Full opinion text
OPINION AND ORDER SARGUS, District Judge. This matter is before the Court following a trial to the Court on Plaintiffs’ claims that Defendant Ohio Edison Company has violated the Clean Air Act [“CAA”], 42 U.S.C. §§ 7401, et seq., in connection with its operation of the W.H. Sammis Station, a coal-fired electric generating facility located in Jefferson County, Ohio. The Plaintiffs consist of the United States of America together with the States of Connecticut, New Jersey and New York. The Sammis Plant is owned by Pennsylvania Power Company, a wholly owned subsidiary of Defendant Ohio Edison which, in turn, is a wholly owned subsidiary of Fir-stEnergy Corporation of Akron, Ohio. The Court has jurisdiction over this action pursuant to 28 U.S.C. § 1331. Pursuant to Fed.R.Civ.P. 52(a), the Court makes the following Findings of Fact and Conclusions of Law based on the evidence adduced at trial. I. INTRODUCTION AND SUMMARY A. Introduction This case highlights an abysmal breakdown in the administrative process following the passage of the landmark Clean Air Act in 1970. For thirty-three years, various administrations have wrestled with and, to a great extent, have avoided a fundamental issue addressed in the Clean Air Act, that is, at what point .plants built before 1970 must comply with new air pollution standards. The Clean Air Act requires plants constructed after 1970 to meet stringent air quality standards, but the Act exempts old facilities from compliance with the law, unless such sites undergo what the law identifies as a “modification.” Decades later, the United States Environmental Protection Agency, together with the States of Connecticut, New Jersey and New York ask this Court to find that eleven construction projects undertaken between 1984 and 1998 on the seven electric generating units at the Sam-mis Plant constituted modifications, requiring Ohio Edison to bring the units into compliance with current ambient air quality standards. By any standard, the enforcement of the Clean Air Act with regard to the Sammis Plant has been disastrous. From a public health perspective, thirty-three years after passage of the Act, the plant to this day emits on an annual basis 145,000 tons of sulphur dioxide, a pollutant injurious to the public health. From an employment perspective, Ohio Edison has chosen to meet other statewide and regional air quality standards by switching to out of state, low sulphur coal, a strategy which in conjunction with other utilities has caused a huge loss of coal mining and related jobs in Ohio. From the standpoint of Ohio Edison, since 1970 the company has invested over $450 million to install pollution control devices on the Sammis units yet still fails to meet the new source pollution standards. Thirty-three years later, the air is still not clean, tens of thousands of jobs have been lost, and enforcement by the EPA has been highly inconsistent. As is described in detail below, the original and current language of the Clean Air Act requires that an older plant undergoing a modification thereafter comply with new air quality standards. Regulations issued under the Clean Air Act by the U.S. EPA may not conflict with statutory language enacted into law by Congress. EPA regulations give further definition as to what types of projects are to be viewed as modifications which trigger the application of new air quality standards to an older facility. These statutory and regulatory definitions are at issue here. This Court takes note of the fact that three decades after passage of the Clean Air Act the EPA finally moved, through this and several other lawsuits, to finally resolve this fundamental issue under the Act. While the law has always been clear, the enforcement strategies of the EPA have not. It is clear to this Court that at various times since 1970 officials of the EPA have been remiss in enforcing the law and clarifying its application to specific projects. For the reasons explained in Section III, 1(H), infra, the Court finds that the EPA’s failures in enforcement do not absolve Ohio Edison from liability under a law that has always been clear. It is also evident from the record in this case that various electric utilities and industry organizations have sought within legal bounds to influence the conduct of the EPA. Given the enormous cost of retrofitting an older electric power plant with new pollution control devices, this strategy should not be unexpected in the democratic and administrative process. What should be unexpected and condemned, however, is an agency unwilling to enforce a clear statutory mandate set forth in an act of Congress. With regard to this case, the parties have litigated at this juncture whether the eleven projects at the Sammis units have triggered application of the standards set forth in the 1977 amendments to the Clean Air Act. The questions resolved today by this Court are legal in nature. In contrast, in the next phase of this case, the remedies the Court may consider and impose involve a much broader, equitable analysis, requiring the Court to consider air quality, public health, economic impact, and employment consequences. The Court may also consider the less than consistent efforts of the EPA to apply and enforce the Clean Air Act. B. Summary of Issues The issues presented in this lawsuit turn on an interpretation of the term “modification.” Congress provided in the Clean Air Act that any modification of a plant triggered application of the Act and later amendments. As described in Section 1(C), infra, the Administrator of the EPA has refined, by regulation, the definition of modification to include only activities which involve both a physical change to a unit and a resulting significant increase in emissions. Excluded from the definition of modification are projects involving only “routine maintenance, repair or replacement.” 40 C.F.R. § 52.21(b)(2)(iii)(a). In this case, Ohio Edison undertook eleven construction projects at the seven Sammis Units. The total cost of the projects was approximately $136.4 million. The documents prepared to justify the expenditures described the various purposes of the projects to include replacement of major components to increase both the life and the reliability of the units. A primary goal of the projects was to prevent or at least diminish the number and duration of outages, meaning unplanned periods of time when the unit was offline and unproductive. By physically replacing aging or deficient components, Ohio Edison intended and achieved a significant increase in the operation and output of the units. In turn, the amount of emission of sulphur dioxide, nitrogen oxides and particulate matter also increased. If the projects were modifications, as used in the Clean Air Act, Ohio Edison was required prior to construction to project and calculate post-construction emissions to determine if the new standards applied. Further, if the projects were modifications, Ohio Edison was required to obtain a pre-construction permit. Because the company contended the projects were not modifications but were instead “routine maintenance, repair and replacement,” neither of those courses was pursued. The EPA and state plaintiffs contend that all eleven projects constituted modifications. While the analysis required to distinguish between a modification sufficient to trigger compliance from routine maintenance, repair and replacement is complex, the distinction is hardly subtle. Routine maintenance, repair and replacement occurs regularly, involves no permanent improvements, is typically limited in expense, is usually performed in large plants by in-house employees, and is treated for accounting purposes as an expense. In contrast to routine maintenance stand capital improvements which generally involve more expense, are large in scope, often involve outside contractors, involve an increase of value to the unit, are usually not undertaken with regular frequency, and are treated for accounting purposes as capital expenditures on the balance sheet. As outlined in Section III, the only two courts which have addressed this issue have essentially adopted this same analysis. As explained in detail below, the projects were all intended to result in increased hours of operation as a result of a reduction in the number and length of forced outages, or shutdown for repair or maintenance. A significant decrease in outages results in a significant increase in both production and emissions. Given the actual goals placed on the construction projects by Ohio Edison, and the substantial increase in emissions certain to follow, the company was required to project future emissions. If those projected increases were substantial, as defined by regulations noted below, preconstruction approval, which was never sought, was required by law. The eleven projects at issue in this case were extensive, involving a combined outlay of $136.4 million dollars. The vast majority of the expenditures were treated for accounting purposes as capital, as opposed to maintenance, expenses. Most of the work was performed by outside contractors, as opposed to in-house maintenance crews. The purpose of the projects was to extend the lives of units built before 1970, not simply to perform routine preventative care on components of the units. Finally, all of the projects involved replacement of major components which had never before been replaced on the particular units. As a result, the projects were not routine in any sense of the term, and could have been projected to significantly increase the emission of pollutants. Congress expressly intended the Clean Air Act and the 1977 Amendments to become applicable to pre-existing plants, as such facilities were modified. As noted by the United States Court of Appeals for the Seventh Circuit in WEPCO'. Congress did not permanently exempt existing plants from these requirements ... existing plants that have been modified are subject to the Clean Air Act programs at issue here. WEPCO, 893 F.2d at 909. Further, as at least one member of the Sixth Circuit has observed: The purpose of the “modification” rule is to ensure that pollution control measures are undertaken when they can be most effective, at the time of new or modified construction. National-Southwire Aluminum Co. v. U.S. EPA, 838 F.2d 835, 843 (6th Cir.1988) (Boggs, J., dissenting). As described in greater detail below, the eleven projects at issue in this case were major modifications sufficient to trigger application of the Clean Air and subsequent amendments. II. FINDINGS OF FACT I. Background The Sammis Plant is situated along the Ohio River on State Route 7 in the Village of Stratton, Saline Township, Jefferson County, Ohio. The Plant consists of seven separate generating units, numbered 1 through 7. Units 1 through 4 were placed in service from 1959 to 1962. Units 1-4 are approximately 150 feet tall, or about 15 stories high. The units use nearly identical naturally circulating boilers in which steam outlet pressures of up to 2,450 pounds per square inch [“psi”] are created. Unit 5 was placed into service in 1967. The unit’s boiler operates in a “once-through universal pressure design,” in which water is evaporated and heated to superheated steam in one continuous series of tubes inside the boiler. Unit 5 includes a coal pulverizing unit which is unique within the United States. The unit is approximately 180 feet tall, or roughly 18 stories high. Unit 6 was placed into service in 1969, while Unit 7 began operations in 1971. The boilers of Units 6 and 7 are identical in design. Similar to Unit 5, these units utilize a once-through universal pressure design while operating at a higher super-critical steam pressure of above 3,203 psi. The boilers of Units 6 and 7 are approximately 200 feet tall. Coal-fired power plants, such as the Sammis plant, generate electricity using three major components: the boiler, turbine and generator. The boiler is a large building — like structure in which coal is burned inside the furnace and the energy from the combustion process is transferred to water to produce steam. The steam is then directed to the turbine where it is further converted to mechanical energy in the form of a spinning turbine shaft, which in turn drives the generator that produces electricity. The walls, roof and floor of the boiler are comprised of tubes, as are the other major components of the boiler, i.e., the economizer, primary superheater, secondary superheater and reheater. The components are made up of densely packed assemblies of tubes that incrementally raise the temperature of the steam before it leaves the boiler to generate electricity. The Sammis units are fueled by pulverized coal, meaning that coal is fed from bunkers to pulverizers that grind the coal to a powdery consistency. The pulverized coal is then conveyed through coal pipes to burners where it is ignited and combusts within the furnace area of the boiler. The flame resulting from the combustion of the pulverized coal/air mixture extends into the furnace area of the boiler, releasing the chemical energy present in the coal in the form of light and heat energy. In the combustion of coal, chemical energy, gas by-products and particulate matter [“PM”] are released. The gases are collectively referred to as flue gas. The flue gases produced from the combustion process form carbon dioxide, carbon monoxide, sulfur dioxide [“S02”]and nitrogen oxides [“NOx”]. The flue gases flow through the convection section of the boiler and exit to the air heater and to any pollution control devices. From there, the flue gases enter an induced draft fan and then exit through a stack and into the atmosphere. The tubes that comprise the waterwalls and major components are in constant contact with the flue gas and/or combusting coal. Leaks in the tubes are caused by thermal cycling (heating up and cooling down), external corrosion from exposure to caustic agents, erosion from high flue gas velocities and entrained ash particles and internal corrosion caused by poor water quality. As a result, the tubes require regular repair or replacement. Each of the units has a Net Dependable Capacity [“NDC”], which is the maximum output of electricity that a unit can expect to achieve over a long period of time. (Pipitone Testimony, Tr. Vol. V at 211). A unit’s NDC is confirmed each year by an eight hour test in accordance with protocols established by the North American Electric Reliability Council [“NERC”]. Sammis Units 1 and 2 had original NDCs of 188 megawatts [“MW”] each. Units 3 and 4 were rated at 192 MW, Unit 5 was rated at 330 MW, and Units 6 and 7 were rated at 650 MW. (Pipitone Testimony, Tr. Vol. V at 218). In the late 1970s, the NDCs were lowered to improve Sammis’ overall reliability and more accurately measure potential output. The changed ratings remain the same today: Units 1-4 have an NDC of 180 MW each, Unit 5 has an NDC of 300 MW and Units 6 and 7 have an NDC of 600 MW each. (Id., Tr. Vol. V at 213). Ohio Edison plans its operations based upon the NDCs of its units. (Id., Tr. Vol. V at 212). Ohio Edison also uses the NDCs in reports concerning reserve margins for its electrical system which are sent to the Public Utilities Commission of Ohio [“PUCO”] and the Federal Energy Regulatory Commission [“FERC”]. (Id., Tr. Vol. V at 214). Electricity is generated on an “as needed” basis, since at most plants electricity cannot be stored. The demand for electricity and hence, the generation of electricity, varies on any given day as well as with the weather patterns and the overall economy. (Garfield Testimony, Tr. Vol. VII at 150-52). The Sammis plant operates within a system of interconnected electric generating units on a “power grid.” (Id., Tr. Vol. VII at 156-57). Ohio Edison is obligated to possess enough generating capacity to meet the highest possible electricity demand with adequate backup capacity to ensure against unforeseeable emergencies. (Koppe Testimony, Tr. Vol. IV at 161). Reliability is a critical element of power plant operation. (Pipitone Testimony, Tr. Vol. V at 192). In general, reliability is measured with reference to whether a unit is able to operate over sustained periods at the level of output required by the utility. (Id., Tr. Vol. V at 193). One measure of reliability is availability, i.e., the percentage of total time in a given period that a unit is available to generate electricity. (Id.). A related measure of reliability is the amount of forced outage rate, which reflects the percentage of time in a period (such as a year) when a unit is forced offline involuntarily. (Id., Tr. Vol. V at 195). A forced outage occurs when a unit must be brought off-line due to a component problem. (Monti Testimony, Tr. Vol. I at 196). The most common cause of forced outages in a coalfired electric plant is boiler tube failure. (Hecking Testimony, Tr. Vol. II at 132; Def. Exhibit 284). Utilization is a measure of how much an available unit is actually used to generate electricity. (Garfield Testimony, Tr. Vol. VII at 166). Many factors influence a utility’s utilization of a given unit, including the unit’s fuel costs, the unit’s heat rate or efficiency, the unit’s response to load variation, the unit’s location in the transmission system, and the demand for electricity and other low-cost sources of electricity. (Id., Tr. Vol. VII at 166). Heat rate measures the quantity of heat necessary to generate a kilowatt-hour of electricity. (Koppe Testimony, Tr. Vol. IV at 158). Heat rate is measured as a ratio of Btu’s per kilowatt hour. (Pipitone Testimony, Tr. Vol. V at 192). In general, the lower a unit’s heat rate, the less coal it will burn to generate the same amount of electricity. (Koppe Testimony, Tr. Vol. IV at 159). In the 1980s and 1990s, Ohio Edison developed a program to improve the heat rate of the Sammis units. (Pipitone Testimony, Tr. Vol. VI at 37). Projections of future heat rate improvements were reflected in five-year plans for the Sammis Plant. (Def. Exhibit 1345, Sammis Plant Five-Year Plan, 1986-1990; Joint Exhibit 315, Sammis Plant Five-Year Plan, 1989-1993). According to Defendant representatives Pipitone and Kaiser, a range of activities were undertaken to improve the heat rate of the Sammis units, from replacement of boiler duct work expansion joints and refurbishment of internal turbine seals to opeartor training. (Pipitone Testimony, Tr. Vol. VI at 37; Kaiser Testimony, Tr. Vol. X at 94, 104). According to Pipitone, the Sammis units experienced long-lasting heat rate improvements as a result of the foregoing efforts. (Pipitone Testimony, Tr. Vol. VI at 38). As stated supra, electric generating boilers are subject to failure due to the conditions under which they operate. Combustion temperatures of up to 3000 F in the Sammis boilers transfer heat to the boiler tube metal, which has temperatures of 450 F to 1,200 F, and then to the fluid inside the tubes at temperatures of approximately 400 to 1,100 F. (Def. Exhibit 136, Report of R. Vetterick at 11). Short-term overheat is the most common cause of boiler tube failure. (Id. at 12). Boiler tube metal temperature quickly rises if anything inside the boiler tube interferes with the heat flow to the boiler fluids. (Id. at 11). At higher temperatures, the tube metal becomes “plastic,” losing strength to the point where the boiler tube metal begins to stretch or bulge out like a balloon due to the internal pressure. (Id.). As a result, the boiler tube wall becomes thinner and ruptures. (Id. at 11-12). Another common cause of boiler tube failure is erosion. (Id. at 12). Fly ash in the flue gas wears away the metal of the boiler tubes and as the tube walls lose strength from thinning, boiler tube failures occur. (Id. at 12). Consequently, boiler components, particularly boiler tubes, must be repaired or replaced on a regular basis. At Sammis, each boiler is regularly scheduled for an outage, during which tube replacement and other needed repairs or work are performed so as to minimize unit downtime. (Pipitone Testimony, Tr. Vol. V at 202). Scheduled boiler outages occur every twelve to thirty-six months at the Sammis units. (Id.). Scheduled turbine outages, which involve more downtime, occur every five to seven years at the Sammis units. (Id., Tr. Vol. at 203). During turbine outages, work is performed inside the boiler and the turbine itself is disassembled and inspected. (Hekking Testimony, Tr. Vol. II at 135-36). Monorails are permanently installed at Sammis for use in such repair and replacement work. (Wagstajf Depo. at 164). The work done inside the boilers is performed by contractors because Sam-mis’ in-house staff is not certified to perform welds on pressurized parts, i.e., tubes, tube panels and tubé assemblies. (Pytash Testimony, Tr. Vol. VII at 84, 85, 89, 93, 107, 108, 122, 124). Regularly scheduled outages result in fewer forced outages, reduced temporary deratings and overall improvement in unit reliability and availability. (Pytash Testimony, Tr. Vol. VII at 100-01, 104-05, 109, 112-14). In connection with improving Sammis’ overall plant performance, Ohio Edison undertook “Plant Betterment / Life Extension Studies” beginning in 1984 for each of the Sammis units. (Pipitone Testimony, Tr. Vol. VI at 12). For example, the study as to Unit 3, dated August 18-31, 1987, states that the “purpose of the inspection [of Unit 3] was to identify what major components would require repair or replacement to permit reliable unit generation to the year 2015 (30 years) and to determine when this work would be required.” (Def. Exhibit 1456 at § I). Further, the study states that “it is practical, from an equipment viewpoint, to extend the life of Sammis Unit 3 until the year 2015 while maintaining current levels of efficiency and availability. The cost to repair or replace the major unit components identified in this report as required to extend life as a base loaded unit to 2015 is estimated to less than $100/kw (1985 dollars).” (Id.). According to Defendant, electric generating units do not have predetermined fives. Defendant contends that the fife of a given unit is determined by overall economic, market and system conditions. (Pi-pitone Testimony, Tr. Vol. VI at 19-20). Ohio Edison submits that, whether a unit has additional fife depends upon the cost incurred by the unit in producing electricity compared to the market price of electricity. Defendant argues that the date 2015 was a date selected for economic analysis purposes. (Id., Tr. Vol. VI at 28, 30). The Government takes issue with this contention and argues that the projects undertaken were done to extend the useful fives of the Sammis units. One of the Government’s experts, Alan Hekking, testified that the age of a coal-fired power plant has a significant impact on the plaint’s availability and reliability, as well as the amount of maintenance. (Hekking Testimony, Tr. Vol. II at 138-39; see also STEAM—Its Generation and Use, Babcock & Wilcox at 46-1 to 46-2 (40th ed.1992), PI. Exhibit 1399). At the beginning of plant fife, there is a start-up period which is often marked by a high forced outage rate. Thereafter, the new plant experiences few forced outages. (Hekking Testimony, Tr. Vol. II at 141). As the plant matures, the aging process results in increased forced outages, maintenance costs and availability declines. Unless overhauls are performed or major components are completely replaced, the forced outage rate gradually increases. (Id. at 144). In the 1980s, as the majority of coal-fired plants in the United States reached the age of 25 to 30 years, a strategy called “fife extension” emerged. (Id. at 146). Life extension is a term used in the electric utility industry to explain a method of delaying plant retirement by replacing and redesigning components of the unit to make the unit more available and reliable for years into the future. (Id. at 146-47). Ohio Edison participated in the fife extension strategy through its membership in a number of electric utility industry groups, in particular, the Electric Power Research Institute [“EPRI”], which was formed in the 1970s. Ohio Edison was a member of the organization from the time of its inception. (Pipitone Testimony, Tr. Vol. VI at 116-18). EPRI sponsored conferences and published studies concluding that the average service fife of a coal-fired boiler is typically 30 to 40 years. (Hekking Testimony, Tr. Vol. II at 156-57). For example, as EPRI explained at a conference in June 1986: Fossil-fuel-fired generating stations have traditionally been built with an assumed nominal design and economic fife of about 30 years. The implicit expectation was that these units would be replaced at the end of this period with new units that would meet load requirements and, through the use of technological improvements, produce power at lower cost, higher availability, and higher efficiency. These expectations have not been realized because of a number of factors that include low load growth, escalating construction costs, historically high interest rates, siting difficulties, and increasingly uncertain regulatory restraints. Utilities have recognized that the potential lifetime of an existing plant may be far in excess of the nominal economic life and that there are numerous inherent economic and system planning advantages in the continued usage of older plants. Thus, utilities are beginning to consider life extension methods as a possible way of retaining units in service for 50 to 60 years or longer. (PI. Exhibit 1862). As described infra, a number of the Sam-mis activities were undertaken to extend the useful lives of the units. These activities were consistent with the “life extension” strategy. II. The Eleven Sammis Activities Plaintiffs claim that Ohio Edison undertook eleven projects at the Sammis Units 1 through 7 which constitute “modifications” for purposes of the CAA. The eleven activities are made up of thirty-four parts replacements to the units. The parts that were replaced were both pressure and non-pressure components. The pressure parts of the Sammis boilers include the furnace water wall tubes, economizer tubes, superheater tubes and reheater tubes. (Amended Joint Stipulations at ¶ 36). The economizer, superheater and reheater function as heat exchangers with water or steam flowing on the inside and the hot boiler combustion gases passing on the outside. (Id.). The non-pressure parts are comprised of burners, coal pipes, pulverizers and low pressure turbine rotors. (Krause Testimony, Tr. Vol. VI at 217). A. Activity 1: 1993 Scheduled Outage — Unit 1 Unit 1 was removed from service for a scheduled turbine outage from September 26, 1993 to January 1, 1994. (Amended Joint Stipulations at ¶ 75). At the time of the outage, Unit 1 was thirty-four years old with no scheduled retirement date. (Def. Exhibit 1905). During the outage, Ohio Edison replaced three banks of horizontal reheater tubes due to corrosion, high temperature creep and dissimilar material weld damage. (Amended Joint Stipulations at ¶ 73). The capitalized cost of the replacements was approximately $2,828,096.92. (Id. at ¶ 74). The total cost of the replacement was $3,286,466.00. (Id.). Ohio Edison also replaced furnace ash hopper boiler tubes at Unit 1. (Id. at ¶ 76). The capitalized cost of the replacement was approximately $2,543,157.12. The total cost of the replacement was $2,404,062.00. (Id. at ¶77). During the same scheduled outage, Ohio Edison also replaced secondary superheater outlet headers at Unit 1. (Id. at ¶ 79). The capitalized cost of the replacement was approximately $858,344.53 and the total cost of the replacement was $931,360.00. (Id. at ¶ 80). The aggregate capitalized cost, in 1992 dollars, of the replacement components at Unit 1 was $6.1 million dollars. (Def. Exhibit 1905). Ohio Edison’s Sammis Boiler Study, July 6, 1989, showed that in 1987-88, there were 8 boiler tube failures at the Unit 1 reheater, secondary superheater outlet headers and furnace ash hopper tubes, all of which were replaced during the Unit 1 outage. (Joint Exhibit 226). The study showed that there would be a virtually 100% reduction in tube failures if the components were replaced. (Id.). Furthermore, the X 176 forms prepared for the replacements of the Unit 1 reheat-er and furnace ash hopper tubes predicted a prevention of tube failures and associated improved availability in the years to follow the replacements. (PI. Exhibit 476). The same predictions were made on the X-176 forms for replacement of the Unit 1 secondary superheater outlet headers (Def. Exhibit 1553) and replacement of the Unit 1 furnace ash hopper boiler tubes (PI. Exhibit 482). B. Activity 2: 1991 Scheduled Outage — Unit 2 Unit 2 was removed from service for a scheduled turbine outage from February 22, 1991 to June 1, 1991. {Amended Joint Stipulations at ¶ 84). At the time of the outage, Unit 2 was thirty years old and had no scheduled retirement date. (Def. Exhibit 1905). During the outage, Ohio Edison replaced three banks of horizontal reheater tubes due to internal corrosion. (Amended Joint Stipulations at ¶ 83). The capitalized cost of the replacement was approximately $2,888,399.93. (Id.). The total cost of the replacement was $2,521,867.00. (Id.). Ohio Edison also replaced furnace ash hopper tubes at Unit 2 during the outage. The capitalized cost of the replacement was approximately $2,036,653.90 and the total cost was $2,978,756.00. (Id. at ¶ 86). During the forced outage, Ohio Edison also replaced the secondary superheater outlet headers of Unit 2. The capitalized cost of the replacement was $875,719.18 and the total cost of the replacement was $956,385.00. (Id. at ¶ 89). The aggregate capitalized cost of the replacement projects at Unit 2, in 1992 dollars, was $5.9 million. (Def. Exhibit 1905). According to Ohio Edison, the tubes and headers replaced during the outage are frequently replaced within the coal-fired electric utility industry. (Def. Exhibit 136, Vetterick Report at 23-24). Ohio Edison concedes that none of the components were inoperable at the time of replacement. Rather, Ohio Edison determined that replacement would be more cost-effective than future repairs. (Krause Testimony, Tr. Vol. VI at 196, 198, 200-02; Pipitone Testimony, Tr. Vol. VII at 9-15; Koppe Testimony, Tr. Vol. IV at 199-201). The purpose of the replacement projects at Unit 2 was to reduce maintenance costs and forced outages and improve availability and reliability. (Def. Exhibit 1905). Ohio Edison’s Sammis Boiler Study, July 6, 1989, shows that in 1987-88, there were 5 tube failures at the Unit 2 reheater, secondary superheater outlet headers and furnace ash hopper tubes. (Joint Exhibit 226). The study predicted that there would be close to a 100% reduction in tube failures if the components were replaced. (Id.). The X-176 forms for the Unit 2 reheater, secondary superheater outlet headers and furnace ash hopper boiler tube replacements anticipated the elimination of tube failures and associated improved availability in the years following the replacements. (Def. Exhibits 1528, 1369 and Joint Exhibit 174). C. Activity 3: 1992 Scheduled Outage — Unit 3 Unit 3 was removed from service for a scheduled turbine outage from August 30, 1992 to December 26,1992. At the time of the outage, Unit 3 was thirty-one years old with no scheduled retirement date. (Def. Exhibit 1905). During the outage, Ohio Edison replaced three banks of horizontal reheater tubes due to creep damage, differential metal weld stresses and internal out-of-serviee corrosion. CAmended Joint Stipulations at ¶ 91). The capitalized cost of the replacements was approximately $3,487,528.06. The total cost of the reheat-er tube replacement was $3,113,596.00. (Id. at ¶ 92). During the outage, Ohio Edison also replaced furnace ash hopper tubes due to corrosion fatigue and out-of-service corrosion. (Id. at ¶ 94; Def. Exhibit 136, Vetterick Report at 24-25). The capitalized cost of the replacement was approximately $2,184,654.18 and the total cost of the replacement was $2,321,520.00. (Amended Joint Stipulations at ¶ 95). Ohio Edison also replaced secondary su-perheater outlet headers on Unit 3 due to creep failure. (Id. at ¶ 97; Def. Exhibit 136, Vetterick Report at 25). The capitalized cost of the replacement was approximately $859,517.62 and the total cost of the replacement was $875,423.00. (Amended Joint Stipulations at ¶ 98). In addition, Ohio Edison replaced some front wall south cell tubes at Unit 3 due to failure from internal corrosion and internal deposits. (Id. at ¶ 100; Def. Exhibit 136, Vetter-ick Report at 25-27). Thirty-nine of the one hundred ten tubes that comprise the front wall of the south cell were replaced. (Krause Testimony, Tr. Vol. VI at 218). The capitalized cost of the replacement was approximately $614,323.83 and the total cost of the replacement was $626,092.00. (Amended Joint Stipulations at ¶ 101). During the same outage, Ohio Edison also replaced some furnace south sidewall tubes at Unit 3 due to severe bowing from previous failures, poor circulation and overheat failures. (Id. at ¶ 103; Def. Exhibit 136, Vetterick Report at 28-29). Seventy-four of the two hundred seventy five south sidewall tubes were replaced. (PI. Exhibit 147, Hekking Report at 37). The capitalized cost of the furnace south sidewall tube replacement was $235,300.76 and the total cost of the replacement was $234,682.00. (Amended Joint Stipulations at ¶ 104). In addition, Ohio Edison replaced radiant downflow tubes at Unit 3 due to severe radiant heat thermal fatigue. (Def. Exhibit 1905 and Def. Exhibit 136, Vetterick Report at 27-28). According to Defendant, the types of replacements made during Activity 3 are common in the coal-fired electric utility industry. (Def. Exhibit 136, Vetterick Report at 24-29; Krause Testimony, Tr. Vol. VII at 9-15; Koppe Testimony, Tr. Vol. IV at 199-201). Further, although none of the components were inoperable at the time of replacement, Ohio Edison determined that it would be more cost-effective to replace them than to make continued repairs. (Krause Testimony, Tr. Vol. VI at 196-98, 200-02; Pipitone Testimony, Tr. Vol. VI at 97-98, 113). Ohio Edison’s goal in doing the replacements was to reduce maintenance costs and forced outages and to improve availability and reliability. (Def. Exhibit 1905). The aggregate capitalized cost, in 1992 dollars, of the Activity 3 replacement projects was $7.8 million dollars. (Id.). The Sammis Boiler Study, July 6, 1989, identified ten tube failures at the seven components that were replaced as part of Activity 3. (Joint Exhibit 226). The study predicted close to a 100% reduction in tube failures after the replacements. (Id.). The X-176 forms preceding the projects predicted a prevention of tube failures and associated improved availability in the years following the replacements. (Joint Exhibit 573, Def. Exhibit 1450, PI. Exhibit 576, PI. Exhibit 123, Def. Exhibit 1453 and PI. Exhibit 490). D. Activity 4: 1990 Scheduled Outage — Unit 4 Unit 4 was removed from service for a scheduled turbine outage from May 13, 1990 to September 26, 1990. (.Amended Joint Stipulations at ¶ 108). At the time the outage began, Unit 4 was twenty-seven years old with no scheduled retirement date. (Def. Exhibit 1905). During the outage, Ohio Edison replaced furnace ash hopper tubes due to tube metal deterioration from corrosion and fatigue and out-of-service corrosion. (Id. at ¶ 106; Def. Exhibit 136, Vetterick Report at 29-30). The capitalized cost of the replacement was approximately $1,873,989.95 and the total cost was $3,028,104.00. (Amended Joint Stipulations at ¶ 107). During the outage, Ohio Edison also replaced front waterwall tubes in part due to waterside corrosion, fatigue cracking, random soot blower erosion, and weld failures. (Id. at ¶ 109; Def. Exhibit 136, Vetterick Report at 30-31). The capitalized cost of the replacement was approximately $1,490,250.06 and the total cost of replacement was $1,871,148.00. (Amended Joint Stipulations at ¶ 110). Ohio Edison also replaced superheater control condenser tubes at Unit 4 due to heat exchanger cracking. (Def. Exhibit 136, Vetterick Report at 31). According to Ohio Edison, the tubes and headers replaced during Activity 4 are commonly replaced by coal-fired plants in the electric utility industry. (Def. Exhibit 136, Vetterick Report at 29-31; Krause Testimony, Tr. Vol. VII at 9-15; Koppe Testimony, Tr. Vol. IV at 199-201). All of the components were operable at the time Ohio Edison determined that replacement would be more cost-effective than continued repair. (Krause Testimony, Tr. Vol. VI at 196-98, 200-02; Pipitone Testimony, Tr. Vol. VI at 98-101, 97-98, 113). Ohio Edison’s intent in undertaking Activity 4 was to reduce maintenance costs and forced outages and improve availability and reliability. (Def. Exhibit 1905). The aggregate capitalized cost of the project, in 1992 dollars, was $3.7 million. (Id.). The Sammis Boiler Study, July 6, 1989, showed that from 1985 to 1988, there were 17 tube failures at the Unit 3 furnace ash hopper tubes, secondary superheater third pass outlet header tube stubs, and water-wall tubes that were ultimately replaced as part of Activity 4. (Joint Exhibit 226). The study predicted a virtually 100% reduction in tube failures if the components were replaced. (Id.). In addition, the X-176 forms prepared for the three projects done in Activity 4 predicted a prevention of tube failures and associated improved availability in the years immediately following the replacements. (Joint Exhibit 404, Joint Exhibit 139, PI. Exhibit 1956). E. Activity 5: 1984 Scheduled Outage — Unit 5 Unit 5 was removed from service for a scheduled turbine outage from January 24, 1984 to October 7,1984. During that time, Ohio Edison replaced the vertical tube furnace with a spiral tube furnace. At the time the project commenced, Unit 5 was sixteen years old. (Def. Exhibit 1905). The purpose of the replacement was to avoid overheating and possible explosions resulting from design and safety deficiencies inherent in the unit. (Krause Testimony, Tr. Vol. VI at 206-08, 214-17; Def. Exhibit 1905; Def. Exhibit 136, Vetterick Report at 32-34). All of the components were operable at the time of replacement. (Krause Testimony, Tr. Vol. VI at 196-98, 200-02; Pipitone Testimony, Tr. Vol. VI at 97-98, 113). The spiral waterwall tubes installed on Unit 5 performed exactly the same function as the vertical waterwall tubes that were replaced, carrying the same amount of feed water and absorbing the same amount of heat as the tubes they replaced. (Vetterick Testimony, Tr. Vol. IX at 166). The boiler’s capacity and operating pressure did not change since there was no functional change with the spiral tube arrangement. (Def. Exhibit 136, Vet- terick Report, at 33; Vetterick Testimony, Tr. Vol. IX at 166). According to Vetter-ick, Ohio Edison’s replacement of the vertical tube furnace with a spiral tube furnace was representative of a commonly practiced response to fundamental design problems in the older boiler and did not change the boiler’s basic operating performance characteristics. (Def. Exhibit 136, Vetterick Report at 32-34). Only five percent of Unit 5’s total heating surface was replaced during the project. (Id. at 32). The capitalized cost of the replacement of the vertical tube furnace with a spiral tube furnace was $12,058,188.07. (Amended Joint Stipulations at ¶ 113). The total capitalized cost of the project, including the installation of new low NOx burners, was approximately $16,739,000.00. (Wagner Testimony, Tr. Vol. VIII at 72-73). The total cost of the project at Unit 5 was approximately $17,500,000.00. (Id., Tr. Vol. VIII at 71). F. Activity 6: 1990 Scheduled Outage — Unit 5 Unit 5 was removed from service for a scheduled turbine outage from April 22, 1990 to July 21, 1990. At the time of the outage, Unit 5 was twenty-two years old with no scheduled retirement date. (Def. Exhibit 1905). During the outage, Ohio Edison replaced economizer tubes damaged by erosion in order to reduce fly ash pluggage and to lessen flue gas velocities. (Amended Joint Stipulations at ¶ 115). The capitalized cost of the replacement of the economizer was approximately $1,500,190.77. (Id. at ¶116). The total cost of the replacement of economizer tubes was $1,538,340.00. (Id.). During the same outage, Ohio Edison replaced secondary superheater outlet pendant tubes at Unit 5 due in part to damage from high temperature creep. (Id. at ¶ 118). Only the third pass of the tubes was replaced; the first and second passes of the secondary superheater tubes were not replaced. (Krause Testimony, Tr. Vol. VI at 220). The capitalized cost of the replacement was approximately $1,889,595.69. (Amended Joint Stipulations at ¶ 119). The total cost of the replacement was $1,831,916.00. (Id.). Also during the outage, Ohio Edison replaced reheater outlet pendant tubes due to damage caused by high temperature creep and coal ash erosion. (Id. at ¶ 121). The bank of inlet tubes were not replaced. (Id. at ¶¶ 121-23). The capitalized cost of the replacement of the reheater outlet pendant tubes was approximately $1,258,613.84. (Id. at ¶122). The total cost of the replacement was $1,196,860.00. (Id.). According to Ohio Edison, the tube replacement is common in the coal-fired electric utility industry. (Def. Exhibit 136, Vetterick Report at 35-37; Krause Testimony, Tr. Vol. VII at 9-15; Koppe Testimony, Tr. Vol. IV at 199-201). All of the components were operable at the time of the replacement. Ohio Edison determined, however, that replacement would be more cost-effective than continued repairs. (Krause Testimony, Tr. Vol. VI at 196-98, 200-02; Pipitone Testimony, Tr. Vol. VI at 97-98,113). The purpose of the activity was to reduce maintenance costs and avoid increases in the forced outage rate. (Def. Exhibit 1905). The aggregate capitalized cost of the project, in 1992 dollars, was $4.8 million. (Id.). Ohio Edison’s Sammis Boiler Study, July 6, 1989, revealed that from 1985 to 1988, there were 17 tube failures at the Unit 5 economizer, reheater outlet pendants, secondary superheater outlet pendants and the upper furnace arch floor, all of which were replaced during Activity 6. (Joint Exhibit 226). The study predicted a 100% reduction in tube failures if the components were replaced. (Id.). The X-176 forms prepared for the replacements predict a prevention of tube failures and associated improved availability in the years immediately following the replacements. (Joint Exhibit 92, Def. Exhibit 1469, Joint Exhibit 436, PI. Exhibit 868). G. Activity 7: 1986-87 Scheduled Outage — Unit 6 Unit 6 was removed from service for a scheduled turbine outage from September 5, 1986 to February 1, 1987. (Amended Joint Stipulations at ¶ 126). At the time of the project, Unit 6 was seventeen years old with no scheduled retirement date. (Def. Exhibit 1905). During the outage, Ohio Edison replaced horizontal reheater and economizer tubes due to erosion, corrosion, and tube failures from fly ash erosion. (Amended Joint Stipulations at ¶ 124; Koster Depo. at 292-93). The capitalized cost of the replacement was approximately $4,899,877.85. (Id. at ¶ 125). According to Ohio Edison, the replacement of the horizontal reheater and economizer tubes is common in the coal-fired electric utility industry. (Def. Exhibit 136, Vetterick Report at 37-40; Krause Testimony, Tr. Vol. VII at 9-15; Koppe Testimony, Tr. Vol. IV at 199-201). All of the components were operable at the time of replacement. Ohio Edison determined that replacement was more cost-effective than continued repairs. (Krause Testimony, Tr. Vol. VI at 196-98, 200-02; Pipitone Testimony, Tr. Vol. VI at 97-98, 113). The purpose of the project was to avoid tube leaks. (Def. Exhibit 1905). The aggregate capitalized cost of the project was $6.3 million. (Id.). In the Sammis Five Year Plan, 1986-1990 (Joint Exhibit 384), Ohio Edison noted that “[rjecent failure history in the pendant reheater, horizontal reheater, and furnace waste and slope areas indicate that failures in these sections will increase from an estimated seven in 1985 to eighteen in 1990.” The X-176 forms for the project predicted a prevention of tube failures and associated improved availability in the years following the replacements. (Def. Exhibit 1617). H. Activity 8: 1991-92 Scheduled Outage — Unit 6 Unit 6 was removed from service for a scheduled turbine outage from December 6, 1991 to April 17, 1992. (Amended Joint Stipulations at ¶ 129). At the time, Unit 6 was twenty-three years old with no scheduled retirement date. (Def. Exhibit 1905). During the outage, Ohio Edison replaced burners at Unit 6 with new low-NOx burners to comply with CAA requirements. (Amended Joint Stipulations at 11127; Def. Exhibit 136, Vetterick Report at 40-41). The capitalized cost of the replacement was approximately $4,002,998.07. (Amended Joint Stipulations at ¶ 128). The total cost of the project was $3,881,462.00. (Id.). According to Ohio Edison, the replacement of burners with low NOx burners .is common within the coal-fired electric utility industry for purposes of reliable operation and pollution control. (Def. Exhibit 136, Vetterick Report at 41). The low NOx burners were installed to reduce NOx emissions in anticipation of the requirements under the Acid Rain Program, Title IV of the Clean Air Act. (Id. at 40-41). Prior to replacement, the Unit 6 burners “caused slagging problems in.the furnace” so that Ohio Edison “occasionally had to take 50 megawatt der-ates to get the boiler cleaned up for further service.” (Krause Testimony, Tr. Vol. VII at 62). The deratings of capacity were taken about 12 days per year. (Id.). According to Vetterick, the low-NOx burners could not have been installed without replacement of the waterwall tubes through which the burners must pass and replacement of the coal pipes to connect the pulverizers to the burners. (Id. at 40, 43-44). Ohio Edison partially replaced front and rear waterwall tubes in the burner area to accommodate the new low NOx burners and to address failures from thermal fatigue and steam corrosion. (Amended Joint Stimulations at ¶ 130; Def. Exhibit 136, Vetterick Report at 40-41; Def. Exhibits 1477, 1482, 1483, 1484). The capitalized cost of the replacement of front and rear waterwall tubes at Unit 6 was approximately $4,352,391.02. (Amended Joint Stipulations at ¶ 131). The total cost of the project was $4,496,302.00. (Id.). During the outage, Ohio Edison replaced reheater riser and pendant tubes at Unit 6 to address failures from out-of-service corrosion damage and high temperature creep. (Id. at ¶ 133; Def. Exhibit 136, Vetterick Report at 41-43). The capitalized cost of the replacement was approximately $4,976,400.32. The total cost of the replacement was $5,321,175.00. (Amended Joint Stipulations at ¶ 134). Ohio Edison also replaced the first, second, and third pass mix area wall panels at Unit 6 due to increasing tube failures at the mix location. (Id. at ¶ 136; Def. Exhibit 136, Vetterick Report at 40-41; Def. Exhibits 1478 and 1479). The capitalized cost of the replacement was approximately $2,875,535.93. {Amended Joint Stipulations at ¶ 137). The total cost of the replacement was $2,527,402.00. (Id.). In addition, Ohio Edison replaced coal pipes at Unit 6 to accommodate the new low-NOx burners and to address fire hazard and safety problems from pipe erosion and leakage. (Id. at ¶ 139; Def. Exhibit 136, Vetterick Report at 43-44, Def. Exhibits 1487 and 1481). The capitalized cost of the replacements was approximately $3,437,941.95. (Amended Joint Stipulations at ¶ 140). The total cost was $3,424,440.00. (Id.). According to Ohio Edison, the tubes, pipes and burners replaced during the outage are commonly replaced by coal-fired plants in the electric utility industry. (Def. Exhibit 136, Vetterick Report at 40-44; Krause Testimony, Tr. Vol. VII at 9-15; Koppe Testimony, Tr. Vol. IV at 199-201). Ohio Edison contends that the project resulted in approximately 60% reduction in NOx emissions. (Krause Testimony, Tr. Vol. VII at 3, 7). The aggregate capitalized cost of the project, in 1992 dollars, was $20.7 million. (Def. Exhibit 1905). Ohio Edison’s Sammis Boiler Study, July 6, 1989, shows that from 1985-1988 there were 28 tube failures at the Unit 6 reheater riser and waterwall tubing and mix area that were replaced as part of Activity 8. (Joint Exhibit 226). The study predicted close to a 100% reduction in tube failures if the components were replaced. (Id.). The X-176 forms for the replacements done during Activity 8 anticipated a reduction in tube failures and/or improved availability in the years immediately following the replacements. (PI. Exhibit 577, Def. Exhibit 1593,1429 and 1491). I. Activity 9: 1998 Scheduled Outage — Unit 6 Unit 6 went out of service for a scheduled turbine outage from January 24, 1998 to May 2, 1998. (Amended Joint Stipulations at ¶ 144). At the time of the project, Unit 6 was twenty-eight years old with no scheduled retirement date. (Def. Exhibit 1905). During the outage, Ohio Edison replaced the CR-77 pulverizers with new MPS pulverizers due to a long history of maintenance problems and low quality coal fineness that caused an increased slagging conditions in the furnace and secondary superheater. (Amended Joint Stipulations at ¶ 142; Def. Exhibit 136, Vetterick Report at 44-46; Vetterick Testimony, Tr. Vol. IX at 172-75; Def. Exhibits 1410, 1496; PI. Exhibit 1614). Both the CR-77 pulverizers and the new MPS pulverizers were manufactured by Babcock and Wilcox. (Hekking Testimony, Tr. Vol. III at 56-57). At the time of replacement, in 1998, the CR-77 pulveriz-ers at Sammis Units 6 and 7 were the last such operating pulverizers in the world. (Vetterick Testimony, Tr. Vol. IX at 174-75; Def. Exhibit 136, Vetterick Report at 45-46; Krause Testimony, Tr. Vol. VI at 225 and Vol. VII at 14). Ohio Edison’s replacement of the pulverizers with MPS pulverizers was consistent with actions taken by other coal-fired plants within the electric utility industry under the same circumstances. (Def. Exhibit 136, Vetterick Report at 45-46). The MPS pulveriz-ers were installed to reduce maintenance costs, increase unit availability and improve heat rate and additional peaking megawatts availability. (Def. Exhibit 1905). The capitalized cost of the project was approximately $16,522,015.42. (Amended Joint Stipulations at ¶ 143). During the five years prior to the replacement of the CR-77 pulverizers, Unit 6 suffered 449 deratings and one outage attributable to the pulverizers. (PL Exhibit 152, Koppe Report at 60). Between 1985 and 1989, Ohio Edison experienced an average loss of annual megawatts per year of 94,619 MW hours. The loss was attributable to outages and deratings caused by the performance of the pulverizers at Unit 6. (PI. Exhibit 1908). As of June 13, 1990, Ohio Edison predicted that “[cjontinued operation of these pulverizers is projected to result in even higher operation and maintenance costs in the future.” (Id.). In May 13, 1997, Ohio Edison again studied the pulverizers at Unit 6 and determined that the unavailability of Unit 6 pulverizers due to needed repairs represented 85,500 lost megawatt hours per year of generation. (Joint Exhibit 31; PI. Exhibit 43, Rosen Rebuttal Report at 12). In a Capital Investment Evaluation prepared on June 24, 1997, Ohio Edison assumed that Unit 6 would suffer a derating of 75 MW for 1140 hours annually. (Pl. Exhibit 1614; PI. Exhibit 43, Rosen Rebuttal Report at 12). The Capital Investment Evaluation also projected an increase in net demonstrated capacity (NDC) of 30 MW as a result of replacing the pulveriz-ers. (PI. Exhibit 1614). J. Activity 10: 1989-1990 Outage— Unit 7 Unit 7 was removed from service for a scheduled turbine outage from October 2, 1989 to January 27, 1990. (Amended Joint Stipulations at ¶ 146). At the time, Unit 7 was seventeen years old with no scheduled retirement date. (Def. Exhibit 1905). During the outage, Ohio Edison replaced economizer tubes at Unit 7 to address frequent tube failures due to fly ash erosion. (Amended Joint Stipulations at ¶ 145; Def. Exhibit 136, Vetterick Report at 47; Def. Exhibit 1500). Ohio Edison also replaced horizontal reheater and reheater riser tubes due to out of service corrosion. (Amended Joint Stipulations at ¶ 147; Def. Exhibit 136, Vetterick Report at 48-49; Def. Exhibit 1084). The capitalized cost of these replacements was approximately $4,103,027.42. (Amended Joint Stipulations at ¶ 148). The total cost of the replacements was $7,859,000.00. (Id.). During the outage, Ohio Edison also replaced front ash hopper tubes at Unit 7 in part because of fireside tube metal wastage, corrosion, fatigue cracking and damage from slag falls. (Id. at ¶ 153; Def. Exhibit 136, Vetterick Report at 49-50; Def. Exhibits 1501 and 1505). The capitalized cost of the replacements was approximately $496,505.39 and the total cost of the replacements was $1,032,095.00. (Amended Joint Stipulations at ¶ 154). During the same outage, Ohio Edison replaced the Westinghouse BB73 low pressure turbine rotors at Unit 7 with new ruggedized rotors due to design defects that led to blade and steeple cracking, high cycle fatigue and excessive vibration. (Amended Joint Stipulations at ¶ 150; Def. Exhibit 1906, Placek Report, at 2-11; Placek Testimony, Tr. Vol. X at 12-17; Pipitone Testimony, Tr. Vol. VI at 85-88; Joint Exhibit 186; Def. Exhibit 1504). The BB73 rotors were manufactured by Westinghouse and had a history of poor performance as a result of significant design problems. (Def. Exhibit 1906, Placek Report at 3-10; Placek Testimony, Tr. Vol. X at 8-10, 14-15; Pipitone Testimony, Tr. Vol. VI at 85-88). Over fifty percent of the Westinghouse BB73 turbine rotors placed in service the coal-fired electric utility industry have been replaced. (Placek Testimony, Tr. Vol. X at 16-17, 33). Nearly seventy percent of the BB73 rotors placed in service in the early 1970s, similar to those at Sammis Unit 7, have been replaced in the industry. (Def. Exhibit 1906, Placek Report at 10; Placek Testimony, Tr. Vol. X at 16 17). The capitalized cost of the replacement of the low pressure turbine rotors was approximately $6,381,006.60. (Amended Joint Stipulations at ¶ 151). The total cost of the replacement was $8,239,738.00. (Id.). According to Ohio Edison, the NDC of Unit 7 never increased as a result of the low-pressure turbine rotor replacement project. (Pipitone Testimony, Tr. Vol. VI at 90; Placek Testimony, Tr. Vol. X at 16-17, 33). Ohio Edison submits that, while Westinghouse stated that its new rugged-ized rotors would permit a 3.5 MW increase in Unit 7’s capacity if more steam could have been supplied to the turbine, Unit 7’s boiler was incapable of supplying more steam to the turbine and therefore the capacity increase was never possible. (Kaiser Testimony, Tr. Vol. X at 87). According to Ohio Edison, the heat rate improved as a result of the project. (Pipitone Testimony, Tr. Vol. VI at 91-92). During the outage, Ohio Edison also replaced burners, coal pipes, pulverizers and combustion controls at Unit 7. The components were replaced to reduce maintenance costs and avoid increased forced outages. The capitalized cost of the replacements was $11.9 million. (Def. Exhibit 1905). The Sammis Boiler Study, July 6, 1989, shows that from 1985 88 there were 45 boiler tube failures caused by the Unit 7 economizer, horizontal reheater and re-heater riser tubes, furnace ash hopper and burners. (Joint Exhibit 226). The study predicted a 100% reduction in failures if the components were replaced. (Id.). Further, the X-176 forms for the replacements show that a prevention of tube failures and/or improved availability in the years immediately following the replacements would be realized. (Def. Exhibit 1340, 1605; PL Exhibit 868, 637; Def. Exhibit 1501,1343). K. Activity 11: 1991 Scheduled Outage — Unit 7 Unit 7 was removed from service for a scheduled boiler outage from August 30, 1991 to October 6, 1991. (Amended Joint Stipulations at ¶ 158). At the time of the outage, Unit 7 was nineteen years old with no scheduled retirement date. (Def. Exhibit 1905). During the outage, Ohio Edison replaced selected waterwall tube panels because of damage from metal waste, overheating, corrosion, fatigue and longitudinal cracking. (Amended Joint Stipulations at ¶ 158; Def. Exhibit 136, Vetterick Report at 50-51; Joint Exhibit 416). According to Ohio Edison, the waterwall tube panels are frequently replaced in the coal-fired electric utility industry. (Def. Exhibit 136, Vetterick Report at 50-51; Krause Testimony, Tr. Vol. VII at 9-15; Koppe Testimony, Tr. Vol. IV at 199-201). The purpose of the project was to reduce maintenance costs and decrease the forced outage rate. The waterwalls were not inoperable at the time of replacement; rather, Ohio Edison determined that it was more cost-effective to replace rather than to repair the tubes. (Krause Testimony, Tr. Vol. VI at 200-02; Pipitone Testimony, Tr. Vol. VI at 97-101). The capitalized cost of the replacement was approximately $446,259.00, in 1992 dollars. (Def. Exhibit 1905). The X-176 form for the replacement of the Unit 7 waterwall tubes shows that a prevention of tube failures and associated improved availability would result in the years immediately following the replacement. (PI. Exhibit 529). III. ANALYSIS OF LAW I. The Clean Air Act The Clean Air Act was enacted “to protect and enhance the quality of the Nation’s air resources so as to promote the public health and welfare and the productive capacity of its population.” 42 U.S.C. § 7401(b). The basic provisions of the Clean Air Act, including the requirements for the EPA to establish National Ambient Air Quality Standards [“NAAQS”] and for the states to develop plans for attaining those standards through State Implementation Plans [“SIPs”], were enacted in 1970. At the same time, Congress created the New Source Performance Standards [“NSPS”] program to ensure that increased pollution from the construction of new and modified emissions sources would be controlled. NSPS standards require major stationary sources of air pollution to install pollution controls based on state of the art technology, taking into account the cost of achieving such reduction and any nonair quality health and environmental impact. 42 U.S.C. § 7411(a)(1). The Clean Air Act defines “new source” as “any stationary source, the construction or modification of which is commenced after the publication of regulations (or, if earlier, proposed regulations) prescribing a standard of performance under this section which will be applicable to such source.” 42 U.S.C. § 7411(a)(2). A “stationary source” is “any building, structure, facility, or installation which emits or may emit any air pollutant.” § 7411(a)(3). The term “modification” is defined as “any physical change in, or change in the method of operation of, a stationary source which increases the amount of any air pollutant emitted by such source or which results in the emission of any air pollutant not previously emitted.” 42 U.S.C. § 7411(a)(4). Consequently, a plant constructed before the Clean Air Act and its implementing regulations is not covered by the New Source pollution standards unless, after such date, it undergoes a modification. In 1977, the CAA was amended to include two additional source programs, the Prevention of Significant Deterioration [“PSD”] and the Non-Attainment New Source Review Requirements [“NNSR”]. PSD applies to all new emissions capacity in areas meeting NAAQS and NNSR applies to all new emissions capac