Searching over 5,500,000 cases.


searching
Buy This Entire Record For $7.95

Download the entire decision to receive the complete text, official citation,
docket number, dissents and concurrences, and footnotes for this case.

Learn more about what you receive with purchase of this case.

Commonwealth v. Allegheny Energy, Inc.

United States District Court, W.D. Pennsylvania

February 6, 2014

Commonwealth of Pennsylvania, Department of Environmental Protection, State of Connecticut, State of Maryland, State of New Jersey, and State of New York, Plaintiffs,
v.
Allegheny Energy, Inc., Allegheny Energy Service Corp., Allegheny Energy Supply Co., LLC, Monongahela Power Co., The Potomac Edison Co., and West Penn Power Co., Defendants.

FINDINGS OF FACT AND CONCLUSIONS OF LAW

JOY FLOWERS CONTI, Chief District Judge.

This matter is before the court following a bench trial. Plaintiffs Commonwealth of Pennsylvania, Department of Environmental Protection ("Pennsylvania DEP"), and the States of Connecticut, Maryland, New Jersey, and New York (together with Pennsylvania DEP, collectively "plaintiffs") seek relief under (1) Part C of Title I of the Clean Air Act ("CAA"), 42 U.S.C. §§ 7404-7479; (2) the new source performance standards ("NSPS") of the CAA, 42 U.S.C. § 7411; and (3) Title V of the CAA, 42 U.S.C. §§ 7661-7661f. Plaintiffs allege that defendants Allegheny Energy, Inc., Allegheny Energy Service Corporation, Allegheny Energy Supply Company, LLC, Monongahela Power Company, the Potomac Edison Company and West Penn Power Company (collectively "Allegheny" or "defendants") violated the CAA by (1) modifying and operating major emitting facilities without obtaining permits and without abiding by emissions limitations required under the prevention of significant deterioration ("PSD") provisions of the CAA; (2) reconstructing and operating two units at a major emitting facility without limiting emissions as required by the NSPS of the CAA; and (3) operating a major emitting facility without obtaining permits as required by Title V of the CAA.

Plaintiff Pennsylvania DEP also brings claims pursuant to the Pennsylvania Air Pollution Control Act ("APCA"), 35 PA. STAT. §§ 4001-4015 . Pennsylvania DEP alleges that Allegheny: (1) failed to abide by the emissions limitations required by the PSD provisions under Pennsylvania law, 25 PA. CODE §§ 127.81-.83; (2) failed to abide by the emissions limitations in Pennsylvania nonattainment new source review provisions ("nonattainment NSR"), 25 PA. CODE §§ 127.201-.218; (3) failed to abide by the emissions limitations required under the NSPS provision of Pennsylvania law, 25 PA. CODE §§ 122.1-.3; (4) failed to obtain pre-construction approval for its projects, including the use of the best available technology ("BAT") standards for its facilities as required by law, 25 PA. CODE §§ 127.11-.51; and (5) failed to obtain Title V operating permits as required by law, 25 PA. CODE §§ 127.401-.464.

Specifically, the projects at issue are (1) the replacement of the boilers of Units 1 and 2 of the Armstrong Plant located in Washington Township, Armstrong County, Pennsylvania ("Armstrong"); (2) replacement of portions, including but not limited to the secondary superheater outlet headers, the reheater, and the lower slope tube panels, of Units 1, 2, and 3 at the Hatfield's Ferry Plant located in Green County, Pennsylvania ("Hatfield"); and (3) replacement of the lower slope tube panels at Unit 3 of the Mitchell Plant located in Courtney, Washington County, Pennsylvania ("Mitchell"), as they relate to the emission of nitrogen oxides ("NOx").

Plaintiffs seek a permanent injunction and civil penalties. The court must decide four preliminary issues: (1) whether certain trial exhibits are admissible; (2) whether the closure of the plants at issue renders the injunctive relief claims moot; (3) whether plaintiffs established that the statute of limitations should be equitably tolled; and (4) whether the court has jurisdiction over plaintiffs' Title V claims. The court must decide three substantive questions: (1) whether any of the projects violated the PSD provisions of the CAA (counts 1, 7, 15, 17, 19, and 23); (2) whether the Armstrong projects were reconstructions which triggered the NSPS of the CAA (counts 4 and 10); and (3) whether Allegheny violated parallel provisions of Pennsylvania law (counts 2, 3, 5, 6, 8, 9, 11, 12, 16, 18, 20, and 24).[1]

This court has subject-matter jurisdiction over the claims in this case pursuant to 42 U.S.C. § 7604(a) and 28 U.S.C. § 1331. The relief requested is authorized pursuant to 42 U.S.C. § 7604 and 28 U.S.C. §§ 2201 and 2202. Venue lies in the United States District Court for the Western District of Pennsylvania pursuant to 42 U.S.C. § 7604(c) and 28 U.S.C. § 1391(b) and (c) because the plants at issue are located in this district.

This matter was bifurcated between liability and damages. A bench trial on liability was held before Chief Judge Gary L. Lancaster from September 13 through September 23, 2010. Chief Judge Lancaster passed away on April 24, 2013. This matter was then reassigned to the undersigned judge. The parties agreed to stand on the record at the status conference held July 11, 2013. The credibility of all the witnesses that testified was assessed based upon the review of the record.

The court considered the evidence adduced at trial, the law applicable to this case, and the submissions of the parties, including extensive proposed findings of fact and conclusions of law and supplemental briefing on developments that occurred post trial. Set forth below are the court's findings of fact and conclusions of law pursuant to Rule 52(a) of the Federal Rules of Civil Procedure. Because the court finds (1) the PSD claims at Armstrong are moot with respect to injunctive relief and time barred with respect to damages; (2) this court lacks subject-matter jurisdiction over the Title V claims; (3) the projects at Hatfield and Mitchell were routine maintenance, repair, and replacement; and (4) the projects at Armstrong were not reconstructions or otherwise subject to new source regulations; all as described below, the court finds that defendants are not liable to plaintiffs on any claim.

I. Findings of Fact

Set forth below are the court's findings of fact with respect to the parties, the operation of coal-fired power plants, and those facts relevant to the determination whether the projects at issue were "major modifications, " which triggered the PSD requirements, or were "routine maintenance, repair and replacement." 40 C.F.R. § 52.21(b)(2)(i), (iii)( a ). As a result of the findings of fact with respect to whether the projects at issue were "major modifications, " the court does not need to reach the emissions issue and, therefore, makes no findings of fact on that issue. Also set forth below are findings of fact regarding whether plaintiffs' Armstrong projects violated the NSPS of the CAA and facts related to whether the statute of limitations should be equitably tolled.

A. The Parties

1. Defendant Allegheny Energy, Inc., is a public utility holding company that owns the five other corporate defendants in this action: Allegheny Energy Service Corporation; Allegheny Energy Supply Company, Monongahela Power Company, The Potomac Edison Company, and West Penn Power Company. (Joint Stipulations - Liability Phase ¶ 1, ECF No. 430 [hereinafter "JS"].)

2. In September 1997, Allegheny Power System, Inc., changed its name to Allegheny Energy. (Pls.' Proposed Findings of Fact ¶ 2, ECF No. 462 [hereinafter "PPF"]; Defs.' Proposed Findings of Fact App. 1, ¶ 1, ECF No. 470 [hereinafter "DPF"].)

3. At the times in issue, Allegheny Energy, Inc., owned all or substantially all of Allegheny Energy Service Corporation, Allegheny Energy Supply Company, Monongahela Power Company, The Potomac Edison Company, and West Penn Power Company or their corporate predecessors. (PPF ¶ 3; DPF App. 1, ¶ 3.)

4. Each defendant is a "person" as that term is defined in 42 U.S.C. § 7602(e). (JS ¶ 3.)

5. This litigation concerns three coal-fired electricity generating stations operated by Allegheny: Armstrong, Hatfield, and Mitchell. (JS ¶ 4.)

6. Each of those power stations is, and was at the time of the projects at issue in this case, a "major emitting facility, " as that term is defined in 42 U.S.C. § 7479(1); a "major stationary source" as that term is defined in 40 C.F.R. § 52.21(b)(1)(i)( b ) and 25 PA. CODE § 127.83; a "major NOx emitting facility" as that term is defined in 25 PA. CODE § 121.1; and a "major facility" for sulfur dioxide ("SO2"), as that term is defined in 25 PA. CODE § 121.1. (JS ¶ 5.)

7. On or about May 20, 2004, the Attorneys General of New York, Connecticut, and New Jersey and the Chief Counsel of Pennsylvania DEP sent a notice of intent to sue to defendants. (JS ¶ 71.)

8. On or about September 8, 2004, the Attorney General of Maryland sent a notice of intent to sue defendants. (JS ¶ 72.)

9. On or about August 3, 2005, the Attorneys General of New York, Connecticut, Maryland, and New Jersey and the Chief Counsel of Pennsylvania DEP sent a notice of intent to sue to defendants for additional violations under the CAA. Among other things, this notice described the NSPS, BAT, and Title V operating permit claims that plaintiffs assert in this action. (JS ¶ 73.)

10. Each notice was served by certified mail on the U.S. Environmental Protection Agency ("EPA") Administrator, the EPA Regional Administrator for the EPA Region in which the plants are located, the Governor of Pennsylvania, and defendants. (JS ¶ 74.)

11. More than sixty days elapsed between the 2004 notices and the filing of plaintiffs' original complaint in this action, in which plaintiffs' pleaded the claims identified in the 2004 notices. (JS ¶ 75.)

12. More than sixty days elapsed between the 2005 notice and the filing of plaintiffs' first amended complaint in this action, in which plaintiffs' pleaded the additional claims identified in the 2005 notice. (JS ¶ 76.)

B. Coal-Fired Electricity Generating Steam Units

1. Generally

13. A coal-fired power plant burns coal in a boiler to heat water that turns into steam and spins a turbine connected to a generator to produce electricity. (Trial Tr. day 1, 44:1-5, Sept. 13, 2010, ECF No. 436.)

14. As part of this process, the coal is ground to a fine powder in pulverizers. ( Id. at 46:15-19.)

15. Pulverized coal and air are blown into the inside of the boiler's furnace through burners. The air contains oxygen which is necessary for the coal to burn in the boiler. ( Id. at 47:13-18, 48:5-10.)

16. The inside of the boiler furnace walls are known as waterwalls because they are composed of tubes with water flowing through them. The lower slopes of a coal-fired boiler are also part of the waterwalls. (PPF ¶ 32; DPF App. 1, ¶ 32.)

17. The burning coal heats the water in the waterwall tubes surrounding the furnace and it turns into steam. (Trial Tr. day 1, 48:14-21, 49:3-15, ECF No. 436.)

18. A header is a large cylinder which collects steam from the numerous tubes in a component, and sends that steam in a single stream to the next component. ( Id. at 49:8-19.)

19. Water separated in the steam drum returns to the boiler for further heating. ( Id. )

20. A "supercritical" boiler operates at a pressure greater than 3, 200 pounds per square inch. Under this pressure, water and steam are indistinguishable. ( Id. at 56:16-57:8.)

21. A "subcritical" boiler operates at a pressure below 3, 200 pounds per square inch, using a process where steam and water are mixed together, requiring separation in a steam drum. (PPF ¶ 36; DPF App. 1, ¶ 36.)

22. The Armstrong and Mitchell boilers are "subcritical" and the Hatfield boilers are "supercritical." (Trial Tr. day 1, 56:19-57:2, ECF No. 436.)

23. After leaving the waterwalls or steam drum, the steam travels through other tubes, called superheaters, where it is further heated and achieves the temperature and pressure needed to turn the turbine. ( Id. at 49:8-25.)

24. When steam leaves the superheater, the steam turns the high pressure turbine. ( Id. at 49:21-25.)

25. The turbine turns the generator, which converts the mechanical energy of the turbine into electricity. ( Id. at 56:2-8.)

26. After traveling through the high pressure turbine, the steam returns to the boiler and travels through tubes called reheaters, which increase both the temperature and pressure of the steam. ( Id. at 56:2-15.)

27. The reheated steam passes through the low-pressure part of the turbine, after which it is condensed into water and returns to the boiler to repeat the process. ( Id. at 56:2-15.)

28. Before the condensed water flows again into the waterwall tubes, it passes through a component known as the economizer, where it is heated by combustion gases before they pass through pollution controls and the stack. ( Id. at 50:14-23.)

29. Before entering the stack, hot combustion gases also pass through an air heater and heat the incoming air. ( Id. at 50:14-51:10.)

30. Leaving the boiler and passing through pollution controls, if any, combustion gases are discharged into the atmosphere through the stack. ( Id. at 53:9-54:10.)

31. SO2 in the exhaust gases can be reduced by scrubbers, which are also called "flue gas desulfurization units." ( Id. at 54:11-19.)

32. NOx in the combustion gases can be reduced by selective catalytic reduction units. ( Id. at 55:12-56:1.)

33. Another method of reducing NOx emissions is the use of low-NOx burners, which produce fewer oxides in nitrogen when combusting coal than prior generations of burners. ( Id. at 47:19-48:4.)

34. Continuous emission monitors measure the amount of pollutants emitted from the stack on a continuous basis. ( Id. at 55:1-11.)

35. A kilowatt hour is a unit of energy equal to one thousand watts of electricity used for one hour. (Trial Tr. day 4, 17:20-18:9, Sept. 21, 2010, ECF No. 437.)

36. A megawatt hour is a unit of energy equal to one million watts of electricity used for one hour. ( Id. at 17:20-18:9.)

37. A British Thermal Unit ("BTU") is a unit of energy. Approximately 3, 413 BTUs equal one kilowatt hour.

38. The terms "unit rating, " "unit capability, " and "unit capacity" all refer to the maximum amount of electricity, typically expressed in megawatts, that a unit can generate at full power. (Trial Tr. day 3, 10:17-11:2, Sept. 20, 2010, ECF No. 434.)

39. "Heat rate" is a measure of the efficiency of a generating unit and is the amount of heat energy, typically expressed in BTUs, required to generate one kilowatt hour of electricity. ( Id. at 10:6-10:13.)

40. A unit is more efficient (that is, uses less coal to generate the same amount of electricity) when its heat rate is lower. ( Id. at 10:6-10:16.)

41. An electric generating unit is "available" when it is capable of producing electricity if needed. (Trial Tr. day 2, 200:20-201:5, Sept. 14, 2010, ECF No. 433.)

42. A unit is in "reserve shutdown" when it is available to generate electricity, but that electricity is not needed. (Trial Tr. day 5, 198:23-199:6, Sept. 22, 2010, ECF No. 438.)

43. A unit is "unavailable" during a planned shutdown, known as a planned outage. (Trial Tr. day 2, 200:23-25, 203:2-9, ECF No. 433.)

44. Electric generating utility companies schedule planned outages on a regular basis to conduct repairs of equipment. ( Id. at 203:6-9.)

45. A unit is also unavailable during an unplanned shutdown, known as an unplanned or forced outage. ( Id. at 203:10-19.)

46. A forced outage occurs when a sudden problem with the unit renders it unable to generate electricity until the problem is fixed. ( Id. at 203:10-19.)

47. Boiler tube leaks are the most common cause of forced outages. ( Id. at 203:20-25.)

48. A single boiler tube leak can shut down a unit for four days. (PPF ¶ 67; DPF App. 1, ¶ 67.)

49. A "derating" occurs when a unit can operate, but not at its maximum capacity because of an equipment problem. (Trial Tr. day 2, 201:11-17, ECF No. 433.)

50. An electric generating unit consists of thousands of independently operating components that must be kept functioning in order to produce electricity. (Trial Tr. day 6, 28:23-29:6, 180:11-12, Sept. 23, 2010, ECF No. 439.)

51. These thousands of components have differing wear rates, and the failure of almost any of them can cause a forced outage or derating. ( Id. at 180:11-14.)

52. Utility companies, including Allegheny, prefer to schedule repair and replacement work during planned outages, rather than wait for worn components to break and cause a forced outage. (Trial Tr. day 7, 214:12-20, Sept. 27, 2010, ECF No. 448.)

53. Forced outages tend to stress the unit and impose higher costs on the utility company and ratepayers. ( Id. at 211:25-212:23.)

54. A unit's availability factor is the percentage of time in a year that a unit was available to generate electricity if needed because it was not shut down for planned maintenance or forced outages. (PPF ¶ 69; DPF App. 1, ¶ 69.)

55. A unit's equivalent availability factor is a refinement of the availability factor that takes into account the effects of deratings and outages on a unit's availability. (Trial Tr. day 2, 201:11-202:11, ECF No. 433; Trial Tr. day 4, 42:19-22, ECF No. 437.)

56. The utilization factor of a unit is the percentage of time the unit is actually operated when it is available to operate. (Trial Tr. day 4, 42:23-43:1, ECF No. 437.)

57. The capacity factor of a unit measures its rate of use. Capacity factor is the percentage of maximum output that is actually generated in a given time period. ( Id. at 22:19-23:11.)

58. For example, a unit with a 70 percent capacity factor in a year produced 70 percent of the energy, typically expressed in megawatt hours, that it could have generated had it operated at full power for the entire year. ( Id. at 22:19-23:8.)

59. A unit is "baseloaded" when it is operated all or most of the time it is available. (Trial Tr. day 2, 202:12-203:1, ECF No. 433.)

60. The manner in which a utility treats a repair or replacement project for accounting purposes - i.e., when determining whether to classify a project as "maintenance" or "capital" expenditure - is governed by a set of industry-wide accounting rules and guidelines, as set forth by the Federal Energy Regulatory Commission ("FERC"). (Trial Tr. day 8, 46:11-18, Sept. 28, 2010, ECF No. 449.)

61. Under FERC's Uniform System of Accounts for electric generating facilities, Allegheny is required to treat certain component replacements as "capital" projects. ( Id. at 46:11-18.)

62. Typically, Pennsylvania DEP did not require plan approvals for routine boiler tube replacements. (Trial Tr. day 7, 44:18-24, ECF No. 448.)

63. Pennsylvania DEP knew that coal-fired power plant operators were replacing large sections of boiler tubes, but never indicated that component replacements required a PSD permit. (Trial Tr. day 2, 180:20-181:1, ECF No. 433; Trial Tr. day 7, 76:14-15, ECF No. 448.)

64. Pennsylvania DEP did not refuse to issue a single Title V operating permit during the late 1990s and early 2000s on the basis that replacing large sections of boiler tubing or boiler components triggered PSD or nonattainment NSR. (Trial Tr. day 2, 181:15-21, ECF No. 433.)

65. Pennsylvania DEP did not notify Allegheny, prior to 2005, that PSD permits were required for like-kind component replacements. (Trial Tr. day 6, 152:21-153:3, 166:9-18, ECF No. 439.)

66. Only once prior to the start of its nonattainment NSR enforcement initiative in 1999 did the EPA make a formal determination that a power plant component replacement project was a "modification" that triggered federal PSD rules; the project was proposed by Wisconsin Electric Power Company ("WEPCo") to extend the life of its coal-fired Port Washington plant. ( Id. at 35:19-21.)

67. In September 1988, the EPA issued the "Clay Memorandum, " an applicability determination for the WEPCo project. The EPA determined that this project was "unprecedented" and triggered the PSD rules because it was not routine maintenance, repair, or replacement. Memorandum from Don R. Clay, Acting Assistant Adm'r for Air and Radiation to David A. Kee, Dir., Air and Radiation Div., Region V (Sept. 9, 1988) (Def.'s Ex. 1824), at 3-4 [hereinafter "Clay Memorandum"].

68. Plaintiffs' expert Richard Koppe ("Koppe") was not aware of any electric utility, prior to 2000, seeking a PSD permit for component replacements like those at issue here. (Trial Tr. day 2, 146:14-21, ECF No. 433.)

2. Facts Common to All Projects

69. The projects at issue are (1) the replacement of the boilers at Units 1 and 2 at Armstrong; (2) replacement of secondary superheater outlet headers, the reheater, and lower slope tube panels of Units 1, 2, and 3 at Hatfield; and (3) replacement of the lower slope tube panels of Unit 3 at Mitchell as they relate to the emission of NOx.

70. Allegheny replaced the components at issue during planned outages when, consistent with Allegheny's usual maintenance practices, other maintenance activities and repairs to equipment not at issue were performed. (Trial Tr. day 6, 48:12-22, ECF No. 439.)

71. For example, low-NOx burners were installed contemporaneously with the Armstrong and Mitchell projects at issue, as well as during the replacement in 1993 of the Hatfield Unit 2 pendant reheater. (DPF ¶ 26; Pls.' Resp. Ex. A, ¶ 26, ECF No. 480-1.)

72. Allegheny performed the projects at issue to prevent or reduce future problems with some or all of the components at issue. (Trial Tr. day 7, 211:25-213:24, ECF No. 448; Trial Tr. day 3, 28:8-14, ECF No. 434.)

73. The economic evaluations justifying the projects referred to improved future availability and reliability, based upon cost-benefit analyses that compared the future if the projects were not performed versus the future if the projects were performed. (Trial Tr. day 6, 175:5-15, ECF No. 439; DPF ¶ 30; Pls.' Resp. Ex. A, ¶ 30.)

74. Allegheny treated the costs of the projects as "capital" expenditures, in keeping with FERC requirements. (Trial Tr. day 7, 102:11-13, ECF No. 448; DPF ¶ 34; Pls.' Resp. Ex. A, ¶ 34.)

75. Outside contractors performed each of the projects at issue. (Trial Tr. day 8, 49:12-18, ECF No. 449; DPF ¶ 35; Pls.' Resp. Ex. A, ¶ 35.)

76. The eight component replacements at issue consisted primarily of replacement of sections of boiler tubes or headers connected to the tube sections. (Trial Tr. day 7, 127:1-4, ECF No. 448; DPF ¶ 19; Pls.' Resp. Ex. A, ¶ 19.)

77. The new replacement components were of like kind and functionally equivalent to those that were replaced, although they incorporated some design improvements. (Trial Tr. day 7, 124:6-16, 129:2-22, 140:20-141:3, ECF No. 448.)

78. None of the replacements changed the capacity or steaming rates of the units at issue, meaning that the maximum amount of steam and electricity that each unit could generate did not increase after any of the projects. ( Id. at 129:14-22, ECF No. 448; Trial Tr. day 6, 159:3-11, ECF No. 439.)

79. None of the projects at issue caused any of the units to move within Allegheny's system "dispatch order" or increased the extent to which the units were called upon to generate electricity. (Trial Tr. day 5, 159:19-160:10, ECF No. 438.)

C. Hatfield

1. Generally

80. Hatfield is located in Greene County, Pennsylvania. (JS ¶ 16.)

81. Hatfield included three units that generated electricity: Units 1, 2, and 3. Each unit burned coal as its primary fuel. (JS ¶ 17.)

82. Unit 1 went into service in 1969. (JS ¶ 18.)

83. Unit 2 went into service in 1970. (JS ¶ 19.)

84. Unit 3 went into service in 1971. (JS ¶ 20.)

85. Hatfield shut down on October 9, 2013. (Second Notice of Subsequent Developments, ECF No. 516.)

86. Each Hatfield unit was an "electric utility steam generating unit" within the meaning of 40 C.F.R. § 60.2 and 25 PA. CODE § 122.3 (as made federal law by 40 C.F.R. §§ 52.2020-.2062). (JS ¶ 21.)

87. Each Hatfield Unit was baseloaded during the period at issue in this case. (Trial Tr. day 2, 202:22-203:1, ECF No. 433.)

88. At all times relevant to this action, Greene County, Pennsylvania, where Hatfield is located, was in attainment or unclassifiable for both SO2 and NOx. (JS ¶ 22.)

89. Allegheny installed low-NOx burners at Hatfield Unit 1 during an outage that ran from October 2, 1994, through November 23, 1994. (JS ¶ 23.)

90. Allegheny installed low-NOx burners at Hatfield Unit 2 during an outage that ran from September 25, 1993, through December 3, 1993. (JS ¶ 24.)

91. Allegheny installed low-NOx burners at Hatfield Unit 3 during an outage that ran from February 25, 1995, through May 8, 1995. (JS ¶ 25.)

2. Hatfield Unit 1 Lower Slope Project

92. Allegheny began planning the Hatfield Unit 1 lower slope project in 1995, more than two years before performing it. (JS ¶ 26.)

93. Allegheny performed this project during an outage that took place from October 11, 1997, to December 20, 1997. (JS ¶ 27.)

94. The project involved completely replacing the lower slope tubes, seal skirt, and ash hopper in a manner that allowed for design improvements such as thicker tubes and redesigned materials and configuration of the furnace seals to improve their longevity. (JS ¶ 28.)

95. The slope tube panels in each unit are about sixty feet wide. (PPF ¶ 308; DPF App. 1, ¶ 308.)

96. Each new slope panel included 464 tubes, and the slope panel replacement was just one aspect of the projects. (PPF ¶ 309; DPF App. 1, ¶ 309.)

97. The purpose of the Hatfield lower slope replacement project was to improve the reliability and availability of the boiler. (PPF ¶ 311.)

98. The work was performed by outside contractors using materials fabricated by outside contractors. (JS ¶ 29.)

99. The total cost of the project was $5, 918, 077. (JS ¶ 31.)

100. Allegheny treated the cost of the project as a capital expenditure, not a maintenance expense, for accounting purposes. (JS ¶ 32.)

3. Hatfield Unit 1 Secondary Superheater Outlet Header Project

101. Allegheny performed this project during an outage that took place from October 11, 1997, to December 20, 1997. (JS ¶ 33.)

102. Allegheny began planning the project more than two years before performing it. (JS ¶ 34.)

103. The project involved replacing both secondary superheater outlet headers at Hatfield Unit 1 with newly fabricated outlet headers that were an upgraded design made with stronger material. (JS ¶ 35.)

104. The work was performed by outside contractors using material fabricated by outside contractors. (JS ¶ 36.)

105. Each secondary superheater outlet header that was replaced was sixty feet long and weighed 90, 000 pounds. (PPF ¶ 397; DPF App. 1, ¶ 397.)

106. Each header had approximately 100 tubes connected to it. (Trial Tr. day 3, 34:18-35:18, ECF No. 434.)

107. These tubes had to be cut free from the header, and a rigging had to be constructed for each tube to prevent it from falling. (PPF ¶ 399; DPF App. 1, ¶ 399.)

108. The outside contractors made a hole in the roof of the building and used a huge crane to reach over the top of the building to lift the old headers out and install the new ones. (PPF ¶ 400; DPF App. 1, ¶ 400.)

109. Each 90, 000 pound secondary superheater outlet header had to be cut into five pieces to make it easier to lift out. (PPF ¶ 401; DPF App. 1, ¶ 401.)

110. The new secondary superheater outlet headers weighed 40, 000 pounds each, and the crane lifted them through the hole in the roof in two parts. (PPF ¶ 402; DPF App. 1, ¶ 402.)

111. After the new secondary superheater outlet headers were lifted into the boiler, they were rigged in place and the hundreds of tubes were welded to the tube stubs on the new header. (PPF ¶ 403; DPF App. 1, ¶ 403.)

112. The total cost of the project was $2, 513, 016. (JS ¶ 37.)

113. Allegheny treated the cost of the project as a capital expenditure, not a maintenance expense, for accounting purposes. (JS ¶ 38.)

114. Prior to this project, Allegheny had not previously replaced the Hatfield Unit 1 secondary superheater outlet headers. (JS ¶ 39.)

4. Hatfield Unit 2 Reheater Project

115. Allegheny began planning this project at least eighteen months before it was performed. (JS ¶ 40.)

116. Allegheny performed the project during a planned outage from September 25, 1993, to December 3, 1993. (JS ¶ 41.)

117. The work was performed by outside contractors, not Allegheny's own maintenance employees. (JS ¶ 46.)

118. The project involved removing the existing reheater assemblies and crossover tubes and replacing them with newly fabricated assemblies made of a different material that Allegheny anticipated would be more resistant to corrosion. (JS ¶ 42.)

119. The pendant reheater consisted of 125 pendants (assemblies of tubing) suspended from a header near the top of the boiler. (PPF ¶ 369; DPF App. 1, ¶ 369.)

120. Each of the 125 pendants weighed several thousand pounds, contained 700 feet tubing and was approximately 40 feet high and 20 feet long. (PPF ¶ 370; DPF App. 1, ¶ 370.)

121. The total tubing in the pendant reheater was approximately seventeen miles long. (PPF ¶ 371; DPF App. 1, ¶ 371.)

122. Contractors performed 2, 265 individual welds to attach the tubing of the new pendant reheater. (PPF ¶ 372; DPF App. 1, ¶ 372.)

123. Allegheny expected the project to reduce forced outages caused by the reheater. (JS ¶ 43.)

124. The total cost of the project was $5, 692, 777. (JS ¶ 44.)

125. Allegheny treated the cost of the project as a capital expenditure, not a maintenance expense, for accounting purposes. (JS ¶ 45.)

126. Although Allegheny had previously replaced some of the crossover tubes, it had never previously replaced the entire pendent reheater or all the crossover tubes. (JS ¶ 47.)

5. Hatfield Unit 2 Lower Slope Project

127. Allegheny began planning for the Hatfield Unit 2 lower slope project in early 1995. (JS ¶ 48.)

128. Allegheny performed this project during a twelve-week outage from September 3, 1999, to ...


Buy This Entire Record For $7.95

Download the entire decision to receive the complete text, official citation,
docket number, dissents and concurrences, and footnotes for this case.

Learn more about what you receive with purchase of this case.