Averaging Plan 0.45 0.41 0.45 0.37 0.66 -38%

PA Shawville GPU 3131 1 Standard Limitation 0.50 0.49 0.99 -51%

PA Shawville GPU 3131 2 Standard Limitation 0.50 0.49 1.02 -52%

PA Shawville GPU 3131 3 Standard Limitation 0.45 0.43 0.83 -48%

PA Shawville GPU 3131 4 Standard Limitation 0.45 0.43 0.82 -48%

PA Sunbury PP&L 3152 3 Averaging Plan 0.50 0.42 0.47 0.41 0.93 -55%

PA Sunbury PP&L 3152 4 Averaging Plan 0.50 0.42 0.47 0.41 1.29 -67%

TN Gallatin TVA 3403 1 Averaging Plan 0.45 0.39 0.47 0.44 0.59 -34%

TN Gallatin TVA 3403 2 Averaging Plan 0.45 0.39 0.47 0.44 0.63 -38%

TN Gallatin TVA 3403 3 Averaging Plan 0.45 0.39 0.47 0.44 0.59 -34%

TN Gallatin TVA 3403 4 Averaging Plan 0.45 0.39 0.47 0.44 0.55 -29%

TN Johnsonville TVA 3406 1 Averaging Plan 0.45 0.47 0.47 0.44 0.45 4%

TN Johnsonville TVA 3406 2 Averaging Plan 0.45 0.47 0.47 0.44 0.48 -2%

TN Johnsonville TVA 3406 3 Averaging Plan 0.45 0.47 0.47 0.44 0.46 2%

TN Johnsonville TVA 3406 4 Averaging Plan 0.45 0.47 0.47 0.44 0.54 -13%

TN Johnsonville TVA 3406 5 Averaging Plan 0.45 0.47 0.47 0.44 0.45 4%

TN Johnsonville TVA 3406 6 Averaging Plan 0.45 0.47 0.47 0.44 0.50 -6%

TN Johnsonville TVA 3406 7 Averaging Plan 0.50 0.47 0.47 0.44 1.00 -53%

TN Johnsonville TVA 3406 8 Averaging Plan 0.50 0.47 0.47 0.44 0.97 -52%

TN Johnsonville TVA 3406 9 Averaging Plan 0.50 0.47 0.47 0.44 1.10 -57%
Appendix C-2: Compliance Results for the 265 Phase I NOx

 Affected Units in 1997

1997

ST Plant Name Operating Utility

ORIS

Code Boiler Compliance Approach

Emission

Limit

Actual

Emission

Rate

AEL or 

Avg. Plan

Limit

Actual

Avg. Plan

Rate

1990

Emission

Rate

Change

from 1990

to 1997

C-2, 8

TN Johnsonville TVA 3406 10 Averaging Plan 0.50 0.47 0.47 0.44 1.07 -56%

UT Gadsby Pacificorp 3648 3 Standard Limitation 0.45 0.07 0.53 -87%

WI Alma Dairyland Power Coop 4140 B4 Averaging Plan 0.50 0.79 0.48 0.45 0.85 -7%

WI Alma Dairyland Power Coop 4140 B5 Averaging Plan 0.50 0.79 0.48 0.45 0.85 -7%

WI Genoa Dairyland Power Coop 4143 1 Averaging Plan 0.45 0.47 0.48 0.45 0.75 -37%

WI J P Madgett Dairyland Power Coop 4271 B1 Averaging Plan 0.50 0.34 0.48 0.45 0.30 13%

WI Port Washington Wisconsin Electric Power Co 4040 1 Averaging Plan 0.50 0.32 0.48 0.36 0.32 0%

WI Port Washington Wisconsin Electric Power Co 4040 2 Averaging Plan 0.50 0.32 0.48 0.36 0.32 0%

WI Port Washington Wisconsin Electric Power Co 4040 3 Averaging Plan 0.50 0.32 0.48 0.36 0.32 0%

WI Port Washington Wisconsin Electric Power Co 4040 4 Averaging Plan 0.50 0.30 0.48 0.36 0.37 -19%

WI Port Washington Wisconsin Electric Power Co 4040 5 Standard Limitation 0.50 Not Oper. 0.00

WI Pulliam Wisconsin Public Service 4072 7 Averaging Plan 0.50 0.35 0.47 0.36 0.69 -49%

WI Pulliam Wisconsin Public Service 4072 8 Averaging Plan 0.50 0.36 0.47 0.36 0.57 -37%

WI South Oak Creek Wisconsin Electric Power Co 4041 5 Averaging Plan 0.50 0.24 0.48 0.36 0.28 -14%

WI South Oak Creek Wisconsin Electric Power Co 4041 6 Averaging Plan 0.50 0.24 0.48 0.36 0.28 -14%

WI South Oak Creek Wisconsin Electric Power Co 4041 7 Averaging Plan 0.45 0.40 0.48 0.36 0.66 -39%

WI South Oak Creek Wisconsin Electric Power Co 4041 8 Averaging Plan 0.45 0.40 0.48 0.36 0.67 -40%

WI Valley Wisconsin Electric Power Co 4042 1 Averaging Plan 0.50 0.44 0.48 0.36 1.10 -60%

WI Valley Wisconsin Electric Power Co 4042 2 Averaging Plan 0.50 0.44 0.48 0.36 1.10 -60%

WI Valley Wisconsin Electric Power Co 4042 3 Averaging Plan 0.50 0.52 0.48 0.36 1.05 -50%

WI Valley Wisconsin Electric Power Co 4042 4 Averaging Plan 0.50 0.52 0.48 0.36 0.93 -44%

WI Weston Wisconsin Public Service 4078 1 Averaging Plan 0.50 0.80 0.47 0.36 0.90 -11%

WI Weston Wisconsin Public Service 4078 2 Averaging Plan 0.50 0.78 0.47 0.36 1.08 -28%

WI Weston Wisconsin Public Service 4078 3 Averaging Plan 0.45 0.21 0.47 0.36 0.26 -19%

WV Albright Monongahela Power Co 3942 1 Averaging Plan 0.50 0.65 0.49 0.45 1.10 -41%

WV Albright Monongahela Power Co 3942 2 Averaging Plan 0.50 0.71 0.49 0.45 1.10 -35%

WV Albright Monongahela Power Co 3942 3 Averaging Plan 0.45 0.39 0.49 0.45 0.71 -45%

WV Fort Martin Monongahela Power Co 3943 1 Averaging Plan 0.45 0.63 0.49 0.45 0.62 2%

WV Harrison Monongahela Power Co 3944 1 Averaging Plan 0.50 0.47 0.49 0.45 0.99 -53%

WV Harrison Monongahela Power Co 3944 2 Averaging Plan 0.50 0.47 0.49 0.45 1.13 -58%

WV Harrison Monongahela Power Co 3944 3 Averaging Plan 0.50 0.47 0.49 0.45 1.06 -56%

WV Mitchell Ohio Power Co 3948 1 AEL Demonstration 0.50 0.51 0.56 0.77 -34%
Appendix C-2: Compliance Results for the 265 Phase I NOx

 Affected Units in 1997

1997

ST Plant Name Operating Utility

ORIS

Code Boiler Compliance Approach

Emission

Limit

Actual

Emission

Rate

AEL or 

Avg. Plan

Limit

Actual

Avg. Plan

Rate

1990

Emission

Rate

Change

from 1990

to 1997

1 Extension granted through 7/31/97 and Alternative Emission Limit pending.

2 Alternative Emission Limitation pending.

C-2, 9

WV Mitchell Ohio Power Co 3948 2 AEL Demonstration 0.50 0.51 0.56 0.77 -34%

WV Mt Storm Vepco 3954 1 Extension1 0.45 0.79 0.88 -10%

WV Mt Storm Vepco 3954 3 AEL Demonstration2 0.45 0.65 1.27 -49%

WV Pleasants Monongahela Power Co 6004 1 Averaging Plan 0.50 0.38 0.49 0.45 0.52 -27%

WV Pleasants Monongahela Power Co 6004 2 Averaging Plan 0.50 0.35 0.49 0.45 0.35 0%

WY Jim Bridger Pacificorp 8066 BW71 Standard Limitation 0.45 0.39 0.63 -38%

WY Jim Bridger Pacificorp 8066 BW72 Standard Limitation 0.45 0.36 0.51 -29%

WY Jim Bridger Pacificorp 8066 BW73 Standard Limitation 0.45 0.39 0.42 -7%

WY Wyodak Pacificorp 6101 BW91 Standard Limitation 0.50 0.31 0.37 -16%
Appendix C-3: Compliance Results for the 272 Early Election Units in 1997

1 New Source Performance Standards subpart.

C-3, 1

ST Plant Name Operating Utility

ORIS

Code Boiler NSPS1

Emission

Limit

Actual 

Emission Rate

1990

Emission Rate

Change from 

1990 to 1997

AL Charles R Lowman Alabama Electric Coop 56 2 D 0.50 0.48 0.62 -23%

AL Charles R Lowman Alabama Electric Coop 56 3 D 0.50 0.49 0.66 -26%

AR Flint Creek Southwestern Electric Power 6138 1 D 0.50 0.30 0.31 -3%

AR Independence Arkansas Power & Light Co 6641 1 D 0.45 0.28 0.34 -18%

AR Independence Arkansas Power & Light Co 6641 2 D 0.45 0.26 0.35 -26%

AR White Bluff Arkansas Power & Light Co 6009 1 D 0.45 0.36 0.29 24%

AR White Bluff Arkansas Power & Light Co 6009 2 D 0.45 0.35 0.34 3%

AZ Apache Station Arizona Electric Pwr Coop 160 2 D 0.50 0.47 0.58 -19%

AZ Apache Station Arizona Electric Pwr Coop 160 3 D 0.50 0.43 0.58 -26%

AZ Cholla Arizona Public Service 113 1 0.45 0.40 0.46 -13%

AZ Cholla Arizona Public Service 113 2 D 0.45 0.33 0.42 -21%

AZ Cholla Arizona Public Service 113 3 D 0.45 0.35 0.36 -3%

AZ Cholla Arizona Public Service 113 4 D 0.45 0.30 0.38 -21%

AZ Coronado Salt River Proj 6177 U1B D 0.50 0.44 0.51 -14%

AZ Coronado Salt River Proj 6177 U2B D 0.50 0.43 0.51 -16%

AZ Navajo Salt River Proj 4941 1 0.45 0.36 0.41 -12%

AZ Navajo Salt River Proj 4941 2 0.45 0.37 0.41 -10%

AZ Navajo Salt River Proj 4941 3 0.45 0.43 0.37 16%

AZ Springerville Tucson Electric Power Co 8223 1 D 0.45 0.39 0.34 15%

AZ Springerville Tucson Electric Power Co 8223 2 D 0.45 0.40 0.33 21%

CO Cherokee Public Service Co of CO 469 3 0.50 0.45 0.73 -38%

CO Cherokee Public Service Co of CO 469 4 0.45 0.35 0.51 -31%

CO Comanche Public Service Co of CO 470 1 0.45 0.24 0.24 0%

CO Comanche Public Service Co of CO 470 2 D 0.50 0.24 0.31 -23%

CO Craig Tri-state G&T Association 6021 C1 D 0.50 0.34 0.39 -13%

CO Craig Tri-state G&T Association 6021 C2 D 0.50 0.36 0.40 -10%

CO Craig Tri-state G&T Association 6021 C3 Da 0.50 0.34 0.28 -13%

CO Pawnee Public Service Co of CO 6248 1 D 0.50 0.21 0.62 -66%

CO Rawhide Platte River Power 6761 101 Da 0.45 0.32 0.43 -26%

CO Ray D Nixon Colorado Springs Utilities 8219 1 D 0.50 0.38 0.54 -30%

CO Valmont Public Service Co of CO 477 5 0.45 0.28 0.66 -58%

CT Bridgeport Harbor United Illuminating Co 568 BHB3 0.45 0.25 0.56 -55%
Appendix C-3: Compliance Results for the 272 Early Election Units in 1997

1 New Source Performance Standards subpart.

C-3, 2

ST

Plant Name Operating Utility ORIS

Code

Boiler NSPS1

Emission

Limit

Actual

Emission Rate

1990

Emission Rate

Change from

1990 to 1997

FL C D Mcintosh Jr City of Lakeland 676 3 D 0.50 0.44 0.46 -4%

FL Crystal River Florida Power Corporation 628 2 0.45 0.43 0.38 13%

FL Crystal River Florida Power Corporation 628 4 D 0.50 0.49 0.50 -2%

FL Crystal River Florida Power Corporation 628 5 D 0.50 0.49 0.47 4%

FL Deerhaven Gainesville Regional Util 663 B2 D 0.50 0.49 0.53 -8%

FL Seminole Seminole Electric Coop Inc 136 1 Da 0.50 0.42 0.43 -2%

FL Seminole Seminole Electric Coop Inc 136 2 Da 0.50 0.40 0.36 11%

FL St Johns River Power Jacksonville Electric Auth 207 1 Da 0.50 0.48 0.50 -4%

FL St Johns River Power Jacksonville Electric Auth 207 2 Da 0.50 0.48 0.59 -19%

GA Scherer Georgia Power Co 6257 4 D 0.45 0.32 0.21 52%

IA Ames City of Ames 1122 7 0.45 0.36 0.60 -40%

IA Ames City of Ames 1122 8 D 0.50 0.43 0.55 -22%

IA Council Bluffs Midamerican Energy Company 1082 1 0.50 0.41 0.56 -27%

IA Council Bluffs Midamerican Energy Company 1082 2 0.45 0.34 0.33 3%

IA Council Bluffs Midamerican Energy Company 1082 3 D 0.50 0.40 0.37 8%

IA George Neal North Midamerican Energy Company 1091 2 0.50 0.46 1.06 -57%

IA George Neal North Midamerican Energy Company 1091 3 D 0.50 0.47 0.39 21%

IA George Neal South Midamerican Energy Company 7343 4 D 0.50 0.43 0.64 -33%

IA Lansing Interstate Power Co 1047 4 D 0.50 0.40 0.50 -20%

IA Louisa Midamerican Energy Company 6664 101 D 0.50 0.27 0.25 8%

IA Ottumwa IES Utilities, Inc. 6254 1 D 0.45 0.36 0.69 -48%

IL Crawford Commonwealth Edison Co 867 7 0.45 0.32 0.33 -3%

IL Crawford Commonwealth Edison Co 867 8 0.45 0.40 0.48 -17%

IL Dallman City of Springfield, IL 963 33 D 0.45 0.34 0.55 -38%

IL Fisk Commonwealth Edison Co 886 19 0.45 0.35 0.39 -10%

IL Waukegan Commonwealth Edison Co 883 7 0.45 0.34 0.26 31%

IL Waukegan Commonwealth Edison Co 883 8 0.45 0.39 0.41 -5%

IL Will County Commonwealth Edison Co 884 3 0.45 0.40 0.39 3%

IL Will County Commonwealth Edison Co 884 4 0.45 0.35 0.31 13%

IN A B Brown Southern Indiana Gas & Elec 6137 1 D 0.50 0.43 0.61 -30%

IN A B Brown Southern Indiana Gas & Elec 6137 2 Da 0.50 0.46 0.39 18%
Appendix C-3: Compliance Results for the 272 Early Election Units in 1997

1 New Source Performance Standards subpart.

2 Conditionally in compliance pending Phase I permit review.

C-3, 3

IN Dean H Mitchell Northern Indiana Pub Serv 996 4 0.45 0.34 0.43 -21%

ST

Plant Name Operating Utility ORIS

Code

Boiler NSPS1

Emission

Limit

Actual

Emission Rate

1990

Emission Rate

Change from

1990 to 1997

IN Dean H Mitchell Northern Indiana Pub Serv 996 5 0.45 0.34 0.43 -21%

IN Dean H Mitchell Northern Indiana Pub Serv 996 6 0.45 0.33 0.58 -43%

IN Dean H Mitchell Northern Indiana Pub Serv 996 11 0.50 0.33 0.58 -43%

IN Merom Hoosier Energy 6213 1SG1 D 0.50 0.41 0.23 78%

IN Merom Hoosier Energy 6213 2SG1 D 0.50 0.40 0.63 -37%

IN R M Schahfer Northern Indiana Pub Serv 6085 15 D 0.50 0.21 0.42 -50%

IN R M Schahfer Northern Indiana Pub Serv 6085 17 Da 0.45 0.38 0.46 -17%

IN R M Schahfer Northern Indiana Pub Serv 6085 18 Da 0.45 0.36 0.44 -18%

IN Rockport Indiana Michigan Power Co 6166 MB12 D 0.50 0.35 0.32 9%

IN Rockport Indiana Michigan Power Co 6166 MB22 D 0.50 0.35 0.32 9%

IN State Line Commonwealth Edison Co 981 3 0.45 0.24 0.32 -25%

IN Whitewater Valley City of Richmond, IN 1040 1 0.50 0.41 0.71 -42%

IN Whitewater Valley City of Richmond, IN 1040 2 0.45 0.41 0.71 -42%

KS Nearman Creek Board of Public Util, KS City 6064 N1 D 0.50 0.43 0.46 -7%

KS Riverton Empire District Electric 1239 39 0.50 0.38 0.83 -54%

KS Riverton Empire District Electric 1239 40 0.45 0.40 0.55 -27%

KY Cane Run Louisville Gas & Electric 1363 4 0.50 0.43 0.84 -49%

KY Cane Run Louisville Gas & Electric 1363 5 0.50 0.47 1.15 -59%

KY Cane Run Louisville Gas & Electric 1363 6 0.45 0.39 1.02 -62%

KY D B Wilson Big Rivers Electric 6823 W1 Da 0.50 0.48 0.56 -14%

KY Mill Creek Louisville Gas & Electric 1364 1 0.45 0.42 0.76 -45%

KY Mill Creek Louisville Gas & Electric 1364 2 0.45 0.44 0.79 -44%

KY Mill Creek Louisville Gas & Electric 1364 3 D 0.50 0.42 0.62 -32%

KY Mill Creek Louisville Gas & Electric 1364 4 D 0.50 0.47 0.57 -18%

KY Trimble County Louisville Gas & Electric 6071 1 D 0.45 0.41 0.62 -34%

LA Big Cajun 2 Cajun Electric Power 6055 2B1 D 0.50 0.31 0.28 11%

LA Big Cajun 2 Cajun Electric Power 6055 2B2 D 0.50 0.30 0.25 20%

LA Big Cajun 2 Cajun Electric Power 6055 2B3 D 0.50 0.27 0.24 13%
Appendix C-3: Compliance Results for the 272 Early Election Units in 1997

1 New Source Performance Standards subpart.

C-3, 4

LA Dolet Hills Central Louisiana Elec Co 51 1 D 0.50 0.45 0.62 -27%

LA R S Nelson Gulf States Utilities 1393 6 D 0.45 0.42 0.20 110%

ST Plant Name Operating Utility

ORIS

Code Boiler NSPS1

Emission

Limit

Actual

Emission Rate

1990

Emission Rate

Change from

1990 to 1997

LA Rodemacher Central Louisiana Elec Co 6190 2 D 0.50 0.37 0.38 -3%

MI B C Cobb Consumers Energy Co 1695 4 0.45 0.40 0.38 5%

MI B C Cobb Consumers Energy Co 1695 5 0.45 0.37 0.36 3%

MI J B Sims City of Grand Haven 1825 3 Da 0.50 0.48 0.51 -6%

MI J C Weadock Consumers Energy Co 1720 7 0.45 0.41 0.44 -7%

MI J C Weadock Consumers Energy Co 1720 8 0.45 0.41 0.44 -7%

MI J R Whiting Consumers Energy Co 1723 1 0.50 0.38 0.82 -54%

MI J R Whiting Consumers Energy Co 1723 3 0.50 0.39 1.04 -63%

MI Presque Isle Upper Peninsula Power Co 1769 7 D 0.50 0.44 0.49 -10%

MI Presque Isle Upper Peninsula Power Co 1769 8 D 0.50 0.42 0.53 -21%

MI Presque Isle Upper Peninsula Power Co 1769 9 D 0.50 0.44 0.66 -33%

MN Clay Boswell Minnesota Power & Light Co 1893 3 0.45 0.32 0.42 -24%

MN Hoot Lake Otter Tail Power Co 1943 2 0.45 0.38 0.58 -34%

MO Sikeston Sikeston Board of Mun Util 6768 1 D 0.50 0.37 0.51 -27%

MT Colstrip Montana Power Company 6076 1 D 0.45 0.39 0.42 -7%

MT Colstrip Montana Power Company 6076 2 D 0.45 0.41 0.43 -5%

MT Colstrip Montana Power Company 6076 3 Da 0.45 0.40 0.34 18%

MT Colstrip Montana Power Company 6076 4 Da 0.45 0.40 0.35 14%

MT Lewis & Clark Montana-Dakota Utilities Co 6089 B1 0.45 0.37 0.57 -35%

NC Buck Duke Energy Corporation 2720 5 0.45 0.45 0.59 -24%

NC Buck Duke Energy Corporation 2720 6 0.45 0.45 0.54 -17%

NC Buck Duke Energy Corporation 2720 7 0.45 0.44 0.57 -23%

NC Buck Duke Energy Corporation 2720 8 0.45 0.44 0.45 -2%

NC Buck Duke Energy Corporation 2720 9 0.45 0.45 0.51 -12%

NC Cliffside Duke Energy Corporation 2721 1 0.45 0.44 Not Oper.

NC Cliffside Duke Energy Corporation 2721 2 0.45 0.44 Not Oper.

NC Cliffside Duke Energy Corporation 2721 3 0.45 0.38 Not Oper.

NC Cliffside Duke Energy Corporation 2721 4 0.45 0.44 Not Oper.

NC Cliffside Duke Energy Corporation 2721 5 0.45 0.44 0.51 -14%

NC Dan River Duke Energy Corporation 2723 1 0.45 0.44 0.52 -15%
Appendix C-3: Compliance Results for the 272 Early Election Units in 1997

1 New Source Performance Standards subpart.

C-3, 5

NC Dan River Duke Energy Corporation 2723 2 0.45 0.44 0.55 -20%

NC Dan River Duke Energy Corporation 2723 3 0.45 0.44 0.56 -21%

ST

Plant Name Operating Utility ORIS

Code

Boiler NSPS1

Emission

Limit

Actual

Emission Rate

1990

Emission Rate

Change from

1990 to 1997

NC G G Allen Duke Energy Corporation 2718 1 0.45 0.43 0.65 -34%

NC G G Allen Duke Energy Corporation 2718 2 0.45 0.44 0.61 -28%

NC G G Allen Duke Energy Corporation 2718 3 0.45 0.44 0.64 -31%

NC G G Allen Duke Energy Corporation 2718 4 0.45 0.43 0.68 -37%

NC G G Allen Duke Energy Corporation 2718 5 0.45 0.43 0.68 -37%

NC Marshall Duke Energy Corporation 2727 1 0.45 0.43 0.48 -10%

NC Marshall Duke Energy Corporation 2727 2 0.45 0.44 0.61 -28%

NC Marshall Duke Energy Corporation 2727 3 0.45 0.44 0.52 -15%

NC Marshall Duke Energy Corporation 2727 4 0.45 0.44 0.70 -37%

NC RiverbEnd Duke Energy Corporation 2732 7 0.45 0.42 0.58 -28%

NC RiverbEnd Duke Energy Corporation 2732 8 0.45 0.40 0.64 -38%

NC RiverbEnd Duke Energy Corporation 2732 9 0.45 0.43 Not Oper.

NC RiverbEnd Duke Energy Corporation 2732 10 0.45 0.43 Not Oper.

ND Antelope Valley Basin Electric Power 6469 B1 D 0.45 0.29 0.43 -33%

ND Antelope Valley Basin Electric Power 6469 B2 D 0.45 0.28 0.27 4%

ND Leland Olds Basin Electric Power 2817 1 0.50 0.27 0.74 -64%

ND Stanton United Power Assn 2824 10 Da 0.45 0.40 0.47 -15%

NE Gerald Gentleman Sta Nebraska Public Power Dist 6077 1 D 0.50 0.48 0.40 20%

NE Gerald Gentleman Sta Nebraska Public Power Dist 6077 2 D 0.50 0.34 0.35 -3%

NE Gerald Whelan Energy City of Hastings 60 1 D 0.45 0.26 0.30 -13%

NE Nebraska City Omaha Public Power Dist 6096 1 D 0.50 0.43 0.48 -10%

NE North Omaha Omaha Public Power Dist 2291 4 0.45 0.31 0.38 -18%

NE Platte City of Grand Island 59 1 D 0.45 0.37 0.48 -23%

NM Escalante Plains Electric Gen & Trans 87 1 Da 0.45 0.39 0.35 11%

NV Mohave Southern California Edison 2341 1 0.45 0.42 0.38 11%

NV Mohave Southern California Edison 2341 2 0.45 0.39 0.46 -15%

NV North Valmy Sierra Pacific Power Co 8224 1 D 0.50 0.30 0.51 -41%

NV North Valmy Sierra Pacific Power Co 8224 2 Da 0.50 0.29 0.40 -28%

NV Reid Gardner Nevada Power Company 2324 4 Da 0.50 0.27 0.38 -29%
Appendix C-3: Compliance Results for the 272 Early Election Units in 1997

1 New Source Performance Standards subpart.

C-3, 6

NY C R Huntley Niagara Mohawk Power Corp 2549 67 0.45 0.31 0.64 -52%

NY C R Huntley Niagara Mohawk Power Corp 2549 68 0.45 0.31 0.64 -52%

NY Dunkirk Niagara Mohawk Power Corp 2554 1 0.45 0.34 0.48 -29%

ST

Plant Name Operating Utility ORIS

Code

Boiler NSPS1

Emission

Limit

Actual

Emission Rate

1990

Emission Rate

Change from

1990 to 1997

NY Dunkirk Niagara Mohawk Power Corp 2554 2 0.45 0.34 0.48 -29%

NY Kintigh Nyseg 6082 1 Da 0.50 0.45 0.62 -27%

NY S A Carlson City of Jamestown 2682 9 0.50 0.45 0.90 -50%

NY S A Carlson City of Jamestown 2682 10 0.50 0.47 0.90 -48%

NY S A Carlson City of Jamestown 2682 11 0.50 0.47 1.05 -55%

NY S A Carlson City of Jamestown 2682 12 0.50 0.45 0.83 -46%

OH Conesville Columbus Southern Power 2840 5 D 0.45 0.42 0.44 -5%

OH Conesville Columbus Southern Power 2840 6 D 0.45 0.42 0.44 -5%

OH W H Zimmer Cincinnati Gas & Electric Co 6019 1 Da 0.50 0.45 Not Oper.

OK Muskogee Oklahoma Gas & Electric Co 2952 4 D 0.45 0.35 0.44 -20%

OK Muskogee Oklahoma Gas & Electric Co 2952 5 D 0.45 0.39 0.41 -5%

OK Muskogee Oklahoma Gas & Electric Co 2952 6 D 0.45 0.37 0.44 -16%

OK Northeastern Public Service Co of OK 2963 3313 D 0.45 0.40 0.53 -25%

OK Northeastern Public Service Co of OK 2963 3314 D 0.45 0.40 0.53 -25%

OK Sooner Oklahoma Gas & Electric Co 6095 1 D 0.45 0.38 0.33 15%

OK Sooner Oklahoma Gas & Electric Co 6095 2 D 0.45 0.40 0.42 -5%

OR Boardman Portland General Electric 6106 1SG D 0.50 0.35 0.40 -13%

PA Bruce Mansfield Ohio Edison Co 6094 3 D 0.50 0.38 0.57 -33%

PA Cromby Peco Energy Company 3159 1 0.50 0.45 0.60 -25%

PA Eddystone Peco Energy Company 3161 1 0.45 0.30 0.42 -29%

PA Eddystone Peco Energy Company 3161 2 0.45 0.30 0.50 -40%

PA Homer City GPU 3122 1 0.50 0.47 1.09 -57%

PA Homer City GPU 3122 2 0.50 0.43 1.04 -59%

PA Homer City GPU 3122 3 D 0.50 0.41 0.62 -34%

PA Keystone GPU 3136 1 0.45 0.39 0.79 -51%

PA Keystone GPU 3136 2 0.45 0.39 0.79 -51%

PA Montour PP&L 3149 1 0.45 0.43 0.95 -55%

PA Montour PP&L 3149 2 0.45 0.42 0.46 -9%
Appendix C-3: Compliance Results for the 272 Early Election Units in 1997

1 New Source Performance Standards subpart.

C-3, 7

PA New Castle Ohio Edison Co 3138 3 0.50 0.46 0.63 -27%

PA New Castle Ohio Edison Co 3138 4 0.50 0.42 0.57 -26%

PA New Castle Ohio Edison Co 3138 5 0.50 0.48 0.73 -34%

PA Titus GPU 3115 1 0.45 0.37 0.73 -49%

ST

Plant Name Operating Utility ORIS

Code

Boiler NSPS1

Emission

Limit

Actual

Emission Rate

1990

Emission Rate

Change from

1990 to 1997

PA Titus GPU 3115 2 0.45 0.39 0.68 -43%

PA Titus GPU 3115 3 0.45 0.39 0.77 -49%

SC Cross South Carolina Pub Serv 130 1 Da 0.50 0.32 Not Oper.

SC Cross South Carolina Pub Serv 130 2 Da 0.45 0.38 0.46 -17%

SC W S Lee Duke Energy Corporation 3264 1 0.45 0.44 0.64 -31%

SC W S Lee Duke Energy Corporation 3264 2 0.45 0.44 0.61 -28%

SC W S Lee Duke Energy Corporation 3264 3 0.45 0.44 0.50 -12%

TN John Sevier TVA 3405 1 0.45 0.41 0.62 -34%

TN John Sevier TVA 3405 2 0.45 0.41 0.62 -34%

TN John Sevier TVA 3405 3 0.45 0.43 0.64 -33%

TN John Sevier TVA 3405 4 0.45 0.43 0.64 -33%

TX Big Brown Texas Utilities Electric Co 3497 1 0.45 0.40 0.40 0%

TX Big Brown Texas Utilities Electric Co 3497 2 0.45 0.36 0.34 6%

TX Coleto Creek Central Power & Light Co 6178 1 D 0.45 0.36 0.38 -5%

TX Gibbons Creek Texas Municipal Power Agency 6136 1 D 0.45 0.37 0.47 -21%

TX Harrington Station Southwestern Public Service 6193 061B D 0.45 0.24 0.27 -11%

TX Harrington Station Southwestern Public Service 6193 062B D 0.45 0.29 0.36 -19%

TX Harrington Station Southwestern Public Service 6193 063B D 0.45 0.27 0.36 -25%

TX J K Spruce City of San Antonio 7097 **1 Da 0.45 0.35 Not Oper.

TX J T Deely City of San Antonio 6181 1 D 0.45 0.36 0.31 16%

TX J T Deely City of San Antonio 6181 2 D 0.45 0.36 0.31 16%

TX Limestone Houston Lighting & Power 298 LIM1 Da 0.45 0.41 0.50 -18%

TX Limestone Houston Lighting & Power 298 LIM2 Da 0.45 0.42 0.48 -13%

TX Martin Lake Texas Utilities Electric Co 6146 1 D 0.45 0.32 0.36 -11%

TX Martin Lake Texas Utilities Electric Co 6146 2 D 0.45 0.30 0.35 -14%

TX Martin Lake Texas Utilities Electric Co 6146 3 D 0.45 0.37 0.42 -12%

TX Monticello Texas Utilities Electric Co 6147 1 0.45 0.31 0.31 0%
Appendix C-3: Compliance Results for the 272 Early Election Units in 1997

1 New Source Performance Standards subpart.

C-3, 8

TX Monticello Texas Utilities Electric Co 6147 2 0.45 0.31 0.40 -23%

TX Monticello Texas Utilities Electric Co 6147 3 D 0.50 0.24 0.21 14%

TX Oklaunion West Texas Utilities Co 127 1 Da 0.50 0.48 0.54 -11%

TX Pirkey Southwestern Electric Power 7902 1 D 0.50 0.36 0.34 6%

TX Sam Seymour Lower Colorado River Auth 6179 1 D 0.45 0.34 0.34 0%

ST

Plant Name Operating Utility ORIS

Code

Boiler NSPS1

Emission

Limit

Actual

Emission Rate

1990

Emission Rate

Change from

1990 to 1997

TX Sam Seymour Lower Colorado River Auth 6179 2 D 0.45 0.38 0.29 31%

TX Sam Seymour Lower Colorado River Auth 6179 3 Da 0.45 0.27 0.25 8%

TX San Miguel San Miguel Electric Coop 6183 SM-1 D 0.50 0.42 0.41 2%

TX Sandow Texas Utilities Electric Co 6648 4 D 0.45 0.34 0.43 -21%

TX Tolk Station Southwestern Public Service 6194 171B D 0.45 0.32 0.38 -16%

TX Tolk Station Southwestern Public Service 6194 172B D 0.45 0.30 0.24 25%

TX W A Parish Houston Lighting & Power 3470 WAP5 D 0.50 0.36 0.47 -23%

TX W A Parish Houston Lighting & Power 3470 WAP6 D 0.50 0.40 0.53 -25%

TX W A Parish Houston Lighting & Power 3470 WAP7 D 0.45 0.40 0.35 14%

TX W A Parish Houston Lighting & Power 3470 WAP8 Da 0.45 0.37 0.31 19%

TX Welsh Southwestern Electric Power 6139 1 D 0.50 0.26 0.27 -4%

TX Welsh Southwestern Electric Power 6139 2 D 0.50 0.29 0.36 -19%

TX Welsh Southwestern Electric Power 6139 3 D 0.50 0.27 0.37 -27%

UT Bonanza Deseret Generation & Tran 7790 1-1 Da 0.50 0.37 0.42 -12%

UT Carbon Pacificorp 3644 1 0.45 0.38 0.50 -24%

UT Carbon Pacificorp 3644 2 0.45 0.39 0.58 -33%

UT Hunter (Emery) Pacificorp 6165 1 D 0.45 0.41 0.50 -18%

UT Hunter (Emery) Pacificorp 6165 2 D 0.45 0.40 0.55 -27%

UT Huntington Pacificorp 8069 1 D 0.45 0.37 0.52 -29%

UT Intermountain Intermountain Power Agency 6481 1SGA Da 0.50 0.39 0.45 -13%

UT Intermountain Intermountain Power Agency 6481 2SGA Da 0.50 0.36 0.38 -5%

VA Chesapeake Vepco 3803 1 0.45 0.45 0.42 7%

VA Chesapeake Vepco 3803 2 0.45 0.44 0.48 -8%

VA Chesapeake Vepco 3803 4 0.45 0.43 0.54 -20%

VA Chesterfield Vepco 3797 3 0.45 0.42 0.52 -19%

VA Chesterfield Vepco 3797 4 0.45 0.45 0.49 -8%
Appendix C-3: Compliance Results for the 272 Early Election Units in 1997

1 New Source Performance Standards subpart.

C-3, 9

VA Glen Lyn Appalachian Power Co 3776 51 0.45 0.42 0.46 -9%

VA Glen Lyn Appalachian Power Co 3776 52 0.45 0.39 Not Oper.

VA Possum Point Vepco 3804 3 0.45 0.45 0.60 -25%

VA Potomac River Pepco 3788 1 0.45 0.42 0.51 -18%

VA Potomac River Pepco 3788 2 0.45 0.39 0.44 -11%

VA Potomac River Pepco 3788 3 0.45 0.44 0.64 -31%

ST

Plant Name Operating Utility ORIS

Code

Boiler NSPS1

Emission

Limit

Actual

Emission Rate

1990

Emission Rate

Change from

1990 to 1997

VA Potomac River Pepco 3788 4 0.45 0.42 0.46 -9%

VA Potomac River Pepco 3788 5 0.45 0.45 0.72 -38%

VA Yorktown Vepco 3809 1 0.45 0.44 0.57 -23%

VA Yorktown Vepco 3809 2 0.45 0.45 0.57 -21%

WA Centralia Pacificorp 3845 BW21 0.45 0.36 0.40 -10%

WA Centralia Pacificorp 3845 BW22 0.45 0.37 0.45 -18%

WI Blount Street Madison Gas & Electric Co 3992 8 0.50 0.41 0.71 -42%

WI Blount Street Madison Gas & Electric Co 3992 9 0.50 0.49 0.61 -20%

WI Columbia Wisconsin Power & Light 8023 1 0.45 0.41 0.46 -11%

WI Columbia Wisconsin Power & Light 8023 2 D 0.45 0.37 0.49 -24%

WI Edgewater Wisconsin Power & Light 4050 5 D 0.50 0.23 0.21 10%

WV Mountaineer (1301) Appalachian Power Co 6264 1 D 0.50 0.50 0.47 6%

WY Dave Johnston Pacificorp 4158 BW41 0.50 0.40 0.48 -17%

WY Dave Johnston Pacificorp 4158 BW42 0.50 0.42 0.54 -22%

WY Jim Bridger Pacificorp 8066 BW74 D 0.45 0.36 0.41 -12%

WY Laramie River Basin Electric Power 6204 1 D 0.50 0.32 0.35 -9%

WY Laramie River Basin Electric Power 6204 2 D 0.50 0.22 0.32 -31%

WY Laramie River Basin Electric Power 6204 3 D 0.50 0.31 0.42 -26%