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 forNOx 

## (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 of0.69 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

3

### Qualifying 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 AllowanceAllocation 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 ofallowance 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 baselinerefer 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) Sub stitution Units(95) 1997 Weighted Av

erage Em ission 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) Sub stitution 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

Em ission Limit (0.50) Tangentially-Fired Boilers

Em ission 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 1T 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

GAMcintosh 1 T T

GAMitchell 3 T T

GAScherer 3 T 4 E

GAWansley 1 T T 2 T T

GAYates Y1BRT T Y2BRT T Y3BRT T Y4BRT T Y5BRT T Y6BRT T Y7BRT 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 KYHmp&L Station 2 H1 T T H2 T T

KY Mill Creek 1 E 2 E 3 E 4 E

KYParadise 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 4TE 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 TE 8 TE MI J H Campbell 1 T T 2 T 3T

MI J R Whiting 1 E 2 T 3 TE 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

NHMerrimack 1 T 2 T

NJ B L England 1 T 2 T

NM Escalante 1 E

NVMohave 1 E 2 E

NVNorth 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 TE 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 1T 2 T 3 T 4 T NY Oswego 4T 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

OHR 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

OHW 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 BW71T BW72 T BW73T 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 JohnsonvilleJVD1 Opt-In 0 0 0 0 0.00% 0.00% TN DuPont JohnsonvilleJVD2 Opt-In 0 0 0 0 0.00% 0.00% TN DuPont JohnsonvilleJVD3 Opt-In 0 0 0 0 0.00% 0.00% TN DuPont JohnsonvilleJVD4 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-3,12APPENDIX 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 BendCS001 (BB01, BB02) 76,818 82,191 FL Big BendBB01 Table1 27,662 38,367 36,986 1,381 FL Big BendBB02 Table1 26,387 47,216 45,205 2,011 FL Big BendXS23 (BB03, BB04) 19,081 20,303 FL Big BendBB03 Table1 26,036 40,281 14,212 26,069 FL Big BendBB04 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, 1APPENDIX 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 Mcintosh1 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 Wansley1 Table1 33,612 34,105 68,908 86,728 34,105 52,623 GA Wansley2 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 Hutsonville5 Substitution 10,772 8,640 9,661 8,721 8,640 81 IL Hutsonville6 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, 2APPENDIX 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 Newton2 Substitution 15,404 13,619 6,346 14,495 13,619 876
IL VermilionCS3 (1, 2) 579 6,208 IL Vermilion 1 Substitution 12,972 16,086 2,173 1147 (e) 12,766 IL Vermilion2 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 Cayuga2 Table1 32,134 51,796 37,415 66,877 51,796 15,081
IN Clifty CreekCS001 (1, 2, 3) 50,661 44,612 IN Clifty Creek1 Table1 19,620 22,350 14,871 7,479 IN Clifty Creek2 Table1 19,289 19,254 14,871 4,383 IN Clifty Creek3 Table1 19,873 19,886 14,870 5,016 IN Clifty CreekCS002 (4, 5, 6) 53,668 48,844 IN Clifty Creek4 Table1 19,552 20,761 16,281 4,480 IN Clifty Creek5 Table1 18,851 19,418 16,281 3,137 IN Clifty Creek6 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 CulleyXS23 (2, 3) 4,800 5,152 IN F B Culley2 Table1 4,703 6,760 5,152 1,608 IN F B Culley3 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, 3APPENDIX 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 Cygne1 Substitution 6,372 6,927 23,489 7,208 6,927 281
KS Quindaro2 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 Paradise3 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, 4APPENDIX 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 Smith11 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, 5APPENDIX 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 Montrose1 Table1 2,877 2,705 7,196 2,840 2,705 135 MO MontroseCS023 (2, 3) 5,431 6,684 MO Montrose2 Table1 7,984 3,370 3,262 108 MO Montrose3 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 Roseton2 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, 6APPENDIX 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 Ashtabula7 Table1 41,910 39,662 18,351 42,659 39,662 2,997 OH AshtabulaCS1 (8, 9, 10, 11) 25,409 6,942 OH Ashtabula8 Substitution 10,753 0 0 0 OH Ashtabula9 Substitution 9,173 0 0 0 OH Ashtabula10 Substitution 8,275 5,902 5,345 557 OH Ashtabula11 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 ConesvilleCS012 (1, 2) 25,264 31,975 OH Conesville1 Table1 4,615 24,980 15,888 9,092 OH Conesville2 Table1 5,360 16,891 16,087 804 OH Conesville3 Table1 12,794 16,424 6,029 17,245 16,424 821 OH Conesville4 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 Stuart2 Substitution 28,054 28,883 39,041 36,006 28,883 7,123 OH J M Stuart3 Substitution 25,957 25,127 38,712 35,618 25,127 10,491 OH J M Stuart4 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, 7APPENDIX 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 Fort6 Table1 12,475 11,815 8,076 3,739 OH Miami Fort7 Table1 38,985 38,666 42,216 49,193 38,666 10,527 OH Miami FortCS056 (5-1, 5-2, 6) 14,421 10,087 OH Miami Fort5-1 Table1 417 1,213 1,006 207 OH Miami Fort5-2 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, 8APPENDIX 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 Shawville2 Table1 13,474 15,609 10,048 16,584 15,609 975 PA ShawvilleCS1 (3, 4) 29,884 33,064 PA Shawville3 Table1 13,846 15,978 15,029 949 PA Shawville4 Table1 13,700 19,165 18,035 1,130
PA Sunbury3 Table1 9,511 11,343 8,530 25,511 11,343 14,168 PA Sunbury4 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, 9APPENDIX 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 River1 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 Weston1 Substitution 1,106 1,318 1,579 1,773 1,318 455 WI Weston2 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 Martin2 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 StormCS0 (1, 2) 107,211 92,716 WV Mt Storm1 Table1 42,570 65,008 46,358 18,650 WV Mt Storm2 Table1 34,644 54,923 46,358 8,565 WV Mt Storm3 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, 10APPENDIX 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 0.46 0.42 1356 Ghent KY 1 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%