EX-99.D1 4 l83479aex99-d1.txt EXHIBIT 99D-1 1 Exhibit D-1 UNITED STATES OF AMERICA BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION Ohio Edison Company, ) The Cleveland Electric Illuminating ) Company, The Toledo Edison Company, ) Docket No. EC01- -000 Pennsylvania Power Company, American ) Transmission Systems, Inc. and their ) public utility affiliates ) ) and ) ) Jersey Central Power & Light ) Company, Metropolitan Edison Company, ) Pennsylvania Electric Company ) and their public utility affiliates ) JOINT APPLICATION FOR APPROVAL OF MERGER This Joint Application For Approval Of Merger ("Application") is filed with the Federal Energy Regulatory Commission ("Commission" or "FERC") pursuant to Section 203 of the Federal Power Act ("Act"), 16 U.S.C. ss.824b (1994), Part 33 of the Commission's regulations thereunder, 18 C.F.R. ss.33 (2000), and the Commission's Merger Policy Statement.(1) The lead applicants on one side of the proposed merger ("Merger") are Ohio Edison Company ("OE"), The Cleveland Electric Illuminating Company ("CEI"), The Toledo Edison Company ("TE"), Pennsylvania Power Company ("PP"), American Transmission ------------------ (1) Inquiry Concerning the Commission's Merger Policy Under the Federal Power Act: Policy Statement, Order No. 592, 2 Systems, Inc. ("ATSI"), and their public utility affiliates (hereafter, the "FirstEnergy Companies"(2)), all of whom are wholly-owned direct or indirect subsidiaries of FirstEnergy Corp., an exempt public utility holding company.(3) On the other side of the Merger, the lead applicants are Jersey Central Power & Light Company ("JCP&L"), Metropolitan Edison Company ("MetEd"), and Pennsylvania Electric Company ("Penelec"), and their public utility affiliates (hereafter, the "GPU Companies"), all of whom are wholly-owned direct or indirect subsidiaries of GPU, Inc., a registered public utility holding company.(4) JCP&L, MetEd and Penelec do business, and are sometimes referred to herein in the singular form, as "GPU Energy." The FirstEnergy Companies and GPU Companies are referred to herein as the "Applicants." Under the Merger, GPU, Inc. will be merged with and into FirstEnergy Corp., which will be the surviving corporation. ------------------ (continued...) FERC Stats. and RegsP. 31,044 (1996), RECONSIDERATION DENIED, Order No. 592-A, 79 FERCP. 61,321 (1997). (2) For ease of reference, some or all of the FirstEnergy Companies will sometimes be referred to herein in singular form as "FirstEnergy" or "FirstEnergy Companies." (3) The other public utility affiliate of FirstEnergy Corp. is FirstEnergy Trading Services, Inc. ("FETS"). (4) The other public utility affiliates of GPU, Inc. are York Haven Power Company, and GPU Advanced Resources, Inc. 2 3 Upon closing of the Merger, each of the GPU Companies will become wholly-owned subsidiaries of FirstEnergy Corp; and JCP&L, MetEd and Penelec (each doing business as GPU Energy) will continue to operate as distribution companies in their respective retail service areas as separate subsidiaries, just as OE, CEI, TE and PP, the traditional public utility companies now owned by FirstEnergy Corp., will continue to operate in their respective retail service areas as separate distribution subsidiaries. ATSI also will continue to exist as a wholly-owned, separate transmission company subject to the Commission's jurisdiction. I. REQUEST FOR EXPEDITED CONSIDERATION AND NO HEARING The Applicants request that the Commission issue a final order approving the Merger, without an evidentiary hearing, by March 31, 2001. The Applicants hope to obtain all required regulatory approvals by April 30, 2001 so that the Merger can be closed by the end of the second quarter of 2001. The Merger will create a combination among utilities that provide retail services, including supplier of last resort obligations, in three states that already have mandated retail customer choice: (a) Ohio, which permits retail choice as of January 1, 2001, and (b) Pennsylvania and New Jersey, where retail choice has already commenced under state law. The introduction of retail competition presents significant new 3 4 risks and challenges to the Applicants that were until recently essentially the sole providers of electricity in franchised areas. The Applicants intend to remain in the generation business and to compete for retail sales both within and outside their service areas in the Northeast quadrant of the United States through subsidiaries engaged in competitive electric sales. The Merger is intended in large part to enhance the Applicants' ability to meet these challenges. Prompt approval of the Merger, to ensure that its consummation is not delayed, is therefore justified. In Applicants' view, the Application contains more than sufficient information to allow the Commission to find that the Merger is consistent with the public interest, i.e., that it will have no adverse impact on (i) competition, (ii) ratepayers subject to protection under the Merger Policy Statement, or (iii) federal or state regulation. In addition, the Application contains information on restructuring initiatives the Applicants have recently completed, have underway, or will soon initiate. In the event, however, that the Commission requires additional information, the Applicants will comply with the Commission's requests on an expedited basis. Further, if the Commission cannot approve the Merger as proposed, the Applicants request the Commission to identify specifically any measures or conditions that, if taken or agreed 4 5 to by the Applicants, would render an evidentiary hearing unnecessary. This procedure was employed in OHIO EDISON COMPANY, ET AL., 80 FERC (Paragraph) 61,039 at 61,107-08 (1997). SEE ALSO ALLEGHENY ENERGY, INC., ET AL., 84 FERC (Paragraph) 61,223 at 62,073 (1998). II. OVERVIEW The Merger will combine two directly connected public utility holding company systems. The Merger will not have any adverse competitive effects in the affected states primarily because: (a) of initiatives and commitments the Applicants, who have been for some time industry leaders in the procompetitive restructuring and realignment of generation and transmission assets, have already undertaken or made;(b) the FirstEnergy Companies do not own sufficient capacity to meet their existing peak load requirements and they purchase additional amounts of power to serve those requirements; and (c) GPU Energy is essentially a transmission and distribution system, and will add only 285 MW of installed generation to the approximately 12,500 MW FirstEnergy now owns, and has, since 1998, made access to its transmission facilities available through an approved independent system operator. Further, as to transmission, FirstEnergy (now via ATSI) has maintained full compliance with the Commission's open access policies, as set forth in Order Nos. 888 and 889, as modified 5 6 and clarified on rehearing and affirmed on appeal(5) (hereafter, "FERC Open Access Policy"). Simultaneously, FirstEnergy has been instrumental in the formation of the "Alliance," a transmission organization that aspires to become one of the first Commission-authorized Regional Transmission Organizations (an "RTO") under Order No. 2000 (the "RTO Final Rule").(6) The Commission already has conditionally authorized the Alliance's formation. SEE Orders issued in Docket Nos. EC99-80-000, ER99-3144-000, and subdockets thereof, on December 20, 1999 and May 18, 2000, 89 FERC P. 61,298 and 91 FERC P. 61,152 (hereafter, the "Alliance Orders"). SEE ALSO the September 15, 2000 Compliance Filing of the Alliance in Docket Nos. ER99-3144-004 and EC99-80- ------------------ (5) Promoting Wholesale Competition Through Open Access Non-Discriminatory Transmission Services By Public Utilities; Recovery Of Stranded Costs By Public Utilities And Transmitting Utilities, Order No. 888, FERC Stats. & Regs, (paragraph) 31,036, clarified, 76 FERC (paragraph) 61,009 and 76 FERC (paragraph) 61,347 (1996), on reh'g, Order No. 888-A, FERC Stats. and Regs, (paragraph) 31,048, clarified, 79 FERC (paragraph) 61,182 (1997), on reh'g, Order No. 888-B, 81 FERC (paragraph) 61,248, on reh'g, Order No. 888-C, 82 FERC (paragraph) 61,046 (1998); Open Access Same-Time Information System And Standards Of Conduct, Order No. 889, FERC Stats. & Regs. (paragraph) 31,035, on reh'g, Order No. 889-A, FERC Stats. & Regs. (paragraph) 31,049, on reh'g, Order No. 889-B, 81 FERC (paragraph) 61,253 (1997); AFF'D, TRANSMISSION ACCESS POLICY STUDY GROUP, ET AL. V. FERC, 225 F.3d 667 (D.C. Cir. 2000). (6) Regional Transmission Organizations, Order No. 2000, FERC Stats. and Regs. (paragraph) 31,089 (2000), ORDER ON REH'G, Order No. 2000-A, (March 8, 2000), FERC Stats. and Regs. (paragraph) 31,092 (2000) (codified at 18 C.F.R.ss.35.34(h)). 6 7 004 (not consolidated) (hereafter, the "Alliance Compliance Filing"). GPU Energy likewise has embraced utility restructuring but by a different, albeit complementary, path. On October 12, 1997, GPU Energy announced it would begin to divest its generation assets and thereafter to concentrate on delivering electricity to customers. Since then, GPU Energy has disposed of thousands of megawatts ("MW") of installed capacity and now owns only about 285 MW of installed capacity. Additionally, of course, GPU Energy, in its role as a transmission provider, is in full compliance with FERC Open Access Policy via its participation in PJM Interconnection, L.L.C. ("PJM"). As an independent system operator ("PJM/ISO"), PJM is responsible for the operation and control of the bulk electric power transmission system, including all of GPU Energy's transmission facilities, throughout major portions of five mid-Atlantic states and the District of Columbia. The Applicants fully expect PJM/ISO to become one of the first regional organizations to achieve full compliance with the RTO Final Rule and thereby to become the "PJM/RTO". Indeed, GPU Energy joined with PJM and the other transmission-owning utilities in the PJM/ISO in a filing that sets forth the few enhancements necessary for PJM to satisfy the requirements of the RTO Final Rule. 7 8 Shortly following the Merger's closing, FirstEnergy's public utility system will consist of (a) essentially the same amount of installed generating capacity that FirstEnergy now owns and operates, (b) a new combination of adjoining transmission systems, composed of (i) a western system owned, controlled, and operated by ATSI, which is committed to the Alliance RTO, and (ii) an eastern system, which will remain under the full operational control of PJM/ISO, and (c) utility distribution systems that will provide services to nearly 4.3 million customers in Ohio, Pennsylvania, and New Jersey. FirstEnergy and ATSI recognize that the Alliance RTO has not yet been approved by FERC. To avoid any market power concerns the Commission may have regarding approval of the Merger pending final action on the Alliance RTO filing, the Applicants make the following commitment as a condition of the Commission's prompt approval of the Merger without an evidentiary hearing on market power issues: In the event that the Alliance fails to be approved by the Commission, ATSI commits to file an application for approval to participate in another RTO that complies with the RTO Final Rule. Overall, FirstEnergy and the GPU Companies believe that the Merger is a key strategic step in becoming a premier energy and related services provider in the region where its subsidiaries 8 9 currently operate. The Merger constitutes a natural alliance of companies with adjoining service areas and interconnected transmission systems, which will eliminate duplicative costs, maximize efficiencies and increase management and operational flexibility. III. TESTIMONY AND MITIGATION A. Testimony Anthony J. Alexander, President of FirstEnergy Corp., provides an overview of FirstEnergy, its electric generation transmission and distribution facilities and operations, the Merger, FirstEnergy's transition to retail competition, the Alliance RTO, the effect of the Merger on wholesale rates, and FirstEnergy's willingness to waive its OHIO POWER immunity when FirstEnergy Corp. becomes a registered public utility holding company. Exhibit No. APP-100. Bruce L. Levy, Senior Vice President and Chief Financial Officer of GPU, Inc. describes the corporate structure of GPU, Inc. and its public utility subsidiaries, the recent divestitures of substantially all of GPU, Inc.'s generation assets, the operations of GPU, Inc.'s public utility subsidiaries, and the effect of the Merger on wholesale rates. Exhibit No. APP-200. Rodney Frame of Analysis Group/Economics provides testimony on the competitive effects of the Merger, including a complete 9 10 "Appendix A" screen in conformance with the Merger Policy Statement and relevant Commission precedent. Exhibit Nos. APP-300 through APP-317. B. Mitigation And Commitments For ease of reference, the Applicants enumerate below all mitigation measures and commitments that they offer in the Application in support of its prompt approval without an evidentiary hearing. COMPETITION AND RATES (1) In the event that the Alliance fails to be approved by the Commission, ATSI commits to file an application for approval to participate in another RTO that complies with the RTO Final Rule. Application at 8; Testimony of Anthony J. Alexander, Exhibit No. APP-100 at 10. (2) The Applicants will hold any and all wholesale requirements customers harmless from any Merger-related costs in excess of Merger savings. Application at 29-30. (3) The Applicants will hold any and all transmission customers harmless from any Merger-related costs in excess of Merger savings. ID. (4) The FirstEnergy Companies will not assert native load preference for transmission service into PJM. Exhibit No. APP-100 at 11. 10 11 REGULATION (5) The Applicants waive their OHIO POWER immunity. Application at 31. IV. THE APPLICANTS A. FirstEnergy FirstEnergy Corp. was formed on November 8, 1997 when the merger of OE and Centerior Energy Corporation, which owned CEI and TE, became effective.(7) FirstEnergy Corp. is a diversified energy services holding company headquartered in Akron, Ohio. Its traditional public utility operating companies, i.e., OE, CEI, TE and PP, along with ATSI, comprise the nation's tenth largest investor-owned electric system, serving 2.2 million customers within 13,200 square miles of northern and central Ohio and western Pennsylvania. OE, CEI, TE and PP are all public utilities under the FPA, and they have received authorization to sell power at market-based rates.(8) The FirstEnergy Companies currently own and operate 16 power plants that produce approximately 12,500 megawatts of power. Approximately 30 percent of the FirstEnergy Companies' ------------------ (7) OHIO EDISON COMPANY, ET AL., 81 FERC (Paragraph) 61,110 (1997), REHEARING DENIED, 85 FERC (Paragraph) 61,203 (1998). (8) MEP INVESTMENTS, LLC, 87 FERC (Paragraph) 61,209 (1999) (a basket order). FETS (formerly Market Responsive Energy, Inc.) also has market-based rate authority. SEE CLEVELAND ELECTRIC ILLUMINATING COMPANY, 76 FERC (Paragraph) 61,346 (1996). 11 12 capacity is nuclear, which produces 40 percent of the energy generated by its plants. The FirstEnergy Companies' nuclear generating stations (Beaver Valley, Davis-Besse and Perry) are operated on a consolidated basis by the FirstEnergy Nuclear Operating Company. The FirstEnergy Companies provide wholesale electric capacity, energy, or transmission services to 37 municipal electric systems in Ohio and five boroughs in Pennsylvania; and transmission service to 11 rural electric cooperatives who are members of Buckeye Rural Electric Cooperative, Inc. FirstEnergy Corp. also indirectly owns an interest in gas transport and production facilities. Exhibit No. APP-100 at 5. The FirstEnergy Companies are in the process of increasing the amount of their capacity from approximately 12,500 MW to approximately 13,000 MW by upgrading the Perry Station from 1248 MW to 1265 MW and installing up to 425 MW of capacity at West Lorain. SEE Exhibit No. APP-101. They also plan to add another 340 megawatts of capacity by the end of 2002. On September 1, 2000, the FirstEnergy Companies transferred ownership and operation of their high voltage transmission facilities in Ohio and Pennsylvania to ATSI.(9) ATSI now owns and ------------------- (9) SEE FIRSTENERGY OPERATING COMPANIES AND AMERICAN TRANSMISSION SYSTEMS, INC., 89 FERC (Paragraph) 61,090 (October 27, 1999). Since September 1, 2000, ATSI has owned, operated 12 13 controls a transmission system of 7,100 circuit miles of transmission lines with voltages of 69 kilovolts and higher and 120 transmission substations with 37 interconnections with six other utilities, including its portion of a 345 kilovolt tie line with PJM (Penelec). ATSI provides non-discriminatory open access transmission services under the terms of its OATT, ATSI FERC Electric Tariff, Second Revised Volume No. 1. In Ohio, the FirstEnergy Companies, in accordance with an approved transition-to-retail competition plan, have agreed to (a) freeze their base distribution electric rates through December 31, 2007, and (b) lower their unbundled residential tariff rates during a five-year "market development period" to reflect a five percent reduction in the generation component of such rates. In addition, the FirstEnergy Companies in Ohio have agreed to other procompetitive measures during the market development period, including (a) the release of up to 1,120 MW of generating capacity during the market development period to retail marketers and brokers at a guaranteed price, plus customer generation shopping credits which, coupled with the guaranteed prices for the released capacity, will provide margins for subscribers of the released capacity. In addition, ----------------- (continued...) and controlled the high voltage transmission system 13 14 OE, CEI and TE are at risk for up to $500 million in nonrecovery of transition costs if the emerging retail market in Ohio does not meet the state's targeted effective level of competition, i.e., a 20 percent customer switching rate.(10) SEE Exhibit No. APP-100 at 7-9. As part of this approved transition to retail competition plan, FirstEnergy Corp. will be dividing its current operations in Ohio into separate business units.(11) To the extent this state-directed restructuring requires Commission authorization to implement, the FirstEnergy Companies will make appropriate filings under Sections 203 and 205 of the Federal Power Act in other dockets. FirstEnergy Services ("Services"), another wholly owned subsidiary of FirstEnergy Corp., sells gas at wholesale and electricity at retail.(12) Services is certified to sell ----------------- (continued...) formerly owned by the FirstEnergy Companies. (10) The latter commitment aligns FirstEnergy's financial interests with Ohio's public interest in realizing retail competition. (11) The plan has been approved by the Public Utilities Commission Of Ohio ("PUCO"). IN THE MATTER OF FIRSTENERGY CORP., Case Nos. 99-1212-EL-ETP, et. seq., 2000 Ohio PUC LEXIS 676 (July 19, 2000). (12) FETS is the FirstEnergy subsidiary which currently has authority to sell power at market-based rates. Its proposed merger into Services is pending before the Commission in Docket No. EC01-3-000. Upon approval of 14 15 electricity in retail markets in Delaware, Maryland, New Jersey, Pennsylvania, and Ohio, and following the Merger will be the corporate entity that competes for electric sales in states allowing retail competition. Under a restructuring settlement approved by the Pennsylvania Public Utility Commission ("PPUC") in June 1999, PP's retail customers are protected from an increase in generation rates until January 1, 2006. On that date a five percent generation rate increase will be in effect until January 1, 2007, when the generation rate cap will expire for PP's retail customers. Exhibit No. APP-100 at 8-9. B. FirstEnergy RTO Compliance Plan By letter dated June 13, 2000, the Alliance Companies(13) officially notified the Commission and all parties of record that: The Alliance Companies are eager to establish the Alliance Regional Transmission Organization ("Alliance RTO") in order that the benefits of the Alliance Transco may be brought to the marketplace as soon as ----------------- (continued...) the proposed merger in Docket No. EC01-3-000, Services will be a public utility under the Federal Power Act. (13) The Alliance Companies are American Electric Power Service Corporation (on behalf of its public utility subsidiaries, Appalachian Power Company, Indiana Michigan Power Company, Kentucky Power Company, Kingsport Power Company, Ohio Power Company and Wheeling Power Company), Consumers Energy Company, The Detroit Edison Company, FirstEnergy Corp. (on behalf of ATSI) and Virginia Electric and Power Company. 15 16 possible. The overriding goals of the Alliance Companies are first to enable the independent provision of transmission service to become a viable business that can attract investment and improve transmission systems; and, second to be participating in an operating RTO on or before December 15, 2001. The Applicants are in the process of preparing a further compliance filing and plan to submit the completed filing as soon as feasible. This letter identifies modifications that the Applicants intend to make to their proposal in compliance with the Commission's directives. Thereafter, on September 15, 2000 the original Alliance Companies made the Alliance Compliance Filing. The Alliance Companies believe that their proposed RTO meets all of the minimum RTO characteristics and functions of the RTO Final Rule. The Filing states, however, that the Alliance Companies are continuing to develop proposals that will, in some respects, exceed the minimum standards, such as the development of a market-based approach to congestion management that can be implemented on "Day 1" of the Alliance RTO operations. Thus, the Alliance Companies do not view the Alliance Compliance Filing as being their ultimate compliance filing under the RTO Final Rule; such filing will be made on or before January 15, 2001. Under FirstEnergy's RTO compliance plan, ATSI will become a member of the Alliance RTO.(14) Pending the effective date of ----------------- (14) This Application refers to filings and commitments made by the Alliance in order to explain why the Merger does 16 17 Alliance RTO operations, ATSI will continue to offer nondiscriminatory open access transmission service under the terms and conditions of ATSI's OATT in full compliance with FERC Open Access Policy. Under this approach, the FirstEnergy Companies other than ATSI, i.e., OE, TE, CEI and PP, receive network integration service from ATSI under the same terms and conditions that are available to all other network customers. In view of these circumstances and the RTO commitment included herein (Application at 8), there is no room for any concern that the Merger will create an entity that can exercise transmission market power. C. The GPU Companies GPU, Inc. is, through its subsidiaries, an international provider of energy-related infrastructure and services. Domestically, GPU's three public utility subsidiaries, doing ----------------- (continued...) not present market power issues concerning the combination of generation and transmission assets. However, any potential issues regarding the Alliance's plans to comply with the RTO Final Rule should be considered in the dockets established for Alliance-specific issues. Accordingly, this proceeding should not be consolidated with the Alliance proceedings in Docket Nos. ER99-3144, EC99-80, and sub-dockets thereof. SEE COMMONWEALTH EDISON COMPANY, ET AL., 91 FERC (Paragraph) 61,036 at 61,135 (April 12, 2000) ("COMMONWEALTH EDISON") (Commission need not address motion to consolidate merger proceeding with proceeding involving proposal to form independent transmission company with existing ISO structure and to achieve compliance with RTO Final Rule). 17 18 business as GPU Energy, serve 2.1 million customers in Pennsylvania and New Jersey. GPU Energy operates now primarily as a transmission and local distribution system. GPU Energy retains only 285 MW of installed capacity (hydroelectric and combustion turbines) and thus is in a net electrical short position (demand generally exceeds supply).(15) Otherwise, it has contracts with non-utility generators and has entered into agreements with other utilities to purchase required capacity and related energy. These agreements include buyback arrangements under which GPU Energy will purchase all of the capacity and energy from (a) the Three Mile Island Unit 1 Nuclear Generating Station through December 31, 2001, and (b) Oyster Creek through March 31, 2003.(16) GPU Energy also has the right to call the capacity (but not the energy) of the Homer City Station (in which Penelec sold its 50 percent interest to a subsidiary of Edison Mission Energy in 1999) through May 31, 2001 and the capacity of the generating stations sold to Sithe Energies and now owned by Reliant Energy through May 31, 2002. GPU Energy's remaining capacity and energy needs will be met by short to intermediate-term ---------------- (15) For background concerning the divestitures, see the testimony of Bruce L. Levy, Exhibit No. APP-200 at 4-5 and decisions cited therein. 18 19 commitments (one month to three years) during times of expected high energy price volatility, and reliance on spot market purchases during other periods. SEE Exhibit No. APP-300 at 9. As to transmission, GPU Energy's system, as explained above, is under the complete operational control of PJM/ISO. Under the PJM Transmission Tariff, PJM/ISO offers pool-wide open access transmission service over the facilities of the transmission owners in PJM. All transmission services are subject to a single, non-pancaked rate based on the costs of the individual utility's transmission system where the point of delivery is located. In general, locational marginal pricing is used for calculating and recovering the costs of transmission congestion. Moreover, it is expected that PJM/ISO will become an RTO in compliance with the RTO Final Rule. The Applicants propose that post-Merger, the GPU Companies will remain in PJM while ATSI will become a part of the Alliance. The Applicants are committed to resolution of inter-RTO seams issues and will work with both organizations to further this objective. Historically, GPU Energy had a number of wholesale requirements (full or partial) customers. As a consequence of ---------------- (continued...) (16) Both of these nuclear power plants are owned by Amergen Energy Company LLC. 19 20 the divestiture program, however, GPU Energy (Penelec), has only two remaining requirements customers, Allegheny Electric Cooperative, Inc. ("Allegheny"), and West Penn Power Company ("West Penn"), that will take service beyond the end of this year. (The Pennsylvania Boroughs of East Conemaugh and Summerhill will terminate their service agreements with GPU Energy as of December 1, 2000.)(17) Allegheny takes service from Penelec under a 1993 Wheeling and Supplemental Power Agreement (WASP Agreement), which could expire as early as 2003. Penelec provides service to West Penn under a 1973 service agreement under Penelec's Tariff No. 1. This service allows West Penn to meet the requirements of approximately four MW of isolated load in Clinton County, Pennsylvania. Both Penelec and MetEd are subject to generation rate caps applicable to their retail customers until December 31, 2010. Both companies also implemented rate decreases for their retail customers on January 1, 1999, 2.5 percent for MetEd customers and 3.0 percent for Penelec customers. Similarly, in New Jersey JCP&L implemented a retail rate reduction on August 1, 1999. The initial annual rate reduction was five percent; but between now and August 1, 2002, the annual reduction increases in steps until it -------------- (17) For more detail on the termination of GPU Energy's cost-based service agreements, see Mr. Levy's testimony, Exhibit No. APP-200 at 7. 20 21 reaches an annual rate of 11 percent, which continues through at least July 31, 2003. GPU, Inc.'s merchant plant businesses own interests in and operate 14 projects in five countries, including the United States. On October 5, 2000, however, Aquila Energy ("Aquila"), a subsidiary of UtiliCorp United, and GPU,Inc., announced the execution of a definitive agreement under which Aquila will purchase all of GPU's merchant plant interests in the United States (six plants in New York, New Jersey, Georgia and Florida, representing about 500 MW of capacity), plus GPU's one-half interest in a 715 MW project under development in Mississippi. GPU, Inc. sells competitive retail energy and related services in the mid-Atlantic region of the United States through its subsidiary, GPU Advanced Resources, Inc. In addition, GPU Electric, an affiliate company of GPU, Inc., develops, owns and operates transmission and distribution facilities outside the United States (but not in Mexico or Canada). V. THE MERGER The Merger will occur in accordance with the Agreement and Plan of Exchange and Merger, dated August 8, 2000 ("Merger Plan") (Exhibit H). Under the Merger Plan, the separate existence of GPU, Inc. will cease, and it will be merged with and into FirstEnergy Corp. with the latter continuing as the surviving corporation. Each GPU shareholder (unless he or she 21 22 has dissented) will have the opportunity to elect to receive cash for all of his or her GPU shares, FirstEnergy shares for all of his or her GPU shares, or cash for a portion, and FirstEnergy shares for the rest, of his or her GPU shares.(18) Shortly after all required regulatory authorizations are received, the Merger will become effective upon the filings of articles of merger by GPU, Inc. with the Department of State of the Commonwealth of Pennsylvania, and a certificate of merger by FirstEnergy Corp. with the Secretary of State of the State of Ohio. Corporate headquarters will be in Akron, Ohio. FirstEnergy Corp. will maintain offices and presence in Morristown, New Jersey and Reading, Pennsylvania, subject to the authority of the Board of Directors. If the Merger were completed today, FirstEnergy would be the sixth largest investor-owned electric utility system in the U.S. based on customers served. With assets of approximately $40 billion, a domestic customer base of 4.3 million, and a __________________ (18) Under the Merger Plan, however, unless an adjustment is made as a result of tax considerations, 50 percent of all issued and outstanding shares of GPU common stock must be exchanged for cash and 50 percent must be exchanged for FirstEnergy common stock. The elections of GPU shareholders to receive cash or FirstEnergy common stock are subject to proration because of this provision and also because of a possible adjustment controlled by tax considerations. 22 23 service area of 37,200 square miles, FirstEnergy will be one of the nation's largest electric utility systems with more resources and opportunities to provide high quality services to customers. VI. MERGER ANALYSIS A. Standard Of Review The Merger is subject to approval under Section 203 of the FPA, which provides: No public utility shall sell, lease, or otherwise dispose of the whole of its facilities subject to the jurisdiction of the Commission, or any part thereof of a value in excess of $50,000, or by any means whatsoever, directly or indirectly, merge or consolidate such facilities or any part thereof with those of any other person, or purchase, acquire, or take any security of any other public utility, without first having secured an order of the Commission authorizing it to do so. 16 U.S.C.ss.824b(a) (1994). The Commission's approval of a merger under Section 203 requires a finding that the proposed merger will be "consistent with the public interest." ID.; COMMONWEALTH EDISON, SUPRA. Under the Merger Policy Statement, the Commission determines whether a proposed merger is consistent with the public interest by considering its effect on (1) competition, (2) rates, and (3) regulation. The Commission should approve the Merger on the basis of this test. 23 24 B. Effect On Competition The Applicants requested Mr. Frame to perform quantitative and qualitative studies of the Merger's effect on competition, including a delivered price screen analysis described in Appendix A to the Merger Policy Statement. If the screen analysis is passed, or if any failures are adequately mitigated, there is generally no need for further analysis. Merger Policy Statement at 30,119-120. Mr. Frame's Appendix A analysis focuses on the market for electric energy, specifically non-firm energy, with particular emphasis on the Economic Capacity measure.(19) Mr. Frame analyzes the relevant product markets in 11 time periods in 12 destination markets. Exhibit No. APP-300 at 7. He concludes that the Merger will not adversely affect competition in any relevant market, nor will it enable the Applicants to raise prices above non-merger levels. Exhibit No. APP-300 at 11-15. For Economic Capacity, in virtually all cases the Merger induced HHI increases fall below the threshold levels included in Appendix A. The only exceptions involve the FirstEnergy and Duquesne Light Company (DQE) destination market where the HHI _______________________ (19) Mr. Frame determines that no barriers exist to entry for long-term firm capacity and, therefore, did not consider that product as a relevant product market in his analysis. SEE ATLANTIC CITY ELECTRIC CO. AND DELMARVA POWER & LIGHT CO., 80 FERC (Paragraph) 61,126 at 61,405 (1997). 24 25 increases in the off-peak periods exceed the Merger Guidelines' screening threshold for all three seasons. However, Mr. Frame concludes that these limited threshold violations do not represent a real market power concern arising from the Merger. The reasons include the difficulty in exercising market power during off-peak hours through the withholding of capacity when such a high percentage of the capacity operating then consists of baseload units (nuclear units and the minimum operating levels for baseload coal units) that cannot be easily or economically withheld. Moreover, the predominant direction of energy flow between the East Central Area Reliability Coordination Agreement(ECAR) region (where FirstEnergy and DQE are located) and the PJM region (where GPU's generating assets are located) is west to east, that is from FirstEnergy and other ECAR suppliers into PJM. When the flows into PJM reach their limits, prices in PJM will rise above prices in areas to the east. GPU's incentive is to seek to get the highest price for the energy it sells and, therefore, it will sell its energy into PJM where the prices are higher, and not in ECAR to the west where the prices are lower. Thus, while the screening analysis might indicate that some of GPU Energy's resources could be competitive in the FirstEnergy and DQE destination markets, it is relatively rare for energy 25 26 actually to flow in the east to west direction that would allow this. Mr. Frame also concludes that there are no HHI changes resulting from the Merger when Available Economic Capacity is analyzed. Since GPU has divested virtually all of its generation, it has no Available Economic Capacity at any price level. Its combination with FirstEnergy therefore cannot possibly increase concentration of Available Economic Capacity in any destination market. In addition to these base case analyses, Mr. Frame analyzes several alternative scenarios in which he assumes different transmission prices (including those where proposed regional transmission tariffs are assumed to be in place), transmission capacities, and market clearing prices. These scenarios collectively bound a range of expectations about future market structure and conditions. The results from these sensitivities reinforce Mr. Frame's conclusion derived from the base case, which is that the Merger does not suggest realistic concerns about the potential exercise of horizontal market power. Mr. Frame also includes a sensitivity analysis that assumes FirstEnergy may send 650 MW of energy into PJM during off-peak hours to help GPU Energy meet its energy supply obligations to retail customers in its service territory. As part of this scenario, Mr. Frame assumes that FirstEnergy acquires the 26 27 transmission capacity necessary to implement the energy transfer and that transmission capability available to others is concomitantly reduced. The HHI changes in these sensitivities contain the same limited, and inconsequential, screen violations as the base case, but no additional ones. In fact, in the sensitivity analysis where the 650 MW of energy is shipped from FirstEnergy to PJM post-merger in off-peak hours, one effect is to reduce the HHIs in the FirstEnergy destination market during off-peak periods and, therefore, the minor base case screen threshold violations are eliminated. It is also important to understand that an Appendix A-type screen analysis will not capture the pro-competitive effects of retail customer choice and the various restructuring initiatives that have been implemented in Pennsylvania and New Jersey and that will begin on January 1, 2001 in Ohio. These initiatives include the commitment to achieve timely compliance with the RTO Final Rule. C. Effect On Rates Under the Merger Policy Statement, the Commission evaluates whether a proposed merger will result in an increase in the merging utilities' cost-based power or transmission rates.(20) __________________________ (20) Although Applicants and their affiliates have market-based rate authority, the Commission has made clear that 27 28 Merger Policy Statement at 30,123-124. In this case, the Merger will not affect any cost-based rates. GPU Energy's only remaining cost-based requirements service arrangements are with West Penn, and with Allegheny under the WASP Agreement which is at issue in Docket No. EL00-88-000. ALLEGHENY ELECTRIC COOPERATIVE, INC. V. PENNSYLVANIA ELECTRIC COMPANY, 92 FERC (Paragraph) 61,206 (September 14, 2000). Approval of the Merger should not be delayed by Allegheny's rate issues with Penelec. Allegheny and West Penn already have declined to terminate their wholesale purchase agreements on four separate occasions when the opportunity to do so was offered in an "open season" associated with Penelec's applications (all granted) for approval of its divestiture transactions; in each case, Allegheny and West Penn were assured that they would not be responsible for any stranded costs if they took advantage of the opportunity to terminate their agreements. Further, Allegheny's rate disputes with Penelec in Docket No. EL00-88-000 are not related to the Merger and should not be introduced into this proceeding. Otherwise, GPU Energy's only cost-based "rates" (GPU Energy is allocated a portion of the revenues collected under the PJM ________________________ (continued...) its ratepayer protection concerns do not apply to customers paying market-based rates. ENRON CORP, ET AL., 78 FERC (Paragraph) 61,179 (1997). 28 29 OATT) are for the transmission services it provides under the PJM OATT.(21) FirstEnergy sells small amounts of wholesale capacity and energy under cost-based rates to certain municipal electric systems in Ohio, and one borough in Pennsylvania.(22) The terms of FirstEnergy's existing sales arrangements ensure that the customers will not be adversely affected by the Merger. ATSI provides open access transmission services under its OATT at cost-based rates. Because ATSI does not own or control generation, it will initially satisfy its ancillary service requirements with power purchased from FirstEnergy under FirstEnergy's Ancillary Services Tariff (FERC Electric Tariff, Original Volume No. 3) at cost-based rates.(23) The ATSI OATT requires ATSI to pass through the costs of this power to its customers without mark-up. To ensure that there will be no legitimate ratepayer protection concerns, the Applicants, including ATSI, hereby commit that they will hold harmless from all Merger-related costs in excess of Merger-related savings all of their wholesale ____________________ (21) SEE footnote 17 above. (22) FirstEnergy sells imbalance energy to four boroughs in Pennsylvania who receive transmission services from ATSI. (23) FirstEnergy's Tariff and service agreement with ATSI were filed on October 3, 2000 in Docket No. ER00-3771-000 with 29 30 customers, including Allegheny, who purchase either (a) requirements service at cost-based rates, or (b) transmission and ancillary services at cost-based rates. See Mr. Alexander's testimony (Exhibit No. APP-100 at 14-16) and Mr. Levy's testimony (Exhibit No. APP-200 at 10-11). D. Non-Discriminatory Transmission The Applicants realize that under certain circumstances, the Commission has required merger applicants to file a single-system open access transmission tariff ("OATT") for non-discriminatory transmission access over the merged transmission system. However, as indicated above, ATSI, FirstEnergy's wholly-owned transmission company, plans to transfer control of its transmission facilities to the Alliance, and GPU Energy's transmission system will remain under the operational control of the PJM/ISO. The Alliance, furthermore, plans to become an RTO that will achieve full compliance with the RTO Final Rule no later than the first day of the Rule's effectiveness; likewise, PJM/ISO plans to achieve full compliance with the RTO Final Rule no later than the first day of the Rule's effectiveness. Accordingly, the Applicants are not required to file a single-system OATT. COMMONWEALTH EDISON, 91 FERC (Paragraph) 61,036 (April 12, _____________________ (continued...) a requested effective date of September 1, 2000, the date ATSI commenced operations. 30 31 2000); and ENERGY EAST CORPORATION, ET AL., 91 FERC (Paragraph) 61,001 (April 3, 2000). E. Effect On Regulation In order to avoid a hearing on the effects of a merger on regulation, the Applicants must demonstrate that the Merger will not affect federal and state regulation of the Applicants. Merger Policy Statement at 30,125. FirstEnergy Corp. intends to register as a holding company under the Public Utility Holding Company Act of 1935 ("PUHCA"). The Applicants, accordingly, will waive OHIO POWER immunity from Commission regulation of non-power affiliate sales.(24) Exhibit No. APP-100 at 13-14. Further, the Merger will not adversely affect state regulation. FirstEnergy (OE, CEI, TE, and PP), and GPU Energy (JCP&L, MetEd and Penelec) will remain subject to effective state regulation following the Merger's closing. VII. AFFILIATED SALES Consistent with Commission policy, FirstEnergy commits not to sell power to GPU Energy, and vice versa, unless the Commission authorizes such sales. Further, the public utility affiliates of these companies will not sell non-power goods and services to each other except under conditions the Commission ___________________ (24) Merger Policy Statement at 30,124-125; OHIO POWER CO. V. FERC, 954 F.2d 779, 782-86 (D.C. Cir.), CERT. DENIED, 506 U.S. 981 (1992). 31 32 imposes on similar transactions between utilities and their affiliated power marketers. VIII. ACCOUNTING In the Merger Policy Statement, the Commission stated that it would no longer consider the proposed accounting treatment as a separate factor but instead ruled that "proper accounting treatment is simply a requirement for all mergers." Merger Policy Statement at 30,126. The Merger will be accounted for under the purchase method in accordance with generally accepted accounting principles. Exhibit No. APP-100 at 9-10. IX. ATTACHMENTS, STANDARDS OF CONDUCT, AND CONFIDENTIAL TREATMENT A. Application The following information is included in the Application: - Direct Testimony of Anthony J. Alexander (Exhibit No. APP-100) and associated exhibits; - Direct Testimony of Bruce L. Levy (Exhibit No. APP-200); - Direct Testimony of Rodney Frame (Exhibit No. APP-300) and associated exhibits; Also attached are the Exhibits A through I as required by Section 33.3 of the Commission's regulations. To the extent necessary, the Applicants request waiver of the Commission's 32 33 regulations to permit acceptance of the attached Exhibits in the form filed. B. Standards Of Conduct The Applicants hereby commit that, effective as of the date of this filing, they will, for purposes of FERC Open Access Policy, treat each other as if they were already affiliated companies. Therefore, ATSI's transmission function personnel will treat GPU Energy's merchant function personnel in the same manner that ATSI's transmission function personnel treat FirstEnergy's merchant function personnel. GPU Energy's transmission function personnel will treat FirstEnergy's merchant function personnel in the same manner that GPU Energy's transmission function personnel treat GPU Energy's merchant function personnel. Upon consummation of the Merger, Applicants will file a combined Standards of Conduct in conformance with FERC Open Access Policy. C. Confidential Treatment The computer model underlying Mr. Frame's study is being submitted on a confidential basis pursuant to 18 C.F.R. section 388.112 (2000). The model is proprietary to Analysis Group/Economics and was developed at great cost to Analysis Group/Economics. The disclosure of the model to the public without limit will adversely impact Analysis Group/Economics. One copy of the model is included with the original copy of the Application in a 33 34 sealed envelope. All other copies of the Application contain a statement that the information has been removed. However, parties may obtain a copy of Mr. Frame's model after executing a Confidentiality Agreement. Arrangements for a copy of the model must be made by contacting Rodney Frame at Analysis Group/Economics at telephone number (202) 785-6300.(25) X. INFORMATION REQUIRED BY SECTION 33.2 OF THE COMMISSION'S REGULATIONS A. Names and Addresses of Principal Business Offices First Energy Corp. GPU, Inc. 76 South Main Street, 300 Madison Avenue Akron, Ohio 443078 P.O. Box 1957 Morristown, New Jersey 07963 Names And Addresses Of Persons Authorized To Receive Notices And Communications With Respect To The Application Robert S. Waters Michael R. Beiting Jones, Day, Reavis & Pogue Associate General Counsel 51 Louisiana Avenue, N.W. FirstEnergy Corp. Washington, D.C. 20001 76 South Main Street Akron, Ohio 44308 Kenneth G. Jaffe Richard P. Sparling Swidler, Berlin, Shereff Friedman, LLP. 3000 K Street, N.W. Suite 300 Washington, D.C. 20007-5116 _______________________ (25) Pursuant to 18 C.F.R.ss.388.112(b)(iv), inquiries regarding this request should be directed to Robert S. Waters; Jones, Day, Reavis & Pogue; 51 Louisiana Avenue, N.W.; Washington, D.C. 20001; phone (202) 879-3687; fax (202) 626-1700. 34 35 B. Designation of Territories Served, by Counties And States The FirstEnergy Companies provide electric service in northern Ohio and western Pennsylvania, in all or portions of the following counties: THE CLEVELAND ELECTRIC ILLUMINATING COMPANY (OHIO) Ashtabula Lorain Cuyahoga Medina Geauga Trumbull Lake OHIO EDISON COMPANY (OHIO) Ashland Madison Ashtabula Mahoning Carroll Marion Champaign Medina Clark Morrow Columbiana Ottawa Crawford Portage Cuyahoga Richland Delaware Sandusky Erie Seneca Fayette Stark Franklin Summit Geauga Trumbull Greene Tuscarawas Holmes Union Huron Wayne Knox Wyandot Lorain PENNSYLVANIA POWER COMPANY (PENNSYLVANIA) Allegheny Crawford Beaver Lawrence Butler Mercer 35 36 THE TOLEDO EDISON COMPANY (OHIO) Defiance Putnam Fulton Sandusky Henry Seneca Lucas Williams Ottawa Wood FirstEnergy also has affiliates engaged in unregulated sales of natural gas and electricity in Delaware, Illinois, Indiana, Kentucky, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Texas, Virginia, and West Virginia. As for GPU Energy, JCP&L provides retail service in northern, western and east central New Jersey, having an estimated population of approximately 2.5 million. MetEd provides retail electric service in all or portions of fourteen counties, in eastern and south central Pennsylvania, having a population of approximately 1 million. Penelec provides retail and wholesale electric service within a territory located in western, northern and south central Pennsylvania extending from the Maryland state line northerly to the New York state line, with a population of approximately 1.5 million. Penelec, as lessee of the property of the Waverly Electric Light & Power Company, also serves a population of approximately 13,700 in Waverly, New York and vicinity. 36 37 C. Description Of Facilities Owned Or Operated For Transmission Of Electric Energy Or The Sale Of Electric Energy At Wholesale In Interstate Commerce As of December 31, 1999, the FirstEnergy Companies owned approximately 7,100 circuit miles of high voltage transmission lines that are 69 kV and above. As of December 31, 1999, JCP&L owned approximately 2,047 circuit miles of transmission lines, MetEd owned approximately 1,236 circuit miles of transmission lines and Penelec owned approximately 2,739 circuit miles of transmission lines. See Section IV of this Application for a description of the Applicants' generation facilities. D. Description Of Transaction And Statement As To Consideration The Merger is described in Section V of this Application. The consideration for the Merger is inherent in the exchange of shares (or receipt of cash in whole or part by shareholders of GPU, Inc.) at closing, as negotiated at arms-length between the parties and as described in the Merger Plan. Exhibit H. The terms of the Merger have been approved by the Boards of Directors. The Applicants were assisted by their own outside investment bankers in the negotiation process. The Merger is voluntary and must be approved by voting shareholders. E. Description Of Facilities Involved In The Transaction The jurisdictional facilities of the Applicants are described herein. 37 38 F. Statement Of The Cost Of The Facilities Involved In The Transaction See Exhibit C. G. Statement As To The Effect Of The Merger Upon Contracts For The Purchase, Sale, Or Interchange Of Electric Energy The Merger will not have a material impact on any contract for the purchase, sale, or interchange of electric energy. The Applicants' commitment to ratepayers is described in Section VI.C of this Application. H. Statement Of Other Federal And State Regulatory Requirements FirstEnergy Corp. is currently a holding company exempt from most provisions of PUHCA. GPU, Inc. is a registered holding company under PUHCA but will cease to exist upon the Merger's closing. FirstEnergy Corp. is required to obtain approval from the Securities and Exchange Commission ("SEC") under Section 9(a)(2) of the PUHCA in connection with the Merger. Section 9(a)(2) of the PUHCA provides that it is unlawful for any person to acquire any security of any public utility company if that person owned, or by virtue of that transaction will come to own, five percent or more of the voting securities of the public utility company and of any other public utility company, without the prior approval of the SEC. An application for approval of the Merger under PUHCA will be filed by FirstEnergy Corp. 38 39 FirstEnergy Corp. will be required to be registered under Section 5 of PUHCA when the Merger is completed. At that time, FirstEnergy Corp. will become subject to the restrictions that PUHCA imposes on registered holding company systems. FirstEnergy Corp. believes that the approval of the Merger by the PUCO is not required. However, under the law of the Commonwealth of Pennsylvania, any public utility must obtain a certificate of public convenience from the PPUC before it (or any affiliate) may acquire from, or transfer to, another entity the title to, or the possession or use of, any property used or useful in the public service. In addition, under the PPUC's policy, a merger that results in the change in control of an existing Pennsylvania public utility (which includes a change in the controlling interest of the utility's parent) requires the issuance of a certificate of public convenience by the PPUC. Additionally, the transfer of the ownership or control of GPU, Inc., as the parent company of JCP&L, and various related matters, are subject to the jurisdiction of the New Jersey Board Of Public Utilities ("BPU"). Pursuant to the law of New Jersey, no person may acquire or seek to acquire control of a public utility directly or indirectly through the medium of an affiliated or parent corporation without first requesting and receiving approval of the BPU. 39 40 OE and PP each holds a license under the Atomic Energy Act ("NRC license") from the Nuclear Regulatory Commission ("NRC") authorizing them to hold ownership or leasehold interests in the Beaver Valley Unit 1 Nuclear Unit and (along with OES Nuclear Inc., which is a wholly-owned subsidiary of OE) the Perry Unit 1 Nuclear Unit. OE also holds an NRC license authorizing it to hold an ownership or a leasehold interest in Beaver Valley Unit 2. Each of CEI and TE holds an NRC license authorizing them to hold ownership or leasehold interests in Perry Unit 1, Beaver Valley Unit 2 and the David-Besse Nuclear Units. The Davis-Besse facility also includes a generally licensed independent spent fuel storage installation. FirstEnergy Nuclear Operating Company holds NRC licenses authorizing it to operate these FirstEnergy nuclear power plants. GPU Nuclear, Inc. ("GPU Nuclear"), MetEd, JCP&L and Penelec each holds an NRC license authorizing it to possess TMI-2. The Saxton Nuclear Experimental Corporation, also an indirect, wholly-owned subsidiary of GPU, Inc. is licensed to possess the Saxton Nuclear Facility, and GPU Nuclear is licensed to possess, manage, use and maintain such facility. On September 14, 2000, FirstEnergy formally informed the NRC, in a docketed filing, that completion of the Merger will not result in a direct or indirect transfer of control of the operating licenses for Perry Nuclear Power Plant, the Davis- 40 41 Besse Nuclear Power Station and the Beaver Valley Power Station Units 1 and 2. The Merger will result in an indirect transfer of control over the possession-only licenses for the two plants owned by GPU and its subsidiaries, i.e., TMI-2, which is being decommissioned, and the Saxton Nuclear Facility. On September 26, 2000, GPU Nuclear and FirstEnergy Corp. requested NRC consent to the indirect transfer of control of the possession-only licenses for TMI-2 and Saxton. The Hart-Scott-Rodino Antitrust Improvements Act ("HSR Act") and the rules and regulations thereunder provide that certain transactions (including the Merger) may not be consummated until certain information has been submitted to the Department of Justice ("DOJ") and the Federal Trade Commission ("FTC") and the specified HSR Act waiting period requirements have been satisfied. The expiration or termination of the HSR Act waiting period would not preclude the DOJ or the FTC from challenging the Merger on antitrust grounds. If the Merger is not consummated within twelve months after the expiration or termination of the HSR Act waiting period, new pre-merger notifications would need to be submitted to the DOJ and the FTC and a new HSR Act waiting period would have to expire or be terminated before the Merger could be consummated. FirstEnergy Corp. and GPU, Inc. will comply with the provisions of the HSR Act. 41 42 Finally, the Federal Communications Commission must approve the transfer of certain licenses from GPU entities to FirstEnergy Corp. I. Facts Showing That The Merger Is Consistent With The Public Interest The facts relied upon to show that the Merger is consistent with the public interest are set forth in this Application. The Merger will not adversely affect competition, rates or regulation. The Merger will enhance competition and the ability of the Applicants to promote further competitive developments. The Applicants have implemented or are about to implement pro-competitive retail access and restructuring in their respective states. Likewise, they support the Commission's independent transmission system initiatives, and the Applicants will continue to provide leadership in the development of the Alliance RTO and the enhancement of PJM in compliance with the RTO Final Rule, and other competition enhancing initiatives while this Application is under review and after the Merger is closed. The Merger will combine two public utility systems with compatible business and strategic goals into a financially stronger energy system better suited to operate in the evolving energy markets. The combined system will have the resources, experience and talent to provide its customers with high quality 42 43 and cost-efficient services, all subject to regulation intended to protect the public interest. J. Brief Statement Of Franchises Held See Attachment 1 to this Application. K. Form Of Notice The Application includes a form of notice, in both hard copy and on diskette, suitable for publication in the Federal Register. XI. CONCLUSION For the reasons set forth herein, including the accompanying testimony and exhibits, the Applicants request that on or before March 31, 2001 the Commission: 1. find that the Merger will not have an adverse effect on competition, rates or regulation, that it is consistent with the public interest, and that the Application satisfies all requirements for authorization of the Merger under Section 203 of the FPA and Part 33 of the Commission's regulations; 2. approve the Merger and grant any and all other authorizations or approvals incidental thereto that may be required; 3. issue such approvals and related authorizations without an evidentiary hearing based on the information set forth in this Application and 43 44 accompanying exhibits; or indicate any conditions that, if agreeable to the Applicants, would result in conditional approval of the Merger without an evidentiary hearing; and 4. waive any filing requirements or other regulations as the Commission may find necessary or appropriate to allow this Application to be accepted for filing and granted. Respectfully submitted, THE FIRSTENERGY COMPANIES THE GPU COMPANIES By: /s/ Robert S. Waters --------------------------------- Leila L. Vespoli Vice President and General Counsel Michael R. Beiting Associate General Counsel FirstEnergy Corp. 76 South Main Street Akron, Ohio 44308 330-384-5795 - voice 330-384-3875 - fax 44 45 By: /s/ Robert S. Waters --------------------------------- Paul T. Ruxin Robert S. Waters Jones, Day Reavis & Pogue 51 Louisiana Avenue, N.W. Washington, D.C. 20001 202-879-3939 - voice 202-626-1700 - fax By: /s/ Robert S. Waters --------------------------------- Ira H. Jolles GPU, Inc. 300 Madison Avenue P.O. Box 1957 Morristown, New Jersey 07963 206-389-4276 - voice 206-447-0849 - fax By: /s/ Robert S. Waters --------------------------------- Kenneth G. Jaffe Richard P. Sparling Swidler, Berlin, Shereff, Friedman, LLP 3000 K Street, N.W. Suite 300 Washington, D.C. 20007-5116 202-424-7563 - voice 202-424-7643 - fax Dated: November 9, 2000 45 46 Attachment 1 Brief Statement of Franchises Held and Dates of Expiration, if Not Perpetual Operating Company Municipality Franchise Expiration PENN POWER Clark Perpetual Bessemer Perpetual Bradford Woods 2010 Callery Perpetual Conneaut Lake 2007 Connoquenessing Perpetual Ellwood City Perpetual Enon Valley Perpetual Evans City 2015 Fredonia Perpetual Harmony 2035 Homewood Perpetual Jackson Center Perpetual Jamestown Perpetual Koppel 2020 Mars Perpetual Mercer Perpetual New Castle Perpetual New Galilee 2003 New Lebanon Perpetual New Wilmington 2016 Salem 2021 Sandy Lake Perpetual Sharon Perpetual Sharpsville Perpetual Sheakleyville Perpetual SNPJ 2027 South New Castle Perpetual Stoneboro Perpetual Valencia Perpetual Volant 2027 Wampum 2021 West Middlesex 2022 Wheatland Perpetual Zelienople Perpetual Page 1 47 Attachment 1 OHIO EDISON Akron Perpetual Alliance Perpetual Andover 2020 Ashland Perpetual Ashley (Delaware County) Perpetual Ashtabula Perpetual Barberton Perpetual Bay View Perpetual Bellvue Perpetual Beloit Perpetual Berlin Heights Perpetual Boston Heights 2000 Butler 2008 Caledonia Perpetual Callery Perpetual Campbell 2017 Canal Fulton Perpetual Canfield 2020 Cardington (Morrow County) Perpetual Castilia Indeterminate Catawba Perpetual Chippewa on the Lake no exp. Date Clark Perpetual Conneaut Indeterminate Conneaut Lake 2007 Craig Beach Perpetual Creston Perpetual Cuyahoga Falls Perpetual Dalton Perpetual Delaware Perpetual Dublin 2000 East Palestine 2000 Edison (Morrow County) 2005 Enon Perpetual Garrettsville 2020 Girard 2011 Gloria Glens Perpetual Green Camp 2003 Green Unspecified Hanoverton 2020 Hayesville 2018 Kipton 2008 Leetonia 2020 Limaville Perpetual Lisbon Perpetual London 2007 Lorain Perpetual Lordstown 2005 Loudonville Perpetual Lowellville 2001 Magnetic Springs (Union County) Perpetual Page 2 48 Attachment 1 Mansfield Perpetual Mantua 2021 Massillon 2014 McDonald 2018 Medina 2001 Medway Perpetual Mifflin 2002 Monroeville 2010 North Ridgeville 2012 Navarre Perpetual New Middletown 2020 New Waterford 2020 North Fairfield Indeterminate North Ridgeville 2012 Norwalk 2022 Ontario 2009 Orangeville 2020 Orville Perpetual Orwell Perpetual Perrysville Perpetual Plain City (Madison County) 2006 Poland 2020 Polk 2008 Port Clinton Indeterminate Ravenna Perpetual Reminderville Perpetual Richwood (Union County) Perpetual Rittman Perpetual Roaming Shores Perpetual Rogers 2020 South Amherst Indeterminate Salem 2021 Sebring Perpetual Seville Indeterminate Sharon Township Perpetual Shawnee Hills (Delaware County) Perpetual Sheffield Lake Perpetual Sheffield Township Perpetual Sheffield Perpetual Shippingport Perpetual Silver Lake 2005 Slovene Nat'l Benefit Society 2027 South Amherst Perpetual South Vienna 2000 Stoneboro Perpetual Struthers 2014 Stow 2018 Streetsboro 1994 Vermillion Perpetual Wadsworth Perpetual Wakeman Perpetual Wellington Perpetual Page 3 49 Attachment 1 Windham Township Unspecified Wooster 2016 Youngstown 2003 Page 4 50 Attachment 1 TOLEDO EDISON Alvordton 2021 Archbold 2025 Bay View 2022 Berkey 2019 Blakeslee 2006 Bradner 2015 Burgoon 2008 Clay Center 2023 Defiance Perpetual Delta 2000 Edgerton 2005 Fayette Perpetual Freeport Perpetual Gibsonburg 2024 Grand Rapids 2020 Green Springs Perpetual Hamler 2019 Harbor View 2030 Haskins 2016 Helena 2026 Holgate 2019 Holland 2016 Jerry City Perpetual Liberty Center 1999/2022 Lindsey 2026 Luckey 2017 Lyons 2015 Marblehead Perpetual Maumee Perpetual McClure 2019 Metamora 2011 Millbury 2027 Milton Center 2013 Montpelier 2016 New Bavaria 2016 Ney 2016 Northwood 2013 Oak Harbor (partial school) 2015 Oregon 2008 Ottowa Hills Perpetual Permberville 2003 Perrysburg 2003 Port Clinton Perpetual Providence Put-In-Bay Perpetual Risingsun 2002 Rocky Ridge Perpetual Rossford 2021 Stryker 2013/2014 Swanton 2020 Sylvania Perpetual Page 5 51 Attachment 1 Toledo 2000 Tonogany 2024 Walbridge 2016 Wauseon Perpetual Wayne Perpetual West Unity 2020 Weston 2012 Whitehouse 2022 Page 6 52 Attachment 1
CEI Acquilla Perpetual Ashtabula Not for longer than provided for in the Charter of the City Avon Perpetual Avon Lake Perpetual Bay Village Perpetual Beachwood Perpetual Bedford Perpetual Bentlyville Perpetual Berea Perpetual Bratenahl Perpetual Brecksville Perpetual Broadview Heights Perpetual Brook Park Perpetual Brooklyn Perpetual Brooklyn Heights Perpetual Burton Perpetual Chagrin Falls Perpetual Cleveland Perpetual Cleveland Heights Perpetual Conneaut Perpetual Corlett Perpetual Cuyahoga Heights Perpetual Dover Perpetual East Cleveland Perpetual East View Perpetual Eastlake Perpetual Euclid Perpetual Fairport Perpetual Fairview Perpetual Garfield Heights Perpetual Gates Mills Perpetual All townships in Perpetual Geauga County Perpetual Geneva Perpetual Geneva-on-the-Lake Perpetual Glenville Perpetual Glenwillow Perpetual Highland Heights Perpetual Hunting Valley Perpetual Idlewild Perpetual Independence Perpetual Jefferson Perpetual Kirtland Hills Perpetual Lake County Perpetual Lakeline Perpetual Lakeville Perpetual Lakewood Perpetual Linndale Perpetual Lyndhurst Perpetual Madison Perpetual Maple Heights Perpetual
Page 7 53 Attachment 1 Mayfield Perpetual Mayfield Heights Perpetual Mentor Perpetual Mentor-on-the-Lake Perpetual Middleburg Heights Perpetual Middlefield Perpetual Miles Heights Perpetual Moreland Hills Perpetual Newburgh Perpetual Newburgh Heights Perpetual North Kingsville Perpetual North Olmstead Perpetual North Perry Perpetual North Randall Perpetual North Royalton Perpetual Nottingham Perpetual Olmstead Falls Perpetual Orange Perpetual Painesville Perpetual Parkview Perpetual Parma Perpetual Parma Heights Perpetual Pepper Pike Perpetual Perry Perpetual Richmond Perpetual Richmond Heights Perpetual Rock Creek Perpetual Rocky River Perpetual Seven Hills Perpetual Shaker Heights Perpetual Solon Perpetual South Euclid Perpetual South Newburgh Perpetual South Russell Perpetual Strongsville Perpetual Timberlake Perpetual University Heights Perpetual Valley View Perpetual Waite Hill Perpetual Warrensville Heights Perpetual West Clarendon - Granted to the Perpetual West Clarendon Light & Power Co. West Park Perpetual West View (formerly Dover) Perpetual Westlake Perpetual Wickliffe Perpetual Willoughby Perpetual Willowick Perpetual Woodmere Perpetual Page 8 54 Attachment 1 GPU Energy has the necessary franchise rights to furnish electric service in the various municipalities or territories in which it currently provides such service. Those electric franchise rights consist generally of: (i) charter rights; and (ii) certificates of public convenience issued by the PaPUC or the BPU. 55 EXHIBITS A - I 56 EXHIBIT A Copies of all resolutions of directors authorizing the proposed merger, and, if approval of stockholders has been obtained, copies of the resolutions of the stockholders. Applicants request waiver of 18 C.F.R. Sec. 33.3 to permit Applicants to file this Application without Exhibit A. In Revised Filing Requirements Under Part 33 of the Commission's Regulations, FERC Statutes and Regulations Paragraph 32,528 (1998), the Commission indicated that the information required in Exhibit A is not necessary. 57 EXHIBIT B A statement of the measure of control or ownership exercised by or over Applicants by any public utility, or bank, trust company, banking association, or firm that is authorized by law to underwrite or participate in the marketing of securities or a public utility, or any company supplying electric equipment to such party. 58 EXHIBIT B STATEMENT OF MEASURE AND CONTROL OR OWNERSHIP No public utility, bank, trust company, banking association, or firm authorized to underwrite or participate in the marketing of securities of a public utility, or any company supplying electric equipment to any of the Applicants exercises any control by or over any of the Applicants, except that Ohio Edison Company, a public utility, is the sole owner of Pennsylvania Power Company, also a public utility. Neither FirstEnergy Corp., nor any of its subsidiaries, have any officers or directors in common with GPU, Inc., or any of its subsidiaries. 59 EXHIBIT C Balance sheets and supporting plant schedules for the most recent 12 month period only, on an actual and on a pro forma basis in the form prescribed for Statement A and B of FERC Form No. 1. 60 FIRSTENERGY CORP / GPU, INC. PRO FORMA COMBINED BALANCE SHEET AS OF DECEMBER 31, 1999 (UNAUDITED)
CLEVELAND JERSEY PENNSYLVANIA ELECTRIC TOLEDO CENTRAL METROPOLITAN OHIO EDISON POWER ILLUMINATING EDISON POWER & LIGHT EDISON COMPANY COMPANY COMPANY COMPANY COMPANY COMPANY ----------- ------------ ------------ ------- ------------- ------------ ASSETS AND OTHER DEBITS ----------------------- UTILITY PLANT SUBTOTAL-UTILITY PLANT (ELECTRIC) $7,472,804,691 $1,167,216,173 $4,359,898,509 $1,756,239,657 $4,282,312,803 $1,520,681,171 LESS ACCUMULATED PROVISIONS FOR DEPRECIATION AND AMORTIZATION 3,373,616,555 767,521,106 1,399,720,269 596,332,265 2,456,966,652 455,205,770 -------------- -------------- -------------- -------------- -------------- -------------- NET UTILITY PLANT (ELECTRIC) 4,099,188,136 399,695,067 2,960,178,220 1,159,907,392 1,825,346,151 1,065,475,401 NET NUCLEAR FUEL 55,333,981 31,511,503 68,353,741 42,000,544 (621,290) 46,189 -------------- -------------- -------------- -------------- -------------- -------------- NET UTILITY PLANT 4,154,522,117 431,206,570 3,028,531,961 1,201,907,936 1,824,724,861 1,065,521,590 OTHER PROPERTY AND INVESTMENTS 1,517,005,165 130,077,791 884,191,865 469,224,559 413,157,834 180,024,455 CURRENT AND ACCRUED ASSETS 538,031,758 128,413,756 220,444,876 119,362,277 541,047,478 260,737,108 DEFERRED DEBITS 2,122,123,557 368,839,038 3,106,287,160 1,450,617,122 3,146,633,735 2,367,456,931 -------------- -------------- -------------- -------------- -------------- -------------- TOTAL ASSETS AND OTHER DEBITS $8,331,682,597 $1,058,537,155 $7,219,455,861 $3,241,311,894 $5,925,563,908 $3,873,740,084 ============== ============== ============== ============== ============== ============== LIABILITIES AND OTHER CREDITS ----------------------------- PROPRIETARY CAPITAL $2,795,389,515 $253,711,910 $1,354,651,501 $761,704,367 $1,482,015,854 $501,444,282 LONG-TERM DEBT 2,230,074,447 282,175,097 2,810,811,850 1,031,546,526 1,450,648,041 683,430,508 OTHER NONCURRENT LIABILITIES 202,356,480 62,465,666 245,137,658 146,971,049 153,539,575 10,337,873 CURRENT AND ACCRUED LIABILITIES 605,436,563 110,583,249 577,024,506 252,317,255 273,782,087 229,850,744 DEFERRED CREDITS 2,408,425,592 349,601,233 2,231,830,344 1,048,772,697 2,565,578,351 2,448,876,677 -------------- -------------- -------------- -------------- -------------- -------------- TOTAL LIABILITIES AND OTHER CREDITS $8,331,682,597 $1,058,537,155 $7,219,455,861 $3,241,311,894 $5,925,563,908 $3,873,740,084 ============== ============== ============== ============== ============== ==============
CURRENT PENNSYLVANIA FIRST ENERGY MERGER FIRSTENERGY ELECTRIC YORK HAVEN OTHER & GPU PRO FORMA PRO FORMA COMPANY POWER COMPANY SUBSIDIARIES ELIMINATIONS ADJUSTMENTS COMBINED ------------ ------------- ------------ ------------ ----------- ------------- ASSETS AND OTHER DEBITS ----------------------- UTILITY PLANT $1,765,403,888 $27,344,118 $4,944,935,898 $0 ($450,000,000) $26,846,836,906 SUBTOTAL-UTILITY PLANT (ELECTRIC) 522,449,183 7,503,064 1,042,715,260 0 (12,150,000) 10,639,880,144 -------------- ----------- --------------- ---------------- -------------- --------------- LESS ACCUMULATED PROVISIONS FOR DEPRECIATION AND AMORTIZATION 1,212,954,703 19,841,054 3,902,220,638 0 (437,850,000) 16,206,956,762 NET UTILITY PLANT (ELECTRIC) 0 0 86,845,484 0 0 283,470,152 -------------- ----------- --------------- ---------------- -------------- --------------- NET NUCLEAR FUEL 1,212,954,703 19,841,054 3,989,066,122 0 (437,850,000) 16,490,426,914 NET UTILITY PLANT 379,291,683 0 10,078,580,461 (9,021,532,910) 880,000,000 5,890,000,0090 OTHER PROPERTY AND INVESTMENTS 202,099,242 13,365,220 2,522,626,996 (1,669,774,352) 0 2,876,354,359 CURRENT AND ACCRUED ASSETS 2,510,468,560 374,519 4,020,579,647 (351,555,958) 1,073,764,211 19,815,788,722 -------------- ----------- --------------- ----------------- -------------- --------------- DEFERRED DEBITS $4,304,614,188 $33,580,793 $20,610,853,426 ($11,042,663,220) $1,515,914,211 $45,072,590,897 ============== =========== =============== ================= ============== =============== TOTAL ASSETS AND OTHER DEBITS LIABILITIES AND OTHER CREDITS ----------------------------- PROPRIETARY CAPITAL $461,182,233 $19,134,855 $10,528,819,301 ($8,634,058,472) ($988,465,382) $8,535,529,964 LONG-TERM DEBT 544,463,592 0 4,928,482,393 (741,606,713) 2,215,422,250 15,523,447,991 OTHER NONCURRENT LIABILITIES 11,246,732 0 57,924,493 0 0 889,979,526 CURRENT AND ACCRUED LIABILITIES 298,186,649 13,931,265 4,004,625,917 (1,667,198,343) 151,757,343 4,850,297,545 DEFERRED CREDITS 2,989,734,982 514,673 1,093,001,322 0 137,200,000 15,273,335,871 -------------- ----------- --------------- ----------------- -------------- --------------- TOTAL LIABILITIES AND OTHER CREDITS $4,304,814,188 $33,580,793 $20,610,853,426 ($11,042,863,220) $1,515,914,211 $45,072,590,897 ============== =========== =============== ================= ============== ===============
61 EXHIBIT D A statement of all known contingent liabilities except minor items such as damage claims and similar items involving relatively small amounts, as of the date of the application. 62 EXHIBIT D STATEMENTS OF CONTINGENT LIABILITIES 63 The consolidated financial statements include FirstEnergy Corp. (Company) and its principal electric utility operating subsidiaries, Ohio Edison Company (OE), The Cleveland Electric Illuminating Company (CEI), Pennsylvania Power Company (Penn) and The Toledo Edison Company (TE). The Company and its utility subsidiaries are referred to throughout as "Companies." The Company's 1997 results of operations include the results of CEI and TE for the period November 8, 1997 through December 31, 1997. The consolidated financial statements also include the Company's other principal subsidiaries: FirstEnergy Facilities Services Group, LLC. (FE Facilities); FirstEnergy Trading Services, Inc. (FETS); and MARBEL Energy Corporation (MARBEL). FE Facilities is the parent company of several heating, ventilating, air conditioning and energy management companies. FETS markets and trades electricity and natural gas in unregulated markets. MARBEL is a fully integrated natural gas company. Significant intercompany transactions have been eliminated. The Companies follow the accounting policies and practices prescribed by the Public Utilities Commission of Ohio (PUCO), the Pennsylvania Public Utility Commission (PPUC) and the Federal Energy Regulatory Commission (FERC). The preparation of financial statements in conformity with generally accepted accounting principles requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. Certain prior year amounts have been reclassified to conform with the current year presentation. Revenues -- The Companies' principal business is providing electric service to customers in central and northern Ohio and western Pennsylvania. The Companies' retail customers are metered on a cycle basis. Revenue is recognized for unbilled electric service through the end of the year. Receivables from customers include sales to residential, commercial and industrial customers located in the Companies' service area and sales to wholesale customers. There was no material concentration of receivables at December 31, 1999 or 1998, with respect to any particular segment of the Companies' customers. CEI and TE sell substantially all of their retail customer accounts receivable to Centerior Funding Corp. under an asset-backed securitization agreement which expires in 2001. Centerior Funding completed a public sale of $150 million of receivables-backed investor certificates in 1996 in a transaction that qualified for sale accounting treatment. Regulatory Plans -- The PUCO approved OE's Rate Reduction and Economic Development Plan in 1995 and FirstEnergy's Rate Reduction and Economic Development Plan for CEI and TE in January 1997. These regulatory plans were to maintain current base electric rates for OE, CEI and TE through December 31, 2005. At the end of the regulatory plan periods, OE base rates were to be reduced by $300 million (approximately 20 percent below current levels) and CEI and TE base rates were to be reduced by a combined $310 million (approximately 15 percent below current levels). The plans also revised the Companies' fuel cost recovery methods. The Companies formerly recovered fuel-related costs not otherwise included in base rates from retail customers through separate energy rates. In accordance with the respective regulatory plans, OE's, CEI's and TE's fuel rates would be frozen through the regulatory plan period, subject to limited periodic adjustments. As part of OE's and FirstEnergy's regulatory plans, transition rate credits were implemented for customers, which are expected to reduce operating revenues for OE by approximately $600 million and CEI and TE by approximately $391 million during the regulatory plan period. In July 1999, Ohio's new electric utility restructuring legislation which will allow Ohio electric customers to select their generation suppliers beginning January 1, 2001, was signed into law. Among other things, the new law provides for a five percent reduction on the generation portion of residential customers' bills and the opportunity to recover transition costs, including regulatory assets, from January 1, 2001 through December 31, 2005. The period for the recovery of regulatory assets only can be extended up to December 31, 2010. The PUCO was authorized to determine the level of transition cost recovery, as well as the recovery period for the regulatory assets portion of those costs, in considering each Ohio electric utility's transition plan application. 64 The Company, on behalf of its Ohio electric utility operating companies - - OE, CEI and TE - - on December 22, 1999 refiled its transition plan under Ohio's new electric utility restructuring law. The plan was originally filed with the PUCO on October 4, 1999, but was refiled to conform to PUCO rules established on November 30, 1999. The new filing also included additional information on FirstEnergy's plans to turn over control, and perhaps ownership, of its transmission assets to the Alliance Regional Transmission Organization. The PUCO indicated that it will endeavor to issue its order in the Company's case within 275 days of the initial October filing date. The transition plan itemizes, or unbundles, the current price of electricity into its component elements - including generation, transmission, distribution and transition charges. As required by the PUCO's rules, the Company's filing also included its proposals on corporate separation of its regulated and unregulated operations, operational and technical support changes needed to accommodate customer choice, an education program to inform customers of their options under the new law, and how the Company's transmission system will be operated to ensure access to all users. Under the plan, customers who remain with OE, CEI, or TE as their generation provider will continue to receive savings under the Company's rate plans, expected to total $759 million between 2000 and 2005. In addition, customers will save $358 million through reduced charges for taxes and a five percent reduction in the price of generation for residential customers beginning January 1, 2001. Customer prices are expected to be frozen through a five-year market development period (2001-2005), except for certain limited statutory exceptions including the five percent reduction in the price of generation for residential customers. The plan proposes recovery of generation-related transition costs of approximately $4.5 billion ($4.0 billion, net of deferred income taxes) over the market development period; transition costs related to regulatory assets aggregating approximately $4.2 billion ($2.9 billion, net of deferred income taxes) will be recovered over the period of 2001 through early 2004 for OE; 2001 through 2007 for TE; and 2001 through 2010 for CEI. In June 1998, the PPUC authorized a rate restructuring plan for Penn which essentially resulted in the deregulation of Penn's generation business as of June 30, 1998. Penn was required to remove from its balance sheet all regulatory assets and liabilities related to its generation business and assess all other assets for impairment. The Securities and Exchange Commission (SEC) issued interpretive guidance regarding asset impairment measurement which concluded that any supplemental regulated cash flows such as a competitive transition charge (CTC) should be excluded from the cash flows of assets in a portion of the business not subject to regulatory accounting practices. If those assets are impaired, a regulatory asset should be established if the costs are recoverable through regulatory cash flows. Consistent with the SEC guidance, Penn reduced its nuclear generating unit investments by approximately $305 million, of which approximately $227 million was recognized as a regulatory asset to be recovered through a CTC over a seven-year transition period; the remaining net amount of $78 million was written off. The charge of $51.7 million ($30.5 million after income taxes) for discontinuing the application of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS 71), to Penn's generation business was recorded as a 1998 extraordinary item on the Consolidated Statement of Income. All of the Companies' regulatory assets are being recovered under provisions of the regulatory plans. In addition, the PUCO has authorized OE to recognize additional capital recovery related to its generating assets (which is reflected as additional depreciation expense) and additional amortization of regulatory assets during the regulatory plan period of at least $2 billion, and the PPUC had authorized Penn to accelerate at least $358 million, more than the amounts that would have been recognized if the regulatory plans were not in effect. These additional amounts are being recovered through current rates. As of December 31, 1999, OE's and Penn's cumulative additional capital recovery and regulatory asset amortization amounted to $1.048 billion (including Penn's impairment discussed above and CTC recovery). CEI and TE recognized a fair value purchase accounting adjustment of $2.55 billion in connection with the FirstEnergy 65 merger; that fair value adjustment recognized for financial reporting purposes will ultimately satisfy the $2 billion asset reduction commitment contained in the CEI and TE regulatory plan. For regulatory purposes, CEI and TE will recognize the accelerated amortization over the period that their rate plan is in effect. Application of SFAS 71 was discontinued in 1997 with respect to CEI 's and TE's nuclear operations (see "Regulatory Assets" below) and in 1998 with respect to Penn's generation operations (as described above). The following summarizes net assets included in property, plant and equipment relating to operations for which the application of SFAS 71 was discontinued, compared with the respective company's total assets at December 31, 1999. SFAS 71 Discontinued Net Assets Total Assets (In millions) CEI $977 $6,209 TE 530 2,667 Penn 76 1,016 Property, Plant and Equipment -- Property, plant and equipment reflects original cost (except for CEI's, TE's and Penn's nuclear generating units which were adjusted to fair value), including payroll and related costs such as taxes, employee benefits, administrative and general costs, and interest costs. The Companies provide for depreciation on a straight-line basis at various rates over the estimated lives of property included in plant in service. The annual composite rate for OE's electric plant was approximately 3.0% in 1999, 1998 and 1997. The annual composite rate for Penn's electric plant was approximately 2.5% in 1999 and 3.0% in 1998 and 1997. CEI's and TE's composite rates were both approximately 3.4% in 1999 and 1998. In addition to the straight-line depreciation recognized in 1999, 1998 and 1997, OE and Penn recognized additional capital recovery of $95 million, $141 million (excluding Penn's impairment) and $172 million, respectively, as additional depreciation expense in accordance with their regulatory plans. Such additional charges in the accumulated provision for depreciation were $517 million and $422 million as of December 31, 1999 and 1998, respectively. Annual depreciation expense in 1999 included approximately $31.0 million for future decommissioning costs applicable to the Companies' ownership and leasehold interests in four nuclear generating units. The Companies' future decommissioning costs reflect the increase in their ownership interests related to the asset transfer with Duquesne Light Company (Duquesne) discussed below in "Common Ownership of Generating Facilities." The Companies' share of the future obligation to decommission these units is approximately $1.8 billion in current dollars and (using a 4.0% escalation rate) approximately $4.5 billion in future dollars. The estimated obligation and the escalation rate were developed based on site specific studies. Payments for decommissioning are expected to begin in 2016, when actual decommissioning work begins. The Companies have recovered approximately $315 million for decommissioning through their electric rates from customers through December 31, 1999. If the actual costs of decommissioning the units exceed the funds accumulated from investing amounts recovered from customers, the Companies expect that additional amount to be recoverable from their customers. The Companies have approximately $543.7 million invested in external decommissioning trust funds as of December 31, 1999. This includes additions to the trust funds and the corresponding liability of $123 million as a result of the asset transfer. Earnings on these funds are reinvested with a corresponding increase to the decommissioning liability. The Companies have also recognized an estimated liability of approximately $36.7 million related to decontamination and decommissioning of nuclear enrichment facilities operated by the United States Department of Energy (DOE), as required by the Energy Policy Act of 1992. The Financial Accounting Standards Board (FASB) issued a proposed accounting standard for nuclear decommissioning costs in 1996. If the standard is adopted as proposed: (1) annual provisions for decommissioning could increase; (2) the net present value of estimated decommissioning costs could be recorded as a liability; and (3) income from the external decommissioning trusts could be reported as investment income. The FASB subsequently expanded the scope of the proposed standard to include other closure and removal obligations related to long-lived assets. A revised proposal may be issued by the FASB in the first quarter of 2000. 66 Common Ownership of Generating Facilities -- The Companies and Duquesne constituted the Central Area Power Coordination Group (CAPCO). The CAPCO companies formerly owned and/or leased, as tenants in common, various power generating facilities. Each of the companies is obligated to pay a share of the costs associated with any jointly owned facility in the same proportion as its interest. The companies' portions of operating expenses associated with jointly owned facilities are included in the corresponding operating expenses on the Consolidated Statements of Income. On March 26, 1999, FirstEnergy completed its agreements with Duquesne to exchange certain generating assets. All regulatory approvals were received by October 1999. In December 1999, Duquesne transferred 1,436 megawatts owned by Duquesne at eight CAPCO generating units in exchange for 1,328 megawatts at three non-CAPCO power plants owned by the Companies. The agreements for the exchange of assets, which was structured as a like-kind exchange for tax purposes, provides the Companies with exclusive ownership and operating control of all CAPCO generating units. The three FirstEnergy plants transferred are being sold by Duquesne to a wholly owned subsidiary of Orion Power Holdings, Inc. (Orion). The Companies will continue to operate those plants until the assets are transferred to the new owners. Duquesne funded decommissioning costs equal to its percentage interest in the three nuclear generating units that were transferred to FirstEnergy. The Duquesne asset transfer to the Orion subsidiary could take place by the middle of 2000. Under the agreements, Duquesne is no longer a participant in the CAPCO arrangements after the exchange. Nuclear Fuel - OE's and Penn's nuclear fuel is recorded at original cost, which includes material, enrichment, fabrication and interest costs incurred prior to reactor load. CEI and TE severally lease their respective portions of nuclear fuel and pay for the fuel as it is consumed (see Note 2). The Companies amortize the cost of nuclear fuel based on the rate of consumption. The Companies' electric rates include amounts for the future disposal of spent nuclear fuel based upon the formula used to compute payments to the DOE. Income Taxes - Details of the total provision for income taxes are shown on the Consolidated Statements of Taxes. Deferred income taxes result from timing differences in the recognition of revenues and expenses for tax and accounting purposes. Investment tax credits, which were deferred when utilized, are being amortized over the recovery period of the related property. The liability method is used to account for deferred income taxes. Deferred income tax liabilities related to tax and accounting basis differences are recognized at the statutory income tax rates in effect when the liabilities are expected to be paid. Alternative minimum tax credits of $101 million, which may be carried forward indefinitely, are available to reduce future federal income taxes. Retirement Benefits - The Companies' trusteed, noncontributory defined benefit pension plan covers almost all full-time employees. Upon retirement, employees receive a monthly pension based on length of service and compensation. In 1998, the Centerior Energy Corporation (Centerior) pension plan was merged into the FirstEnergy pension plan. The Companies use the projected unit credit method for funding purposes and were not required to make pension contributions during the three years ended December 31, 1999. The assets of the pension plan consist primarily of common stocks, United States government bonds and corporate bonds. The Companies provide a minimum amount of noncontributory life insurance to retired employees in addition to optional contributory insurance. Health care benefits, which include certain employee deductibles and copayments, are also available to retired employees, their dependents and, under certain circumstances, their survivors. The Companies pay insurance premiums to cover a portion of these benefits in excess of set limits; all amounts up to the limits are paid by the Companies. The Companies recognize the expected cost of providing other postretirement benefits to employees and their beneficiaries and covered dependents from the time employees are hired until they become eligible to receive those benefits. 67 The following sets forth the funded status of the plans and amounts recognized on the Consolidated Balance Sheets as of December 31:
Other Pension Benefits Postretirement Benefits (In millions) Change in benefit obligation: Benefit obligation as of January 1 $ 1,500.1 $ 1,327.5 $ 601.3 $ 534.1 Service cost 28.3 25.0 9.3 7.5 Interest cost 102.0 92.5 40.7 37.6 Plan amendments -- 44.3 -- 40.1 Actuarial loss (gain) (155.6) 101.6 (17.6) 10.7 Net increase from asset swap 14.8 -- 12.5 -- Benefits paid (95.5) (90.8) (37.8) (28.7) Benefit obligation as of December 31 1,394.1 1,500.1 608.4 601.3 Change in plan assets: Fair value of plan assets as of January 1 1,683.0 1,542.5 3.9 2.8 Actual return on plan assets 220.0 231.3 0.6 0.7 Company contribution -- -- 0.4 0.4 Benefits paid (95.5) (90.8) -- -- Fair value of plan assets as of December 31 1,807.5 1,683.0 4.9 3.9 Funded status of plan 413.4 182.9 (603.5) (597.4) Unrecognized actuarial loss (gain) (303.5) (110.8) 24.9 30.6 Unrecognized prior service cost 57.3 63.0 24.1 27.4 Unrecognized net transition obligation (asset) (10.1) (18.0) 120.1 129.3 Prepaid (accrued) benefit cost $ 157.1 $ 117.1 $ (434.4) $ (410.1) Assumptions used as of December 31: Discount rate 7.75% 7.00% 7.75% 7.00% Expected long-term return on plan assets 10.25% 10.25% 10.25% 10.25% Rate of compensation increase 4.00% 4.00% 4.00% 4.00%
Net pension and other postretirement benefit costs for the three years ended December 31, 1999 were computed as follows:
Other Pension Benefits Postretirement Benefits (In millions) Service cost $ 28.3 $ 25.0 $ 15.2 $ 9.3 $ 7.5 $ 4.6 Interest cost 102.0 93.5 55.9 40.7 37.6 20.4 Expected return on plan assets (168.1) (152.7) (99.7) (0.4) (0.3) (0.2) Amortization of transition obligation (asset) (7.9) (8.0) (8.0) 9.2 9.2 8.2 Amortization of prior service cost 5.7 2.3 2.1 3.3 (0.8) 0.3 Recognized net actuarial loss (gain) -- (2.6) (0.9) -- -- -- Voluntary early retirement program expense -- -- 54.5 -- -- 1.9 Net benefit cost $ (40.0) $ (43.5) $ 19.1 $ 62.1 $ 53.2 $ 35.2
The health care trend rate assumption is 5.3% in 2000, 5.2% in 2001 and 5.0% for 2002 and later years. Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plan. An increase in the health care trend rate assumption by one percentage point would increase the total service and interest cost components by $4.5 million and the postretirement benefit obligation by $72.0 million. A decrease in the same assumption by one percentage point would decrease the total service and interest cost components by $3.5 million and the postretirement benefit obligation by $58.2 million. Supplemental Cash Flows Information -- All temporary cash investments purchased with an initial maturity of three months or less are reported as cash equivalents on the Consolidated Balance Sheets. At December 31, 1999 and 1998, cash and cash equivalents included $83 million and $26 million, respectively, to be used for the redemption of long-term debt in the first quarter of 2000 and in 1999, respectively. The Companies reflect temporary cash investments at cost, which approximates their fair market value. Noncash financing and investing activities included capital lease transactions amounting to $36.2 million, $61.8 million and $3.0 million for the years 1999, 1998 and 1997, respectively. Commercial paper transactions of OES Fuel, Incorporated (OES Fuel) (a wholly owned subsidiary of OE) that have initial maturity periods of three months or less are reported net within financing activities under long-term debt and are reflected as long-term debt on the Consolidated Balance Sheets (see Note 3H). 68 All borrowings with initial maturities of less than one year are defined as financial instruments under generally accepted accounting principles and are reported on the Consolidated Balance Sheets at cost, which approximates their fair market value. The following sets forth the approximate fair value and related carrying amounts of all other long-term debt, preferred stock subject to mandatory redemption and investments other than cash and cash equivalents as of December 31:
Carrying Fair Carrying Fair Value Value Value Value (In millions) Long-term debt $6,381 $6,331 $6,783 $7,247 Preferred stock $ 295 $ 280 $ 335 $ 340 Investments other than cash and cash equivalents: Debt securities -Maturity (5-10 years) $ 475 $ 476 $ 481 $ 520 -Maturity (more than (0 years) 1,068 1,013 1,109 1,139 Equity securities 17 17 17 17 All other 852 874 520 533 $2,412 $2,380 $2,127 $2,209
The fair values of long-term debt and preferred stock reflect the present value of the cash outflows relating to those securities based on the current call price, the yield to maturity or the yield to call, as deemed appropriate at the end of each respective year. The yields assumed were based on securities with similar characteristics offered by a corporation with credit ratings similar to the Companies' ratings. The fair value of investments other than cash and cash equivalents represent cost (which approximates fair value) or the present value of the cash inflows based on the yield to maturity. The yields assumed were based on financial instruments with similar characteristics and terms. Investments other than cash and cash equivalents include decommissioning trust investments. Unrealized gains and losses applicable to the decommissioning trusts have been recognized in the trust investment with a corresponding change to the decommissioning liability. The debt and equity securities referred to above are in the held-to-maturity category, The Companies have no securities held for trading purposes. Effective December 31, 1998, the Company began accounting for its commodity price derivatives, entered into specifically for trading purposes, on a mark-to-market basis in accordance with Emerging Issues Task Force Issue 98-10, "Accounting for Energy Trading arid Risk Management Activities," with gains and losses recognized currently in the Consolidated Statements of Income. The contracts that were marked to market are included in the Consolidated Balance Sheets as Deferred Charges and Deferred Credits at their fair values. The impact on the consolidated financial statements was immaterial. Regulatory Assets - The Companies recognize, as regulatory assets, costs which the FERC, PUCO and PPUC have authorized for recovery from customers in future periods. Without such authorization, the costs would have been charged to income as incurred. All regulatory assets are being recovered from customers under the Companies' respective regulatory plans. Based on those regulatory plans, at this time, the Companies are continuing to bill and collect cost-based rates relating to all of OE's operations, CEI's and TE's nonnuclear operations, and Penn's nongeneration operations and they continue the application of SFAS 71 to those respective operations. OE and Penn recognized additional cost recovery of $257 million, $50 million and $39 million in 1999, 1998 and 1997, respectively, as additional regulatory asset amortization in accordance with their regulatory plans. FirstEnergy's regulatory plan does not provide for full recovery of CEI's and TE's nuclear operations. As a result, in October 1997, CEI and TE discontinued application of SFAS 71 for their nuclear operations and decreased their regulatory assets of customer receivables for future income taxes related to the nuclear assets by $794 million. The PUCO indicated that it will endeavor to issue its order related to the Company's transition plan by mid-2000. The application of SFAS 71 to OE's generation business and the nonnuclear generation businesses of CEI and TE will be discontinued at that time. If the transition plans ultimately approved by the PUCO for OE, CEI and TE do not provide adequate recovery of their nuclear generating unit investments and regulatory assets, there would be a charge to earnings which could have a material adverse effect on the results of operations and financial condition for the Company, OE, CEI and TE. The Companies will continue to bill and collect cost-based rates for their transmission and distribution services, which will remain regulated; accordingly, it is appropriate that the Companies continue the application of SFAS 71 to those respective operations after December 31, 2000. 69 Net regulatory assets on the Consolidated Balance Sheets are comprised of the following:
(In millions) Nuclear unit expenses $ 1,123.0 $ 1,164.8 Customer receivables for future income taxes 444.3 444.0 Rate stabilization program deferrals 420.1 440.1 Sale and leaseback costs 17.8 218.7 Competitive transition charge 280.4 331.0 Loss on reacquired debt 173.9 183.5 Employee postretirement benefit costs 24.8 28.9 DOE decommissioning and decontamination costs 29.5 32.9 Other 29.6 43.5 Total $ 2,543.4 $ 2,887.4
The Companies lease certain generating facilities, nuclear fuel, office space and other property and equipment under cancelable arid noncancelable leases. OE sold portions of its ownership interests in Perry Unit 1 and Beaver Valley Unit 2 and entered into operating leases on the portions sold for basic lease terms of approximately 29 years. CEI and TE also sold portions of their ownership interests in Beaver Valley Unit 2 and Bruce Mansfield Units 1, 2 and 3 and entered into similar operating leases for lease terms of approximately 30 years. During the terms of their respective leases, OE, CEI and TE continue to be responsible, to the extent of their individual combined ownership and leasehold interests, for costs associated with the units including construction expenditures, operation and maintenance expenses, insurance, nuclear fuel, property taxes and decommissioning. They have the right, at the end of the respective basic lease terms, to renew their respective leases. They also have the right to purchase the facilities at the expiration of the basic lease term or renewal term (if elected) at a price equal to the fair market value of the facilities. The basic rental payments are adjusted when applicable federal tax law changes. OES Finance, Incorporated (OES Finance), a wholly owned subsidiary of OE, maintains deposits pledged as collateral to secure reimbursement obligations relating to certain letters of credit supporting OE's obligations to lessors under the Beaver Valley Unit 2 sale and leaseback arrangements. The deposits pledged to the financial institution providing those letters of credit are the sole property of OES Finance. In the event of liquidation, OES Finance, as a separate corporate entity, would have to satisfy its obligations to creditors before any of its assets could be made available to OE as sole owner of OES Finance common stock. Nuclear fuel is currently financed for CEI and TE through leases with a special-purpose corporation. As of December 31,1999, $116 million of nuclear fuel was financed under a lease financing arrangement totaling $145 million ($30 million of intermediate-term notes arid $115 million from bank credit arrangements). The notes mature in August 2000 and the bank credit arrangements expire in September 2000. Lease rates are based on intermediate-term note rates, bank rates and commercial paper rates. Consistent with the regulatory treatment, the rentals for capital and operating leases are charged to operating expenses on the Consolidated Statements of Income. Such costs for the three years ended December 31, 1999, are summarized as follows: (In millions) Operating leases Interest element $ 208.6 $ 201.2 $ 149.9 Other 110.3 147.8 45.2 Capital leases Interest element 17.5 17.6 6.1 Other 76.1 66.3 6.0 Total rentals $ 412.5 $ 432.9 $ 207.2 The future minimum lease payments as of December 31, 1999, are:
Operating Leases Capital Lease Capital Leases Payments Trusts Net (in millions) 2000 $ 75.4 $ 296.5 $ 150.6 $ 145.9 2001 45.2 307.5 146.1 161.4 2002 29.7 312.7 169.5 143.2 2003 16.0 326.6 176.5 150.1 2004 12.1 291.8 110.7 181.1 Years thereafter 71.6 3,645.8 1,364.3 2,281.5 Total minimum lease payments 250.0 $ 5,180.9 $ 2,117.7 $ 3,063.2 Executory costs 26.9 Net minimum lease payments 223.1 Interest portion 64.8 Present value of net minimum lease payments 158.3 Less current portion 55.2 Noncurrent portion $103.1
70 OE invested in the PNBV Capital Trust, which was established to purchase a portion of the lease obligation bonds issued on behalf of lessors in OE's Perry Unit 1 and Beaver Valley Unit 2 sale and leaseback transactions. CEI and TE established the Shippingport Capital Trust to purchase the lease obligation bonds issued on behalf of lessors in their Bruce Mansfield Units 1, 2 and 3 sale and leaseback transactions. The PNBV and Shippingport capital trust arrangements effectively reduce lease costs related to those transactions. (A) Retained Earnings - There are no restrictions on retained earnings for payment of cash dividends on the Company's common stock. (B) Employee Stock Ownership Plan - The Companies fund the matching contribution for their 401(k) savings plan through an ESOP Trust. All full-time employees eligible for participation in the 401(k) savings plan are covered by the ESOP. The ESOP borrowed $200 million from OE and acquired 10,654,114 shares of OE's common stock through market purchases; the shares were converted into the Company's common stock in connection with the merger. Dividends on ESOP shares are used to service the debt. Shares are released from the ESOP on a pro rata basis as debt service payments are made. In 1999, 1998 and 1997, 627,427 shares, 423,206 shares and 429,515 shares, respectively, were allocated to employees with the corresponding expense recognized based on the shares allocated method. The fair value of 6,778,905 shares unallocated as of December 31, 1999, was approximately $153.8 million. Total ESOP-related compensation expense was calculated as follows: (In millions) Base compensation $ 18.3 $ 13.5 $ 9.9 Dividends on common stock held by the ESOP and used to service debt (4.5) (3.9) (3.4) Net expense $ 13.8 $ 9.6 $ 6.5 (C) Stock Compensation Plans -- Under the Centerior Equity Compensation Plan (Centerior Plan) adopted in 1994, common stock options were granted to management employees. Upon consummation of the merger, outstanding options became exercisable for the Company's common stock with option prices and the number of shares adjusted to reflect the merger conversion ratio. All options under the Centerior Plan expire on or before February 25, 2007. On April 30,1998, the Company adopted the Executive and Director Incentive Compensation Plan (FE Plan). The FE Plan permits awards to be made to key employees in the form of restricted stock, stock options, stock appreciation rights, performance shares or cash. Common stock granted under the FE Plan may not exceed 7.5 million shares. No stock appreciation rights or performance shares have been issued under the FE Plan. A total of 20,000 shares of restricted stock were granted in 1998, with a per share market price of $30.78. Restrictions on the restricted stock lapse in 25% annual increments beginning in the fourth year from date of grant. Dividends on the 1998 grant are not restricted. An additional 8,000 shares of restricted stock were granted in 1999, in five separate awards with a weighted average market price per share of $30.89 and weighted average cliff vesting period of 5.8 years. Dividends on the 1999 grants are being restricted. Options were granted in 1998 arid 1999, and are exercisable after four years from the date of grant with some acceleration of vesting possible based on performance. Stock option activity for the converted Centerior Plan stock options and FE Plan stock options was as follows: Weighted Average Number of Exercise Options Price Stock Option Activity Balance at December 31, 1996 -- $ -- Options granted (at merger) 743,086 23.85 Options exercised 222,023 22.13 Options forfeited 3,675 22.75 Balance at December 31, 1997 517,388 24.59 (517,388 options exercisable) Options granted 189,491 29.82 Options exercised 335,058 24.67 Options forfeited 7,535 29.82 Balance at December 31, 1998 364,286 27.13 (182,330 options exercisable) Options granted 1,811,658 24.90 Options exercised 22,575 21.42 Balance at December 31,1999 2,153,369 25.32 (159,755 options exercisable) 71 As of December 31, 1999, the weighted average remaining contractual life of outstanding stock options was 6.2 years. Under the Executive Deferred Compensation Plan, adopted January 1, 1999, employees can direct a portion of their Annual Incentive Award and/or Long Term Incentive Award into an unfunded FirstEnergy Stock Account to receive vested stock units. An additional 20% premium is received in the form of stock units based on the amount allocated to the FirstEnergy Stock Account. Dividends are calculated quarterly on stock units outstanding and are paid in the form of additional stock units. Upon withdrawal, stock units are converted to FirstEnergy shares. Payout occurs three years from the date of deferral. As of December 31, 1999, there were 61,465.81 stock units outstanding. The Company continues to apply APB Opinion 25, "Accounting for Stock Issued to Employees." As required by SFAS 123, ""Accounting for Stock-Based Compensation," the Company has determined pro forma earnings as though the Company had accounted for employee stock options under the fair value method. The weighted average assumptions used in valuing the options and their resulting fair values are as follows: Valuation assumptions: Expected option term (years) 6.4 10 8 Expected volatility 20.03% 15.50% 16.00% Expected dividend yield 5.97% 5.68% 5.80% Risk-free interest rate 5.97% 5.65% 5.94% Fair value per option $ 3.42 $ 3.25 $ 2.92 The pro forma effects of applying fair value accounting to the Company's stock options would be to reduce net income and earnings per share. The following table summarizes the pro forma effect. Net Income (000) As Reported $568,299 $410,874 Pro Forms $567,876 $410,839 Earnings Per Share of Common Stock - Basic and Diluted As Reported $2.50 $1.82 Pro Forma $2.50 $1.82 (D) Comprehensive Income - In 1998, the Company adopted SFAS 130, "Reporting Comprehensive Income," and applied the standard to all periods presented in the Consolidated Statements of Common Stockholders' Equity. Comprehensive income includes net income as reported on the Consolidated Statements of Income and all other changes in common stockholders' equity except those resulting from transactions with common stockholders. (E) Preferred and Preference Stock - Penn's 7.75% series of preferred stock has a restriction which prevents early redemption prior to July 2003. OE's 8.45% series of preferred stock has no optional redemption provision. CEI's $88.00 Series R preferred stock is not redeemable before December 2001 and its $90.00 Series S has no optional redemption provision. All other preferred stock may be redeemed by the Companies in whole, or in part, with 30-90 days' notice. Preference stock authorized for the Companies are 8 million shares without par value for OE; 3 million shares without par value for CEI; and 5 million shares, $25 par value for TE. No preference shares are currently outstanding. (F) Preferred Stock Subject to Mandatory Redemption - Annual sinking fund provisions for the Companies' preferred stock are as follows: Redemption Price Per Series Shares Share Date Beginning OE 8.45% 50,000 $ 100 (i) CEI $ 7.35 C 10,000 100 (i) 88.00 E 3,000 1,000 (i) 91.50 Q 10,714 1,000 (i) 90.00 S 18,750 1,000 (i) 88.00 R 50,000 1,000 December 1 2001 Penn 7.625 % 7,500 100 October 1 2002 (i) Sinking fund provisions are in effect. Annual sinking fund requirements for the next five years are $38 million in 2000, $85 million in 2001, $19 million in 2002, $2 million in 2003 and $2 million in 2004. A liability of$19 million was included in the net assets acquired from CEI and TE for preferred dividends declared attributable to the post-merger period. Accordingly, no accruals for CEI and TE preferred dividends are included in the Company's Consolidated Statement of Income for the period November 8,1997 through December 31, 1997. 72 (G) Ohio Edison Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trust Holding Solely Ohio Edison Subordinated Debentures - Ohio Edison Financing Trust, a wholly owned subsidiary of OE, has issued $120 million of 9% Cumulative Trust Preferred Capital Securities. GE purchased all of the Trust's Common Securities and simultaneously issued to the Trust $123.7 million principal amount of 9% Junior Subordinated Debentures due 2025 in exchange for the proceeds that the Trust received from its sale of Preferred and Common Securities. The sole assets of the Trust are the Subordinated Debentures whose interest and other payment dates coincide with the distribution and other payment dates on the Trust Securities. Under certain circumstances, the Subordinated Debentures could be distributed to the holders of the outstanding Trust Securities in the event the Trust is liquidated. The Subordinated Debentures may be optionally redeemed by GE beginning December 31, 2000, at a redemption price of $25 per Subordinated Debenture plus accrued interest, in which event the Trust Securities will be redeemed on a pro rata basis at $25 per share plus accumulated distributions. OE's obligations under the Subordinated Debentures along with the related Indenture, amended and restated Trust Agreement, Guarantee Agreement and the Agreement for expenses and liabilities, constitute a full and unconditional guarantee by GE of payments due on the Preferred Securities. (H) Long-Term Debt - The first mortgage indentures and their supplements, which secure all of the Companies' first mortgage bonds, serve as direct first mortgage liens on substantially all property and franchises, other than specifically excepted property, owned by the Companies. Based on the amount of bonds authenticated by the Trustees through December 31,1999, OE's, TE's and Penn's annual sinking and improvement fund requirements for all bonds issued under the mortgage amounts to $31 million. OE, TE and Penn expect to deposit funds in 2000 that will be withdrawn upon the surrender for cancellation of a like principal amount of bonds, which are specifically authenticated for such purposes against unfunded property additions or against previously retired bonds. This method can result in minor increases in the amount of the annual sinking fund requirement. Sinking fund requirements for first mortgage bonds and maturing long-term debt (excluding capital leases) for the next five years are: (In millions) 2000 $668.8 2001 375.7 2002 945.8 2003 459.0 2004 833.3 The Companies' obligations to repay certain pollution control revenue bonds are secured by several series of first mortgage bonds and, in some cases, by subordinate liens on the related pollution control facilities. Certain pollution control revenue bonds are entitled to the benefit of irrevocable bank letters of credit of $397.3 million. To the extent that drawings are made under those letters of credit to pay principal of, or interest on, the pollution control revenue bonds, OE, Penn and/or CEI are entitled to a credit against their obligation to repay those bonds. The Companies pay annual fees of 0.43% to 1.10% of the amounts of the letters of credit to the issuing banks and are obligated to reimburse the banks for any drawings thereunder. 73 OE had unsecured borrowings of$190 million at December 31, 1999, supported by a $250 million long-term revolving credit facility agreement which expires November 18, 2002. OE must pay an annual facility fee of 0.20% on the total credit facility amount. In addition, the credit agreement provides that OE maintain unused first mortgage bond capability for the full credit agreement amount under OE's indenture as potential security for the unsecured borrowings. CEI and TE have letters of credit of approximately $222 million in connection with the sale and leaseback of Beaver Valley Unit 2 that expire in May 2002. The letters of credit are secured by first mortgage bonds of CEI and TE in the proportion of 40% and 60%, respectively (see Note 2). OE's and Penn's nuclear fuel purchases are financed through the issuance of OES Fuel commercial paper and loans, both of which are supported by a $180.5 million long-term bank credit agreement which expires March 31, 2001. Accordingly, the commercial paper and loans are reflected as long-term debt on the Consolidated Balance Sheets. OES Fuel must pay an annual facility fee of 0.20% on the total line of credit and an annual commitment fee of 0.0625% on any unused amount. Short-term borrowings outstanding at December 31, 1999, consisted of $257.8 million of bank borrowings and $160.0 million of OES Capital, Incorporated (OES Capital) commercial paper. OES Capital is a wholly owned sub- sidiary of OE whose borrowings are secured by customer accounts receivable. OES Capital can borrow up to $170 million under a receivables financing agreement at rates based on certain bank commercial paper and is required to pay an annual fee of 0.20% on the amount of the entire finance limit. The receivables financing agreement expires in 2002. The Companies have various credit facilities with domestic banks that provide for borrowings of up to $205 million under various interest rate options. OE's short-term borrowings may be made under its lines of credit on its unsecured notes. To assure the availability of these lines, the Companies are required to pay annual commitment fees that vary from 0.125% to 0.50%. These lines expire at various times during 2000. The weighted average interest rates on short-term borrowings outstanding at December 31, 1999 and 1998, were 6.51% and 5.67%, respectively. Capital Expenditures - The Companies' current forecasts reflect expenditures of approximately $3.0 billion for property additions and improvements from 2000-2004, of which approximately $650 million is applicable to 2000. Investments for additional nuclear fuel during the 2000-2004 period are estimated to be approximately $497 million, of which approximately $159 million applies to 2000. During the same periods, the Companies' nuclear fuel investments are expected to be reduced by approximately $480 million and $106 million, respectively, as the nuclear fuel is consumed. Stock Repurchase Program - On November 17, 1998, the Board of Directors authorized the repurchase of up to 15 million shares of the Company's common stock over a three-year period beginning in 1999. Repurchases are made on the open market, at prevailing prices, and are funded primarily through the use of operating cash flows. During 1999, the Company repurchased and retired 4.6 million shares of its common stock at an average price of $28.08 per share. The Company also entered into a forward contract with Credit Suisse First Boston Corporation for the purchase of 1.4 million shares of the Company's common stock at an average price of $24.22 per share to be settled on November 3, 2000. The contract may be settled through gross physical settlement, net share settlement or net cash settlement at the Company's election. 74 Nuc]ear Insurance - The Price-Anderson Act limits the public liability relative to a single incident at a nuclear power plant to $9.5 billion. The amount is covered by a combination of private insurance and an industry retrospective rating plan. The Companies' maximum potential assessment under the industry retrospective rating plan would be $352.4 million per incident but not more than $40 million in any one year for each incident. The Companies are also insured under policies for each nuclear plant. Under these policies, up to $2.75 billion is provided for property damage and decontamination and decommissioning costs. The Companies have also obtained approximately $1.43 billion of insurance coverage for replacement power costs. Under these policies, the Companies can be assessed a maximum of approximately $44 million for incidents at any covered nuclear facility occurring during a policy year which are in excess of accumulated funds available to the insurer for paying losses. The Companies intend to maintain insurance against nuclear risks as described above as long as it is available. To the extent that replacement power, property damage, decontamination, decommissioning, repair and replacement costs and other such costs arising from a nuclear incident at any of the Companies' plants exceed the policy limits of the insurance in effect with respect to that plant, to the extent a nuclear incident is determined not to be covered by the Companies' insurance policies, or to the extent such insurance becomes unavailable in the future, the Companies would remain at risk for such costs. Environmental Matters - Various federal, state and local authorities regulate the Companies with regard to air and water quality and other environmental matters. The Companies estimate additional capital expenditures for environmental compliance of approximately $292 million, which is included in the construction forecast provided under "Capital Expenditures" for 2000 through 2004. The Companies are in compliance with the current sulfur dioxide (SO (subscript 2)) and nitrogen oxides (NOx) reduction requirements under the Clean Air Act Amendments of 1990. SO(subscript 2) reductions are being achieved by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or purchasing emission allowances. NOx reductions are being achieved through combustion controls and generating more electricity from lower-emitting plants. In September 1998, the Environmental Protection Agency (EPA) finalized regulations requiring additional NOx reductions from the Companies' Ohio and Pennsylvania facilities by May 2003. The EPA's NOx Transport Rule imposes uniform reductions of NOx emissions across a region of twenty-two states and the District of Columbia, including Ohio and Pennsylvania, based on a conclusion that such NOx emissions are contributing significantly to ozone pollution in the eastern United States. In May 1999, the U.S. Court of Appeals for the D.C. Circuit issued a stay which delays implementation of EPA's NOx Transport Rule until the Court has ruled on the merits of various appeals. Under the NOx Transport Rule, each of the twenty-two states are required to submit revised State Implementation Plans (SIP) which comply with individual state NOx budgets established by the EPA contemplating an approximate 85% reduction in utility plant NOx emissions from projected 2007 emissions. A proposed Federal Implementation Plan accompanied the NOx Transport Rule and may be implemented by the EPA in states which fail to revise their SIP. In another separate but related action, eight states filed petitions with the EPA under Section 126 of the Clean Air Act seeking reductions of NOx emissions which are alleged to contribute to ozone pollution in the eight petitioning states. The EPA suggests that the Section 126 petitions will be adequately addressed by the NOx Transport Program, but a December 17, 1999 rulemaking established an alternative program which would require nearly identical 85% NOx reductions at 392 utility plants, including the Companies' Ohio and Pennsylvania plants, by May 2003, in the event implementation of the NOx Transport Rule is delayed. New Section 126 petitions were filed by New Jersey, Maryland, Delaware and the District of Columbia in mid-1999 and are still under evaluation by the EPA. The Companies continue to evaluate their compliance plans and other compliance options. 75 The Companies are required to meet federally approved SO(subscript 2) regulations. Violations of such regulations can result in shutdown of the generating unit involved and/or civil or criminal penalties of up to $27,500 for each day the unit is in violation. The EPA has an interim enforcement policy for $02 regulations in Ohio that allows for compliance based on a 30-day averaging period. The Companies cannot predict what action the EPA may take in the future with respect to the interim enforcement policy. In July 1997, the EPA promulgated changes in the National Ambient Air Quality Standard (NAAQS) for ozone and proposed a new NAAQS for previously unregulated ultra-fine particulate matter. In May 1999, the U.S. Court of Appeals for the D.C. Circuit remanded both standards back to the EPA finding constitutional and other defects in the new NAAQS rules. The D.C. Circuit Court, on October 29, 1999, denied an EPA petition for rehearing. The Companies cannot predict the EPA's action in response to the Court's remand order. The cost of compliance with these regulations, if they are reinstated, may be substantial and depends on the manner in which they are ultimately implemented, if at all, by the states in which the Companies operate affected facilities. In September 1999, FirstEnergy received, and subsequently in October 1999, OE and Penn received, a citizen suit notification letter from the New York Attorney General's office alleging Clean Air Act violations at the W. H. Sammis Plant. In November 1999, OE and Penn received a citizen suit notification letter from the Connecticut Attorney General's office alleging Clean Air Act violations at the Sammis Plant. On November 3, 1999, the EPA issued Notices of Violation (NOV) or a Compliance Order to eight utilities covering 32 power plants, including the Sammis Plant. In addition, the U.S. Department of Justice filed seven civil complaints against various investor-owned utilities, which included a complaint against OE and Penn in the U.S. District Court for the Southern District of Ohio. The NOV and complaint allege violations of the Clean Air Act based on operation and maintenance of the Sammis Plant dating back to 1984. The complaint requests permanent injunctive relief to require the installation of "best available control technology" and civil penalties of up to $27,500 per day of violation. Although unable to predict the outcome of this litigation, the Company believes the Sammis Plant is in full compliance with the Clean Air Act and the NOV and complaint are without merit. Penalties could be imposed if the Sammis Plant continues to operate without correcting the alleged violations and a court determines that the allegations are valid. It is anticipated at this time that the Sammis Plant will continue to operate while the matter is being decided. CEI and TE have been named as "potentially responsible parties" (PRPs) at waste disposal sites which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved, are often unsubstantiated and subject to dispute. Federal law provides that all PRPs for a particular site be held liable on a joint and several basis. CEI and TE have accrued liabilities totaling $5.4 million as of December 31, 1999, based on estimates of the costs of cleanup and the proportionate responsibility of other PRPs for such costs. CEI and TE believe that waste disposal costs will not have a material adverse effect on their financial condition, cash flows or results of operations. The Company's primary segment is its Electric Utility Operating Companies which includes four regulated electric utility operating companies that provide electric service in Ohio and Pennsylvania. Its other material business segment is FETS which markets and trades electricity in nonregulated markets. Financial data for these business segments and products and services are as shown on the following page: 76
Electric FE Trading All Reconciling Utilities Services Other Eliminations Totals (In millions) 1999 External revenues $ 5,421 $ 191 $ 708 $ -- $ 6,320 Intersegment revenues 32 60 102 (194) -- Total revenues 5,453 251 810 (194) 6,320 Depreciation and amortization 913 -- 25 -- 938 Net interest charges 549 6 66 (49) 572 Income taxes 377 (5) 23 -- 395 Net income/Earnings on common stock 545 (8) 35 (4) 568 Total assets 17,105 181 1,864 (926) 18,224 Property additions 417 -- 130 -- 547 Acquisitions -- 25 53 -- 78 1998 External revenues $ 5,215 $ 411 $ 249 $ -- $ 5,875 Intersegment revenues 32 26 97 (155) -- Total revenues 5,247 437 346 (155) 5,875 Depreciation and amortization 748 -- 11 -- 759 Net interest charges 590 2 69 (60) 601 Income taxes 320 (35) (2) -- 283 Extraordinary item: Pennsylvania restructuring (31) -- -- -- (31) Net income/Earnings on common stock 478 (52) 1 (16) 411 Total assets 18,316 54 1,742 (1,920) 18,192 Property additions 304 -- 64 -- 368 Acquisitions -- -- 285 -- 285 1997 External revenues $ 2,844 $ 43 $ 74 $ -- $ 2,961 Intersegment revenues 33 -- 106 (139) -- Total revenues 2,877 43 180 (139) 2,961 Depreciation and amortization 470 -- 5 -- 475 Net interest charges 300 -- 60 (51) 309 Income taxes 206 -- 3 -- 209 Net income/Earnings on common stock 335 (1) 4 (32) 306 Total assets 18,700 32 1,209 (1,680) 18,261 Property additions 166 -- 38 -- 204 Acquisitions -- -- 1,582 -- 1,582
Oil & Gas Energy Related Electricity Sales and Sales and Sales Production Services (In millions) Year 1999 $5,253 $ 203 $ 503 1998 4,980 26 198 1997 2,775 -- -- 77 The following summarizes certain consolidated operating results by quarter for 1999 and 1998.
Three Months Ended March 31, June 30, September 30, December 31, 1999 1999 1999 1999 (In millions, except per share amounts) Revenues $ 1,417.4 $ 1,523.9 $ 1,732.4 $ 1,645.9 Expenses 1,041.7 1,149.8 1,291.0 1,301.7 Income Before Interest and Income Taxes 375.7 374.1 441.4 344.2 Net Interest Charges 146.1 147.4 141.3 137.5 Income Taxes 92.9 101.4 114.3 86.2 Net Income $ 136.7 $ 125.3 $ 185.8 $ 120.5 Earnings per Share of Common Stock $.60 $.55 $.82 $.53 March 31, June 30, September 30, December 31, Three Months Ended 1998 1998 1998 1998 (In millions, except per share amounts) Revenues $ 1,367.1 $ 1,464.0 $ 1,722.0 $ 1,321.8 Expenses 1,016.8 1,197.1 1,294.0 1,020.8 Income Before Interest and Income Taxes 350.3 266.9 428.0 301.0 Net Interest Charges 143.6 154.7 153.3 149.4 Income Taxes 83.0 52.2 111.7 56.9 Income Before Extraordinary Item 123.7 60.0 163.0 94.7 Extraordinary Item (Net of Income Taxes) (Note 1) -- (30.5) -- -- Net Income $ 123.7 $ 29.5 $ 163.0 $ 94.7 Earnings per Share of Common Stock Before Extraordinary Item $.56 $.27 $.71 $.41 Extraordinary Item (Net of Income Taxes) (Note 1) -- (.14) -- -- Earnings per Share of Common Stock $.56 $.13 $.71 $.41
The Company was formed on November 8,1997 by the merger of OE and Centerior. The merger was accounted for as a purchase of Centerior's net assets with 77,637,704 shares of FirstEnergy Common Stock through the conversion of each outstanding Centerior Common Stock share into 0.525 of a share of FirstEnergy Common Stock (fractional shares were paid in cash). Based on an imputed value of $20.125 per share, the purchase price was approximately $1.582 billion, which also included approximately $20 million of merger related costs. Goodwill of approximately $2.0 billion was recognized (to be amortized on a straight-line basis over forty years), which represented the excess of the purchase price over Centerior's net assets after fair value adjustments. Accumulated amortization of goodwill was approximately $109 million as of December 31, 1999. The merger purchase accounting adjustments, which were recorded in the records of Centerior's direct subsidiaries, included recognizing estimated severance and other compensation liabilities ($80 million). The amount charged against the liability in 1998 relating to the costs of involuntary employee separation was $41 million. In addition, the liability was reduced to approximately $9 million as of December 31, 1998 to represent potential costs associated with the separation of 493 CEI employees. The liability adjustment was offset by a corresponding reduction to goodwill recognized in connection with the Centerior acquisition. The following pro forma statement of income of FirstEnergy gives effect to the OE/Centerior merger as if it had been consummated on January 1, 1997, with the purchase accounting adjustments actually recognized in the business combination. Year Ended December 31, 1997 (In millions, except per share amounts) Revenues $5,206 Expenses 3,800 Income Before Interest and Income Taxes 1,406 Net Interest Charges 643 Income Taxes 336 Net Income $ 427 Earnings per Share of Common Stock $ 1.92 Pro forma adjustments reflected above include: (1) adjusting CEI and TE nuclear generating units to fair value based upon independent appraisals and estimated discounted future cash flows based on management's estimate of cost recovery; (2) goodwill recognized representing the excess of the purchase price over Centerior's adjusted net assets; (3) elimination of revenue and expense transactions between OE and Centerior; (4) amortization of the fair value adjustment for long-term debt; and (5) adjustments for estimated tax effects on the above adjustments. 78 PART I. FINANCIAL INFORMATION ----------------------------- FIRSTENERGY CORP. AND SUBSIDIARIES OHIO EDISON COMPANY AND SUBSIDIARIES THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARY THE TOLEDO EDISON COMPANY AND SUBSIDIARY PENNSYLVANIA POWER COMPANY NOTES TO FINANCIAL STATEMENTS (Unaudited) 1 - FINANCIAL STATEMENTS: The principal business of FirstEnergy Corp. (FirstEnergy) is the holding, directly or indirectly, of all of the outstanding common stock of its four principal electric utility operating subsidiaries, Ohio Edison Company (OE), The Cleveland Electric Illuminating Company (CEI), The Toledo Edison Company (TE) and Pennsylvania Power Company (Penn). These utility subsidiaries are referred to throughout as "Companies." Penn is a wholly owned subsidiary of OE. The condensed unaudited financial statements of FirstEnergy and each of the Companies reflect all normal recurring adjustments that, in the opinion of management, are necessary to fairly present results of operations for the interim periods. These statements should be read in connection with the financial statements and notes included in the combined Annual Report on Form 10-K for the year ended December 31, 1999 for FirstEnergy and the Companies. Significant intercompany transactions have been eliminated. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. Actual results could differ from those estimates. The reported results of operations are not indicative of results of operations for any future period. Certain prior year amounts have been reclassified to conform with the current year presentation. Penn's results of operations for the 1999 interim periods include Penn and its wholly owned subsidiary, Penn Power Energy, Inc. (PPE). Penn's interest in PPE was transferred to FirstEnergy Services Corp. (FE Services), an affiliate, effective December 31, 1999. The sole assets of the subsidiary trust that is the obligor on the preferred securities included in FirstEnergy's and OE's capitalization are $123,711,350 principal amount of 9% Junior Subordinated Debentures of OE due December 31, 2025. 2 - COMMITMENTS, GUARANTEES AND CONTINGENCIES: CAPITAL EXPENDITURES- FirstEnergy's current forecast reflects expenditures of approximately $3.0 billion (OE-$766 million, CEI-$529 million, TE-$259 million, Penn-$234 million and unregulated subsidiaries-$1.212 billion) for property additions and improvements from 2000-2004, of which approximately $670 million (OE-$213 million, CEI-$109 million, TE-$99 million, Penn-$29 million and unregulated subsidiaries-$220 million) is applicable to 2000. Investments for additional nuclear fuel during the 2000-2004 period are estimated to be approximately $462 million (OE-$113 million, CEI-$157 million, TE-$108 million and Penn-$84 million), of which approximately $152 million (OE-$33 million, CEI-$56 million, TE-$39 million and Penn-$24 million) applies to 2000. STOCK REPURCHASE PROGRAM- On November 17, 1998, the Board of Directors authorized the repurchase of up to 15 million shares of FirstEnergy's common stock over a three-year period beginning in 1999. Repurchases are made on the open market, at prevailing prices, and are funded primarily through the use of operating cash flows. During the second quarter of 2000 and the first six months of 2000, FirstEnergy repurchased and retired 1.7 million shares (average price of $24.29 per share) and 3.2 million shares (average price of $22.71 per share) of its common stock, respectively. In 1999, FirstEnergy also entered into a forward contract with Credit Suisse First Boston Corporation for the purchase of 1.4 1 79 million shares of FirstEnergy's common stock at an average price of $24.22 per share to be settled on November 3, 2000. The contract may be settled through gross physical settlement, net share settlement or net cash settlement at FirstEnergy's election. ENVIRONMENTAL MATTERS- Various federal, state and local authorities regulate the Companies with regard to air and water quality and other environmental matters. The Companies estimate capital expenditures for environmental compliance of approximately $292 million (OE-$144 million, CEI-$84 million, TE-$33 million and Penn-$31 million), which is included in the construction estimate given under "Capital Expenditures" for 2000 through 2004. The Companies are required to meet federally approved sulfur dioxide (SO2) regulations. Violations of such regulations can result in shutdown of the generating unit involved and/or civil or criminal penalties of up to $27,500 for each day the unit is in violation. The Environmental Protection Agency (EPA) has an interim enforcement policy for SO2 regulations in Ohio that allows for compliance based on a 30-day averaging period. The Companies cannot predict what action the EPA may take in the future with respect to the interim enforcement policy. The Companies are in compliance with the current SO2 and nitrogen oxides (NOx) reduction requirements under the Clean Air Act Amendments of 1990. SO2 reductions are being achieved by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or purchasing emission allowances. NOx reductions are being achieved through combustion controls and the generation of more electricity at lower-emitting plants. In September 1998, the EPA finalized regulations requiring additional NOx reductions from the Companies' Ohio and Pennsylvania facilities by May 2003. The EPA's NOx Transport Rule imposes uniform reductions of NOx emissions across a region of twenty-two states and the District of Columbia, including Ohio and Pennsylvania, based on a conclusion that such NOx emissions are contributing significantly to ozone pollution in the eastern United States. In March 2000, the U.S. Court of Appeals for the D.C. Circuit upheld EPA's NOx Transport Rule except as applied to the State of Wisconsin and portions of Georgia and Missouri. By October 2000, states are to submit revised State Implementation Plans (SIP) which Comply with individual state NOx budgets established by the EPA contemplating an approximate 85% reduction in utility plant NOx emissions from projected 2007 emissions. A proposed Federal Implementation Plan accompanied the NOx Transport Rule and may be implemented by the EPA in states which fail to revise their SIP. In another separate but related action, eight states filed petitions with the EPA under Section 126 of the Clean Air Act seeking reductions of NOx emissions which are alleged to contribute to ozone pollution in the eight petitioning states. The EPA position is that the Section 126 petitions will be adequately addressed by the NOx Transport Program, but a December 17, 1999 rulemaking established an alternative program which would require nearly identical 85% NOx reductions at 392 utility plants, including the Companies' Ohio and Pennsylvania plants, by May 2003, in the event implementation of the NOx Transport Rule is delayed. Additional Section 126 petitions were filed by New Jersey, Maryland, Delaware and the District of Columbia in mid-1999 and are still under evaluation by the EPA. The Companies continue to evaluate their compliance plans and other compliance options. In July 1997, EPA promulgated changes in the National Ambient Air Quality Standard (NAAQS) for ozone and proposed a new NAAQS for previously unregulated ultra-fine particulate matter. In May 1999, the U.S. Court of Appeals for the D.C. Circuit remanded both standards to the EPA, having found constitutional and other defects in the new NAAQS rules. The D.C. Circuit Court, on October 29, 1999, denied an EPA petition for rehearing. The U.S. Supreme Court, on May 22, 2000, agreed to hear appeals of both EPA and industry petitioners regarding the new NAAQS rules and a decision is expected in 2001. The cost of compliance with these regulations, if they are reinstated, may be substantial and will depend on the manner in which they are ultimately implemented, if at all, by the states in which the Companies operate affected facilities. In September 1999, FirstEnergy received, and subsequently in October 1999, OE and Penn received, a citizen suit notification letter from the New York Attorney General's office alleging Clean Air Act violations at the W. H. Sammis Plant. In November 1999, OE and Penn received a citizen suit notification letter from the Connecticut Attorney General's office alleging Clean Air Act violations at the Sammis Plant. In November 1999 and March 2000, the EPA issued Notices of Violation (NOV) or a Compliance Order to eight utilities covering 36 power plants, including the Sammis Plant. In addition, the U.S. Department of Justice filed seven civil complaints against various investor-owned utilities, which included a complaint against OE and Penn in the U.S. District Court for the Southern District of Ohio. The NOV and complaint allege violations of the Clean Air Act based on operation and maintenance of the Sammis Plant dating back to 1984. The complaint requests permanent injunctive relief to require the installation of "best available control technology" and civil penalties of up to $27,500 per day of violation. Although unable to predict the outcome of these proceedings, FirstEnergy believes the Sammis Plant is in full compliance with the Clean Air Act and 2 80 the NOV and complaint are without merit. Penalties could be imposed if the Sammis Plant continues to operate without correcting the alleged violations and a court determines that the allegations are valid. It is anticipated at this time that the Sammis Plant will continue to operate until these proceedings are concluded. 3 81 As a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976, federal and state hazardous waste regulations have been promulgated. Certain fossil-fuel combustion waste products, such as coal ash, were exempted from hazardous, waste disposal requirements pending EPA's evaluation of the need for future regulation. EPA has issued its final regulatory determination that regulation of coal ash as a hazardous waste is unnecessary. On April 25, 2000, EPA announced that it will develop national standards regulating disposal of coal ash under its authority to regulate nonhazardous waste. CEI and TE have been named as "potentially responsible parties" (PRPs) at waste disposal sites which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved, are often unsubstantiated and subject to dispute. Federal law provides that all PRPs for a particular site be held liable on a joint and several basis. CEI and TE have accrued liabilities of $4.4 million and $0.6 million, respectively, as of June 30, 2000, based on estimates of the costs of cleanup and the proportionate responsibility of other PRPs for such costs. CEI and TE believe that waste disposal costs will not have a material adverse effect on their financial condition, cash flows or results of operations. MERGER AGREEMENT- On August 8, 2000, FirstEnergy and GPU, Inc. (GPU), a Pennsylvania corporation, entered into an Agreement and Plan of Merger. Under the merger agreement, FirstEnergy would acquire all of the outstanding shares of GPU's common stock for approximately $4.5 billion in cash and FirstEnergy common stock. FirstEnergy would also assume approximately $7.4 billion of GPU's debt and preferred stock. The transaction would be accounted for by the purchase method. The combined company's principal electric utility operating companies would include OE, CEI, TE and Penn, as well as GPU's electric utility operating companies - Jersey Central Power & Light Company, Metropolitan Edison Company, and Pennsylvania Electric Company, which serve customers in Pennsylvania and New Jersey. Under the agreement, GPU shareholders would receive the equivalent of $36.50 for each share of GPU common stock they own, payable in cash or in FirstEnergy common stock, as long as FirstEnergy's common stock price is between $24.24 and $29.63. Each GPU shareholder would be able to elect the form of consideration they wish to receive, subject to proration so that the aggregate consideration to all GPU shareholders will be 50 percent cash and 50 percent FirstEnergy common stock. Each GPU share converted into FirstEnergy common stock would receive not less than 1.2318 and not more than 1.5055 shares of FirstEnergy common stock, depending on the average closing price of FirstEnergy stock during the 20-day trading period ending on the sixth trading date prior to the merger closing. The stock portion of the consideration is expected to be tax-free to GPU shareholders. The Merger has been approved by the respective Boards of Directors of the Company and GPU and is expected to close promptly after all of the conditions to the consummation of the Merger, including shareholder approval and the receipt of all necessary regulatory approvals, are fulfilled or waived. The receipt of all necessary regulatory approvals, including, the Federal Energy Regulatory Commission, the Nuclear Regulatory Commission, the Federal Communications Commission, and the Securities and Exchange Commission, are expected to take approximately one year. 3- REGULATORY ACCOUNTING: On July 19, 2000, the Public Utilities Commission of Ohio (PUCO) approved FirstEnergy's transition plan by adopting the agreement with major parties to the transition plan it had filed in 1999, on behalf of OE, CEI and TE under Ohio's electric utility restructuring law. Major parties to the agreement included the PUCO staff, the Ohio Consumers' Counsel, the Industrial Energy Users-Ohio, certain power marketers and others. Major provisions of the agreement consisted of approval of the transition plan as filed, including recovery of transition costs through no later than 2006 for CE, mid-2007 for TE and 2008 for CEI, except Where a longer period of recovery is provided for in the agreement. The total transition cost amounts to be recovered are as filed in the transition plan. FirstEnergy will also allow preferred access over FirstEnergy's subsidiaries to non-affiliated marketers, brokers and aggregators to 1,120 megawatts of generation capacity through 2005 at established prices for sales to the Ohio operating companies' retail customers. The base electric rates for distribution service for OE, CEI and TE under their prior respective regulatory plans will be extended from December 31, 2005 through December 31, 2007. 4 82 The transition rate credits for customers under their prior regulatory plans will also be extended through the Companies' respective transition cost recovery periods. 5 83 Beginning January 1, 2001 when Ohio electric customers have the choice to select their generation suppliers under the Ohio restructuring law, the agreement provides to FirstEnergy's Ohio customers electing alternative suppliers, an additional incentive applied to the shopping credit of 45% for residential customers, 30% for commercial customers and 15% for industrial customers as reductions from their bills, when they select alternative energy providers (the credits exceed the price FirstEnergy will be offering to electricity suppliers relating to the 1,120 megawatts described on the previous page). The amount of the incentive will serve to reduce the amortization of transition costs during the market development period (January 1, 2001 through December 31, 2005) and will be recovered over the remaining transition cost recovery periods. If the customer shopping goals established in the agreement are not achieved by the end of 2005, the transition cost recovery periods could be shortened for OE, CEI and TE to reduce recovery by as much as $500 million (OE-$250 million, CEI-$170 million and TE-$80 million), but any such adjustment would be computed on a class-by-class and pro-rata basis. The application of Statement of Financial Accounting Standards (SFAS) No. 71 "Accounting for the Effect of Certain Types of Regulation" (SFAS 71) to OE's generation business and the nonnuclear generation businesses of CEI and TE was discontinued effective with the issuance of the PUCO order. The June 30, 2000 balance sheets reflect the effect of such discontinuance with the reduction of plant investment and the corresponding recognition of regulatory assets recoverable through future regulatory cash flows for generating assets that were impaired in the amount of $1.6 billion ($1.2 billion, $304 million and $53 million for OE, CEI and TE, respectively). The Companies continue to bill and collect cost-based rates for their transmission and distribution services, which remain regulated; accordingly, it is appropriate that the Companies continue the application of SFAS 71 to those respective operations. 4 - NEW ACCOUNTING STANDARD: In June 2000, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 138 (SFAS 138), "Accounting for Certain Derivative Instruments and Certain Hedging Activities - an amendment of FASB Statement No. 133." SFAS 138 modifies Statement No. 133 (SFAS 133) in several ways. The most significant impact of the amendment for FirstEnergy is expansion of the "normal purchases and normal sales" exception in SFAS 133 to include contracts that implicitly or explicitly permit net settlement. As a consequence, a number of contracts entered into in the normal course of business which were previously required to be accounted for as derivative instruments under SFAS 133 will now be excluded from those provisions, reducing SFAS 133's potential for volatility on earnings and other comprehensive income. The amendment also modifies certain hedging requirements of SFAS 133. FirstEnergy anticipates adopting SFAS 138 on its effective date of January 1, 2001. FirstEnergy is in the process of quantifying the impacts on its financial statements of adopting this new standard. 6 84 5. SEGMENT INFORMATION: FirstEnergy's primary segment is its Electric Utility Operating Companies which include four electric utilities that provide electric service in Ohio and Pennsylvania. Its other material business segment consists of the subsidiaries that operate unregulated businesses. Financial data for these business segments are as follows:
Segment Financial Information ----------------------------- Electric Unregulated Reconciling Three Months Ended: Utilities Businesses Eliminations Totals ------------------- --------- ---------- ------------ ------ (In millions) June 30, 2000 ------------- External revenues .................................. $ 1,342 $ 360 $ -- $ 1,702 Intersegment revenues .............................. 29 40 (69) -- Total revenues .................................... 1,371 400 (69) 1,702 Depreciation and amortization ...................... 220 5 -- 225 Net interest charges ............................... 128 17 (11) 134 Income taxes ....................................... 99 (4) -- 95 Net income/Earnings on common stock ................ 141 (4) (2) 135 Total assets ....................................... 17,169 2,092 (1,160) 18,101 Property additions ................................. 102 22 -- 124 Acquisitions ....................................... -- -- -- -- June 30, 1999 ------------- External revenues .................................. $ 1,335 $ 184 $ -- $ 1,519 Intersegment revenues .............................. 8 45 (53) -- Total revenues .................................... 1,343 229 (53) 1,519 Depreciation and amortization ...................... 208 9 -- 217 Net interest charges ............................... 143 16 (12) 147 Income taxes ....................................... 101 -- -- 101 Net income/Earnings on common stock ................ 125 3 (3) 125 Total assets ....................................... 17,393 1,924 (934) 18,383 Property additions ................................. 69 24 -- 93 Acquisitions ....................................... -- -- -- -- Electric Unregulated Reconciling Six Months Ended: Utilities Businesses Eliminations Totals ----------------- --------- ---------- ------------ ------ (In millions) June 30, 2000 ------------- External revenues .................................. $ 2,617 $ 693 $ -- $ 3,310 Intersegment revenues .............................. 57 66 (123) -- Total revenues .................................... 2,674 759 (123) 3,310 Depreciation and amortization ...................... 417 10 -- 427 Net interest charges ............................... 259 35 (25) 269 Income taxes ....................................... 196 (3) -- 193 Net income/Earnings on common stock ................ 282 (2) (4) 276 Total assets ....................................... 17,169 2,092 (1,160) 18,101 Property additions ................................. 219 57 -- 276 Acquisitions ....................................... -- -- -- -- June 30, 1999 ------------- External revenues .................................. $ 2,612 $ 329 $ -- $ 2,941 Intersegment revenues .............................. 16 68 (84) -- Total revenues .................................... 2,628 397 (84) 2,941 Depreciation and amortization ...................... 394 14 -- 408 Net interest charges ............................... 285 32 (24) 293 Income taxes ....................................... 197 (3) -- 194 Net income/Earnings on common stock ................ 268 (2) (4) 262 Total assets ....................................... 17,393 1,924 (934) 18,383 Property additions 121 54 -- 175 Acquisitions -- 9 -- 9
7 85 Notes to Consolidated Financial Statements GPU, Inc. owns all the outstanding common stock of three domestic electric utilities-Jersey Central Power & Light Company (JCP&L), Metropolitan Edison Company (Met-Ed) and Pennsylvania Electric Company (Penelec). The customer service function, transmission and distribution operations and the operations of the remaining non-nuclear generating facilities of these electric utilities are conducting business under the name GPU Energy. JCP&L, Met-Ed and Penelec considered together are referred to as the "GPU Energy companies." The nuclear generation operations of GPU Energy are conducted by GPU Nuclear, Inc. (GPUN). GPU Capital, Inc. and GPU Electric, Inc. and their subsidiaries own, operate and fund the acquisition of electric and gas transmission and distribution systems in foreign countries, and are referred to as "GPU Electric." GPU International, Inc. and GPU Power, Inc. and their subsidiaries develop, own and operate generation facilities in the United States and foreign countries and are referred to as the "GPUI Group." Other subsidiaries of GPU, Inc. include GPU Advanced Resources, Inc. (GPU AR), which is involved in retail energy sales; GPU Telcom Services, Inc. (GPU Telcom), which is engaged in telecommunications-related businesses; and GPU Service, Inc. (GPUS), which provides legal, accounting, financial and other services to the GPU companies. All of these companies considered together are referred to as "GPU." 1. Summary of Significant Accounting Policies The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and revenues and expenses during the reporting period. Actual results could differ from those estimates. System of Accounts: Certain reclassifications of prior years' data have been made to conform with the current presentation. The GPU Energy companies' accounting records are maintained in accordance with the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission (FERC) and adopted by the Pennsylvania Public Utility Commission (PaPUC) and the New Jersey Board of Public Utilities (NJBPU). GPU's accounting records also comply with the Securities and Exchange Commission's (SEC) rules and regulations. Consolidation: The GPU consolidated financial statements include the accounts of its wholly-owned subsidiaries and any affiliates in which it has a controlling financial interest (generally evidenced by a greater than 50% ownership interest). All significant intercompany transactions and accounts are eliminated in consolidation. GPU also uses the equity method of accounting for investments in affiliates in which it has the ability to exercise significant influence. Effective in the third quarter of 1999, GPU began accounting for its Midlands Electricity plc (Midlands) investment as a consolidated entity due to GPU's purchase from Cinergy Corp. (Cinergy) of the remaining 50% ownership interest in Midlands which GPU did not own. As a result of this change, GPU's remaining equity investments are no longer presented in the Notes to Consolidated Financial Statements since these investments as of December 31, 1999 are considered immaterial to GPU's results of operations and financial condition. Regulatory Accounting: Statement of Financial Accounting Standards No.71 (FAS 71), "Accounting for the Effects of Certain Types of Regulation," applies to regulated utilities that have the ability to recover their costs through rates established by regulators and charged to customers. The GPU Energy companies' transmission and distribution operations are currently accounted for under the provisions of FAS 71. In accordance with FAS 71, GPU has deferred certain costs pursuant to actions of the NJBPU and PaPUC and is recovering or expects to recover such costs in regulated rates charged to customers. Regulatory assets and liabilities are reflected net in the Deferred Debits and Other Assets section of the Consolidated Balance Sheets. For additional information about regulatory assets and liabilities, see Note 12, Commitments and Contingencies. With the receipt of the NJBPU Summary Restructuring Order (Summary Order) in 1999 and the PaPUC Restructuring Orders (Restructuring Orders) in 1998, GPU determined that the GPU Energy companies' electric generation operations no longer met the criteria for the continued application of FAS 71, and therefore adopted, for that portion of its business, the provisions of Statement of Financial Accounting Standards No. 101 (FAS 101), "Regulated Enterprises-Accounting for the Discontinuation of Application of FASB Statement No.71" and Emerging Issues Task Force Issue 97-4 (EITF) (Issue 97-4), Deregulation of the Pricing of Electricity -- Issues Related to the Application of FASB Statement No.71 "Accounting for the Effects of Certain Types of Regulation" and No. 101 "Regulated Enterprises -- Accounting for the Discontinuation of Application of FASB Statement No. 71." Currency Translation: In accordance with Statement of Financial Accounting Standards No. 52 (FAS 52), "Foreign Currency Translation," balance sheet accounts of foreign operations are translated from foreign currencies into US dollars at year-end rates, while income statement accounts are translated at the average month-end exchange rates for the relevant period. The resulting translation adjustments are included in Accumulated other comprehensive income/(loss), net of deferred taxes, on the Consolidated Balance Sheets. Gains and losses resulting from foreign currency transactions are included in Net Income. 26 GPU 1999 FINANCIAL REPORT 86 Revenues: GPU recognizes operating revenues for services rendered to the end of the relevant accounting period. GPU Electric and the GPU Energy companies' electric operating revenues also include an estimate for unbilled revenues. Deferred Costs: JCP&L recovers its prudently incurred generation-related costs through a Market Transition Charge (MTC) and Basic Generation Service (BGS) charge, and defers any differences between actual costs and amounts recovered from customers through rates. Met-Ed and Penelec use deferred accounting for the above-market portion of nonutility generation (NUG) costs which are collected through the Competitive Transition Charge (CTC). Utility Plant: At December 31, 1999 and 1998, the GPU Energy companies' generation plants are valued at the lower of cost or market. All other utility plant and additions are valued at cost. The assets of acquired companies are carried at their fair value as of the acquisition date, less accumulated depreciation. Depreciation: GPU generally provides for depreciation at annual rates determined and revised periodically, on the basis of studies, to be sufficient to depreciate the original cost of depreciable property over estimated remaining service lives, which are generally longer than those employed for tax purposes. These rates, on an aggregate composite basis, resulted in annual rates of 2.96%, 3.43% and 3.34% for the years 1999, 1998 and 1997, respectively. GPU GasNet uses the volumetric depreciation method to amortize the cost of its gas pipeline. AMORTIZATION POLICIES: Accounting for TMI-2 and Forked River Investments At December 31, 1999, $61 million is included in Regulatory assets, net on the Consolidated Balance Sheets for JCP&L's investment in Three Mile Island Unit 2 (TMI-2). JCP&L is collecting annual revenues for the amortization of TMI-2 of $9.6 million. This level of revenue will be sufficient to recover the remaining investment by 2008. Met-Ed and Penelec have collected all of their TMI-2 investment attributable to retail customers. At December 31, 1999, $56 million is included in Regulatory assets, net on the Consolidated Balance Sheets for JCP&L's Forked River project. JCP&L is collecting annual revenues for the amortization of this project of $11.2 million, which will be sufficient to recover its remaining investment by 2006. Because JCP&L has not been provided revenues for a return on the unamortized balances of the damaged TMI-2 facility and the cancelled Forked River project, these investments are being carried at their discounted present values. Nuclear Fuel The GPU Energy companies amortize nuclear fuel on a unit-of-production basis. Rates are determined and periodically revised to amortize the cost of the fuel over its useful life. At December 31, 1999 and 1998, the liability of the GPU Energy companies for future contributions to the Federal Decontamination and Decommissioning Fund for the cleanup of uranium enrichment plants operated by the Federal Government amounted to $25 million and $28 million, respectively, and was primarily reflected in Deferred Credits and Other Liabilities-Other. Annual contributions, which began in 1993, are being made over a 15-year period. JCP&L is recovering these costs from customers through its BGS and MTC rates while Met-Ed and Penelec anticipate recovery in Phase II of their restructuring proceedings which are expected to begin in early 2000. Goodwill Goodwill, resulting from GPU's purchase of various businesses, is recorded on the Consolidated Balance Sheets and amortized to expense, on a straight-line basis, over its useful life not to exceed 40 years. Goodwill amortization expense amounted to $51.6 million, $14 million and $2.8 million for the years ended December 31, 1999, 1998 and 1997, respectively. In addition, GPU's investments accounted for under the equity method or cost method include goodwill (net of amortization) totaling $21 million and $18.5 million as of December 31, 1999 and 1998, respectively, which is amortized on a straight-line basis over 20 years. Amortization expense on this goodwill (which is reflected on the Consolidated Statements of Income in Other Income and Deductions) amounted to $1.9 million, $1.6 million and $3.6 million for the years ended December 31, 1999, 1998 and 1997, respectively. GPU periodically reviews undiscounted projections of future cash flows from operations to assess whether any potential intangible impairment exists on its goodwill. For additional information of goodwill resulting from acquisitions, see Note 7, Acquisitions. Nuclear Fuel Disposal Fee: The GPU Energy companies are providing for estimated future disposal costs for spent nuclear fuel at the Oyster Creek nuclear generating station (Oyster Creek) and Three Mile Island Unit 1 (TMI-1) in accordance with the Nuclear Waste Policy Act of 1982. The GPU Energy companies entered into contracts in 1983 with the US Department of Energy (DOE) for the disposal of spent nuclear fuel. The total liability under these contracts, including interest, at December 31, 1999, all of which relates to spent nuclear fuel from nuclear generation through April 1983, amounted to $198 million, and is reflected in Deferred Credits and Other Liabilities-Other. As the actual liability is substantially in excess of the amount recovered to date from ratepayers, the GPU Energy companies have reflected such excess in Regulatory assets, net. The distribution rates presently charged to customers provide for the collection of these costs, plus interest, over a remaining period of seven years for JCP&L. Met-Ed and Penelec are recovering these costs through their respective CTC. 27 GPU 1999 FINANCIAL REPORT 87 The GPU Energy companies' current rates provide for the recovery of costs for spent nuclear fuel disposal costs resulting from nuclear generation subsequent to April 1983. The GPU Energy companies are making quarterly payments to the DOE based on one mill per kilowatt-hour. These remittances hove ceased for TMI-1 and will cease for Oyster Creek when that facility is sold. For a discussion of the DOE's current inability to begin acceptance of spent nuclear fuel from the GPU Energy companies and other standard contract holders, see Note 12, Commitments and Contingencies. Income Taxes: GPU files a consolidated federal income tax return. All participants are jointly and severally liable for the full amount of any tax, including penalties and interest, which may be assessed against the group. Deferred income taxes, which result primarily from purchase accounting adjustments, liberalized depreciation methods, deferred costs, decommissioning funds and discounted Forked River and TMI-2 investments, reflect the impact of temporary differences between the amounts of assets and liabilities recognized for financial reporting purposes and the amounts recognized for tax purposes. Investment tax credits (ITC) are amortized over the estimated service lives of the related facilities. Carrying Amounts of Financial Instruments: The carrying amounts of Temporary cash investments, Special deposits, Securities due within one year and Notes payable on the Consolidated Balance Sheets approximate fair value due to the short period to maturity. The carrying amounts of the Nuclear decommissioning trusts and Nuclear fuel disposal trust, whose assets are invested in cash equivalents and debt and equity securities, also approximate fair value. DERIVATIVE INSTRUMENTS: CPU's use of derivative instruments is intended primarily to manage the risk of interest rate, foreign currency and commodity price fluctuations. GPU does not intend to hold or issue derivative instruments for trading purposes. Commodity Derivatives The GPU Energy companies use futures contracts to manage the risk of fluctuations in the market price of electricity and natural gas. These contracts qualify for hedge accounting treatment under current accounting rules since price movements of the commodity derivatives are highly correlated with the underlying hedged commodities and the transactions are designated as hedges at inception. Accordingly, under the deferral method of accounting, gains and losses related to commodity derivatives are recognized in Power purchased and interchanged in the Consolidated Statements of Income when the hedged transaction closes or if the commodity derivative is no longer sufficiently correlated. Prior to income or loss recognition, deferred gains and losses relating to these transactions are recorded in Current Assets or Current Liabilities in the Consolidated Balance Sheets. Interest Rote Swap Agreements GPU Electric uses interest rate swap agreements to manage the risk of increases in variable interest rates. At December 31, 1999, these agreements covered approximately $1.3 billion of debt, including commercial paper, and were scheduled to expire on various dates through November 2007. Differences between amounts paid and received under interest rate swaps are recorded as adjustments to the interest expense of the underlying debt since the swaps are related to specific assets, liabilities or anticipated transactions. All of the agreements effectively convert variable rate debt, including commercial paper, to fixed rate debt. For the year ended December 31, 1999, fixed rate interest expense incurred in connection with the swap agreements exceeded the variable rate interest expense that would have been incurred had the swaps not been in place by approximately $20.7 million. Currency Swap Agreements GPU Electric uses currency swap agreements to manage currency risk caused by fluctuations in the US dollar exchange rate related to debt issued in the US by Avon Energy Partners Holdings (Avon). These swap agreements effectively convert principal and interest payments on this US dollar debt to fixed sterling principal and interest payments, and expire on the maturity dates of the bonds. Interest expense is recorded based on the fixed sterling interest rate. At December 31, 1999, these currency swap agreements covered (pound sterling)517 million (US $850 million) of debt. Interest expense would have been (pound sterling)16.6 million (US $26.9 million) as compared to (pound sterling)18.2 million (US $29.5 million) for the year ended December 31, 1999 had these agreements not been in place. Indexed Swap Agreement As part of an amended power purchase agreement with Niagara Mohawk Power Corporation (NIMO), Onondaga Cogeneration L.P (Onondaga), a GPU International subsidiary, entered into a 10-year indexed swap agreement in 1998 which is intended to provide Onondaga a fixed revenue stream. At December 31, 1999 and 1998, the indexed swap agreement is valued at $55.1 million and $62.4 million, respectively and is included in Other-Deferred Debits and Other Assets on the Consolidated Balance Sheets. This valuation was derived using the discounted estimated cash flows related to payments expected to be received by Onondaga. The indexed swap is being amortized to expense over the life of the swap agreement. As a result of the anticipated expiration of a related power put agreement between Onondaga and NIMO, GPU International expects to recognize in income the unamortized balance of the indexed swap agreement, mostly offset by a plant impairment, resulting in a slight gain in 2000. 28 GPU 1999 FINANCIAL REPORT 88 Environmental Liabilities: GPU may be subject to loss contingencies resulting from environmental laws and regulations, which include obligations to mitigate the effects on the environment of the disposal or release of certain hazardous wastes and substances at various sites. GPU records liabilities (on an undiscounted basis) for hazardous waste sites where it is probable that a loss has been incurred and the amount of the loss can be reasonably estimated and adjusts these liabilities as required to reflect changes in circumstances. Statements of Cash Flows: For the purpose of the consolidated statements of cash flows, temporary investments include all unrestricted liquid assets, such as cash deposits and debt securities, with maturities generally of three months or less. Cash flows are reported using the US dollar equivalent of the functional currencies in effect at the time of the cash transaction. The effect of exchange rate changes on cash balances held in foreign currencies are reported as a separate line item on the Consolidated Statements of Cash Flows. Avon and Midlands have a formal agreement with a United Kingdom bank, under which they maintain available cash balances in a number of subsidiary bank accounts and an overdraft in the main Midlands operating account. The overdraft balance was $224.6 million as of December 31, 1999, while total cash at Midlands was $274.6 million. Since Midlands manages the overdraft balance in such a way that it does not exceed the available cash balances in the other associated accounts, no interest or fees are paid under this arrangement. In effect, Midlands uses the overdraft facility to utilize the available cash in the other bank accounts. The overdraft position and the offsetting cash balances subject to this arrangement are shown on the Consolidated Balance Sheets in Bank overdraft and Cash and temporary cash investments, respectively. 2. SHORT-TERM BORROWING ARRANGEMENTS At December 31, 1999 and 1998, short-term debt outstanding consisted of $1.2 billion and $369 million, respectively. GPU's weighted average interest rate on the short-term borrowings was 6.5% and 6.4% at December 31, 1999 and 1998, respectively. GPU has various credit facilities in place, the most significant of which are discussed below. These credit facilities generally provide GPU bank loans at negotiable market rates. In addition, commitment fees or facility fees are determined by market rates at the time the facility is put in place, and can change based on the borrower's current bond rating. GPU, Inc. and GPU Energy companies: GPU, Inc. and the GPU Energy companies have available $450 million of short-term borrowing facilities, which includes a $250 million revolving credit agreement and various bank lines of credit. In addition, GPU, Inc., JCP&L, Met-Ed and Penelec can issue commercial paper in amounts of up to $100 million, $150 million, $75 million, and $100 million, respectively. From these sources, GPU, Inc. has regulatory authority to have $250 million outstanding at any one time. JCP&L, Met-Ed and Penelec are limited by their charters or SEC authorization to $265 million, $150 million and $150 million, respectively, of short-term debt outstanding at any one time. As of December 31, 1999, GPU, Inc. and the GPU Energy companies had $123.5 million and $53.6 million, respectively, of short-term debt outstanding. GPU Electric: GPU Capital has a $1 billion 364-day senior revolving credit agreement due in December 2000 supporting the issuance of commercial paper for its $1 billion commercial paper program established to fund GPU Electric acquisitions. GPU, Inc. has guaranteed GPU Capital's obligations under this program. At December 31, 1999, $768 million was outstanding under the commercial paper program, of which $370 million is included in long-term debt on the Consolidated Balance Sheets since it is management's intent to reissue this amount of the commercial paper on a long-term basis. For additional information, see Note 3 Long-Term Debt. GPU Australia Holdings, Inc. has $270 million available under its senior revolving credit facility due in November 2002. This facility, in combination with other GPU, Inc. credit facilities, serves as credit support for GPU Australia Holdings' $350 million commercial paper program. GPU, Inc. has guaranteed GPU Australia Holdings' obligations under this program. At December 31, 1999, $182 million was outstanding under the commercial paper program. Austran Holdings, Inc. (Austran), a wholly-owned indirect subsidiary of GPU Electric, has a A$500 million (approximately US $328 million) commercial paper program to refinance the maturing portion of the senior debt credit facility used to finance the PowerNet Victoria (GPU PowerNet) acquisition. GPU PowerNet has guaranteed Austran's obligations under this program. At December 31, 1999, A$420 million (approximately US $275 million) was outstanding under this program. Midlands maintains a (pound sterling)200 million (approximately US $323 million) syndicated revolving credit facility with a bank for working capital purposes, which matures May 2001. At December 31, 1999, (pound sterling)87 million (approximately US $140 million) was outstanding under this facility. GPUI Group: GPU International has a revolving credit agreement providing for borrowings through December 2000 of up to $30 million outstanding at any one time, of which up to $15 million may be utilized to provide letters of credit. GPU, Inc. has guaranteed GPU International's obligations under this agreement. At December 31, 1999, no borrowings or letters of credit were outstanding under this facility. 29 GPU 1999 FINANCIAL REPORT 89 3. Long.term Debt At December 31, 1999, long-term debt outstanding consisted of the following:
DUE INTEREST TOTAL DEBT WITHIN (IN MILLIONS) MATURITIES RATES OUTSTANDING ONE YEAR ---------------------------------------------------------------------------------------------------------- GPU Energy companies & GPUS: First mortgage bonds 2000-2027 5.35-9.48% $ 1,783(1) $ 90 Senior notes 2004-2019 5.75-6.63% 350 -- Other long-term debt 2000-2039 6.76-7.69% 34 -- GPU Electric: Bank loans 2000-2014 4.16-13% 2,483 475 Bonds 2002-2008 7.38.7.46% 1,092 -- Commercial paper/Medium term notes 2000-2002 6.3-7.65% 633(2) -- GPUI Group 2000-2022 4.5-7% 46 5 ---------------------------------------------------------------------------------------------------------- Total $ 6,421 $570 ----------------------------------------------------------------------------------------------------------
(1) Amount is less unamortized net discount of $4.6 million. (2) Amount includes $370 million of commercial paper, which is included in long-term debt on the Consolidated Balance Sheets since it is management's intent to reissue this amount on a long-term basis. For the years 2000, 2001, 2002, 2003 and 2004, GPU has long-term debt maturities of $570 million, $1.1 billion, $1.2 billion, $260 million and $343 million, respectively. Substantially all of the utility plant owned by the GPU Energy companies is subject to the liens of their respective mortgages. The fair value of long-term debt is estimated based on the quoted market prices for the same or similar issues or on the current rates offered to GPU for debt of the same remaining maturities and credit qualities. The estimated fair value of GPU's long-term debt, including amounts due within one year, as of December 31, 1999 and 1998 is as follows: CARRYING FAIR (IN MILLIONS) AMOUNT VALUE --------------------------------------------------- 1999 $6,421 $6,312 1998 $4,387 $4,455 At December 31, 1999, GPU Electric had long-term debt outstanding of approximately $470 million, which was guaranteed by GPU, Inc. The guaranteed amount consisted of $370 million under the GPU Capital $1 billion commercial paper program and up to $100 million under the (pound sterling)245 million credit facility used to partially fund GPU's acquisition of Cinergy's 50% interest in Midlands. 4. Preferred Securities Cumulative Preferred Stock: At December 31, 1999, JCP&L had the following cumulative preferred stock outstanding: STATED VALUE SHARES STATED VALUE SERIES PER SHARE OUTSTANDING (IN THOUSANDS) ---------------------------------------------------------------------------- With mandatory redemption: 7.52% $100 340,000 $34,000 8.65% $100 500,000 50,000 ---------------------------------------------------------------------------- Total 840,000 84,000 ======= Amounts due within one year (10,833) ---------------------------------------------------------------------------- Total $73,167 ======= Without mandatory redemption: 4% $100 125,000 $12,500 ======= Premium 149 ---------------------------------------------------------------------------- Total $12,649 ============================================================================ 30 GPU 1999 FINANCIAL REPORT 90 The fair value of the preferred stock with mandatory redemption, including amounts due within one year at December 31, 1999 and 1998, was $86.5 million and $94.7 million, respectively. The 7.52% and 8.65% Series are callable at various prices above their stated values beginning in 2002 and 2000, respectively. The 7.52% Series is to be redeemed ratably over twenty years, beginning in 1998. The 8.65% Series is to be redeemed ratably over six years beginning in 2000. The shares with mandatory redemption have redemption requirements of $10.8 million for each year of the next five years. The 4% Series is callable at a price above its stated value. At December 31, 1999, JCP&L could call this series for $13.3 million. In 1999, Met-Ed and Penelec redeemed all of their outstanding shares of cumulative preferred stock for $12.5 million and $17.4 million, respectively. As a result, a reacquisition loss of $1.3 million was charged to income. During 1999, JCP&L redeemed all of its outstanding shares of 7.88% cumulative preferred stock with a stated value of $25 million and $5 million stated value of its 7.52% cumulative preferred stock pursuant to mandatory and optional sinking fund provisions. As a result, a reacquisition loss of $0.8 million was charged to income. During 1998, JCP&L redeemed $5 million stated value of its 7.52% cumulative preferred stock and $10 million stated value of its 8.48% cumulative preferred stock pursuant to mandatory and optional sinking fund provisions. JCP&L's total redemption cost for 1999 and 1998 was $30.9 million and $15 million, respectively. Subsidiary-Obligated Mandatorily Redeemable Preferred Securities: JCP&L Capital, LP., Met-Ed Capital, L.P. and Penelec Capital, L.P. are special-purpose partnerships in which a subsidiary of JCP&L, Met-Ed and Penelec, respectively, is the sole general partner. In 1995, JCP&L Capital, L.P. issued $125 million at 8.56% (5 million shares at $25 per share) of mandatorily redeemable preferred securities (MIPS) and in 1994, Met-Ed Capital, L.P. and Penelec Capital, L.P. issued $100 million at 9% (4 million shares at $25.0 per shore) and $105 million at 8.75% (4.2 million shares at $25 per share), respectively, of MIPS. The proceeds were loaned to JCP&L, Met-Ed and Penelec, respectively, which, in turn, issued their deferrable interest subordinated debentures to the partnerships. In 1999, Met-Ed and Penelec redeemed all of their outstanding shares of MIPS for $100 million and $105 million, respectively. At December 31, 1999, JCP&L's outstanding shares of MIPS had a fair value of $120.6 million. The MIPS of JCP&L Capital, L.P. mature in 2044 and are redeemable at the option of JCP&L beginning in May of 2000 at 100% of their principal amount, or earlier under certain limited circumstances, including the loss of the federal tax deduction for interest paid on the subordinated debentures. JCP&L has fully and unconditionally guaranteed payment of distributions, to the extent there is sufficient cash on hand to permit such payments and legally available funds, and payments on liquidation or redemption of its Preferred Securities. Distributions on the MIPS (and interest on the subordinated debentures) may be deferred for up to 60 months, but JCP&L, may not pay dividends on, or redeem or acquire, any of its cumulative preferred or common stock until deferred payments on its subordinated debentures are paid in full. Trust Preferred Securities: In 1999, $100 million of trust preferred securities were issued on behalf of each of Met-Ed and Penelec at 7.35% and 7.34%, respectively. The trust preferred securities were issued by Met-Ed Capital Trust and Penelec Capital Trust and represent a beneficial interest in the trust equal to a cumulative preferred limited partnership interest in Met-Ed Capital II, L.P. and Penelec Capital II, L.P. The preferred securities are the sole assets of the trust and the only revenues of the trust will be distributions on the trust preferred securities. Each trust security has entitled the holder to receive quarterly cash distributions. Met-Ed and Penelec unconditionally guaranteed the payments by Met-Ed Capital II, L.P. and Penelec Capital II, L.P., respectively. The fair value of the Met-Ed and Penelec trust preferred securities at December 31, 1999 was $81 million and $80.8 million, respectively. 5. Stockholders' Equity ------------------------------------------------------------------------------- The following table presents information relating to the common stock ($2.50 par value) of GPU, Inc.:
1999 1998 1997 ----------------------------------------------------------------------------------------------- Authorized shares 350,000,000 350,000,000 350,000,000 Issued shares 132,783,338 132,783,338 125,783,338 Reacquired shares 10,977,798 4,787,657 4,950,727 Outstanding shares 121,805,540 127,995,681 120,832,611 Outstanding restricted units 283,602 268,360 247,955 Outstanding stock options 394,750 335,950 --
31 GPU 1999 FINANCIAL REPORT 91 In 1999, GPU, Inc. reacquired 6.4 million shares of common stock at a total cost of $225.8 million. Pursuant to the 1990 Employee Stock Plan (as restated to reflect amendments through June 3, 1999), awards may be granted in the form of incentive stock options, nonqualified stock options, restricted shares of common stock, restricted units and stock appreciation rights, which may accompany options. In 1999, 1998 and 1997, GPU, Inc. issued restricted units to officers representing rights to receive shares of common stock, on a one-for-one basis, at the end of the restriction period. The number of shares eventually issued will depend upon the degree to which GPU's performance goals have been met for the restriction period and could range from 0% to 200% of the originally awarded units plus additional units resulting from reinvested dividend equivalents. In 1999, GPU, Inc. granted stock options to its officers to purchase 90,600, 1,000 and 1,000 shares at $42.9375, $34.50 and $34.6875 per share, respectively. In 1998, GPU, Inc. granted stock options to its officers to purchase 305,950 and 30,000 shares at $36.625 per share and $44.25 per share, respectively. All options have an exercise price equal to the fair market value of GPU, Inc. common stock on the grant date. Options are exercisable in accordance with the terms set forth in the Stock Option Agreement. In 1999 and 1998, no options were exercised. Since 1997, pursuant to the Deferred Stock Unit Plan for Outside Directors, restricted units were issued to outside directors representing rights to receive shares of GPU, Inc. common stock, on a one-for-one basis. All restricted units are considered common stock equivalents and, accordingly, are reflected in the computation of diluted earnings per share shown on the Consolidated Statements of Income. The restricted units accrue dividend equivalents on a quarterly basis, which are reinvested in additional restricted units. In 1999, 1998 and 1997, through the above-mentioned plans, officers and outside directors were awarded 56,994, 53,260 and 64,941 restricted units, respectively. In 1999, 1998 and 1997, also through those plans, GPU, Inc. issued a total of 20,215, 20,611 and 54,491 shares of common stock, respectively, from previously reacquired shares. In 1996, GPU adopted the disclosure requirements of Statement of Financial Accounting Standards No. 123 (FAS 123), "Accounting for Stock-Based Compensation," which establishes a fair value-based method of accounting for employee stock-based compensation. As permitted by FAS 123 GPU continues to follow the intrinsic value method set forth in APB Opinion No. 25, "Accounting for Stock Issued to Employees" and disclose the pro forma effects on net income (loss) had the fair value of the options been expensed. The pro forma effects on net income resulting from the application of the fair value-based method of accounting defined in FAS 123 are immaterial. Accumulated Other Comprehensive Income/(Loss): in 1997, GPU adopted Statement of Financial Accounting Standards No. 130, "Reporting Comprehensive Income.' At December 31, 1999 and 1998, GPU had on the Consolidated Balance Sheets the following amounts in Accumulated other comprehensive income/(loss): (IN THOUSANDS) 1999 1998 -------------------------------------------------------------------------------- Net unrealized gains on investments $ 34,183 $ 28,345 Foreign currency translation (40,518) (54,377) Minimum pension liability (6) (5,272) -------------------------------------------------------------------------------- Accumulated other comprehensive income/(loss) $ (6.341) $(31,304) -------------------------------------------------------------------------------- 32 GPU 1999 FINANCIAL REPORT 92 The components of the change in accumulated other comprehensive income/(loss), and the related tax effects, for the years 1999, 1998 and 1997 are as follows:
AMOUNT INCOME TAX AMOUNT BEFORE (EXPENSE) NET OF (IN THOUSANDS) TAXES BENEFIT TAXES =================================================================================================================================== 1999 Net unrealized gains on investments $ 12,516 $ (4,680) $ 7,836 Adjustment for amounts included in income (1,998) -- (1,998) ----------------------------------------------------------------------------------------------------------------------------------- Net change in accumulated other comprehensive income 10,518 (4,680) 5,838 ----------------------------------------------------------------------------------------------------------------------------------- Foreign currency translation adjustments 19,735 (6,907) 12,828 Adjustment for amounts included in income 1,586 (555) 1,031 ----------------------------------------------------------------------------------------------------------------------------------- Net change in accumulated other comprehensive income 21,321 (7,462) 13,859 ----------------------------------------------------------------------------------------------------------------------------------- Minimum pension liability 8,957 (3,691) 5,266 ----------------------------------------------------------------------------------------------------------------------------------- Total change in accumulated other comprehensive income/(loss) $40,796 $ (15,833) $ 24,963 ==================================================================================================================================== 1998 Net unrealized gains on investments $ 13,235 $ (4,248) $ 8,987 ----------------------------------------------------------------------------------------------------------------------------------- Foreign currency translation adjustments (23,295) 8,233 (15,062) Adjustment for amounts included in income 8,737 (3,136) 5,601 ----------------------------------------------------------------------------------------------------------------------------------- Net change in accumulated other comprehensive income (14,558) 5,097 (9,461) ----------------------------------------------------------------------------------------------------------------------------------- Minimum pension liability (2,605) 1,071 (1,534) ----------------------------------------------------------------------------------------------------------------------------------- Total change in accumulated other comprehensive income/(loss) $ (3,928) $ 1,920 $ (2,008) ==================================================================================================================================== 1997 Net unrealized gains on investments $ 10,895 $ (4,521) $ 6,374 Foreign currency translation adjustments (73,115) 24,186 (48,929) Minimum pension liability (2,541) 1,046 (1,495) ----------------------------------------------------------------------------------------------------------------------------------- Total change in accumulated other comprehensive income/(loss) $ (64,761) $ 20,711 $ (44,050) ====================================================================================================================================
6. Accounting For Extraordinary And Non-Recurring Items JCP&L Restructuring Write-off: In 1999, the NJBPU issued a Summary Order regarding JCP&L's unbundling, stranded cost and restructuring filings. Accordingly, in 1999 JCP&L discontinued the application of FAS 71 and adopted the provisions of FAS 101 and EITF 97-4 with respect to its electric generation operations. The transmission and distribution operations of JCP&L continue to be subject to the provisions of FAS 71. In 1999, JCP&L recorded a reduction in operating revenues of $115 million relating to the Summary Order which resulted in an after-tax charge to earnings of $68 million, or $0.54 per share. This reduction reflects JCP&L's obligation to refund to customers 5% from rates in effect as of April 30, 1997. The refund will be made to customers from August 1, 2002 through July 31, 2003. Since JCP&L is no longer subject to FAS 71 for the generation portion of its business, GPU performed an impairment test on Oyster Creek in accordance with Statement of Financial Accounting Standards No. 121 (FAS 121) "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of." This test determined that JCP&L's net investment in Oyster Creek, including plant, nuclear fuel and materials and supplies inventories, was impaired. This investment was written down by a total of $678 million (pre-tax) in 1999 to reflect the plant's fair market value. This impairment, which was recorded as an extraordinary deduction, was reversed and reestablished as a regulatory asset since the Summary Order provides for rate recovery. Generation Asset Divestiture: As discussed below, in 1999, the GPU Energy companies completed the sales of TMI-1 and substantially all of their fossil-fuel and hydroelectric stations. The GPU Energy companies sold TMI-1 to AmerGen Energy Company, LLC (AmerGen), a joint venture of PECO Energy and British Energy, for a total purchase price of approximately $100 million. The sale did not have a significant impact on 1999 earnings since TMI-1 had been written down to its fair market value in 1998. The majority of the amount written down and the majority of the remaining loss from the sale resulted 33 GPU 1999 FINANCIAL REPORT 93 in the deferral of $528.3 million as a regulatory asset pending separate and further reviews by the NJBPU and the PaPUC (Phase II of the Pennsylvania restructuring proceedings). The GPU Energy companies completed the sales of substantially all their fossil fuel and hydroelectric generating facilities to Sithe Energies (Sithe) for approximately $1.6 billion (JCP&L's 50% interest in Yards Creek was not included in the sale and the sales of the 66 MW Forked River combustion turbines an 19 MW York Haven hydroelectric station were postponed). The sale resulted in the recording of an after-tax gain of $13.4 million in 1999 for the portion of the gain related to wholesale operations and the deferral of the remaining pre-tax gain of $706.5 million as a regulatory liability pending separate and further reviews by the NJBPU and the PaPUC. Penelec sold its 20% interest in the Seneca Pumped Storage Hydroelectric Generating Station to The Cleveland Electric Illuminating Company for $43 million. The sale resulted in the recording of an after-tax gain of $1.2 million in 1999 for the portion of the gain related to wholesale operations and the deferral of the remaining pre-tax gain of $30.2 million as a regulatory liability pending further review by the PaPUC. Penelec sold its 50% interest in the Homer City Station to a subsidiary of Edison Mission Energy for approximately $900 million. As a result, Penelec recorded an after-tax gain of $22.6 million in 1999 for the portion of the gain related to wholesale operations and deferred as a regulatory liability the remaining pre-tax gain of $590.7 million pending further review by the PaPUC. Midlands sold its electric supply business to National Power plc for approximately $300 million. As a result, in 1999 GPU recorded an after-tax gain on the sale of $6.8 million. For information on JCP&L's pending sale of Oyster Creek, see Note 12, Commitments and Contingencies. Pennsylvania Restructuring Write-offs: In 1998, Met-Ed and Penelec received PaPUC Restructuring Orders which, among other things, essentially removed from regulation the costs associated with providing electric generation service to Pennsylvania consumers, effective January 1, 1999. Accordingly, in 1998 Met-Ed and Penelec discontinued the application of FAS 71 and adopted the provisions of FAS 101 and EITF Issue 97-4 with respect to their electric generation operations. The transmission and distribution operations of Met-Ed and Penelec continue to be subject to the provisions of FAS 71. As a result of the Restructuring Orders, Met-Ed and Penelec recorded an extraordinary charge of $25.8 million (after-tax) or $0.20 per share and a non-recurring charge of $40 million (after-tax), or $0.32 per share, for customer refunds of 1998 revenues and for the establishment of a sustainable energy fund. In accordance with FAS 121, impairment tests were performed and determined that the net investment in TMI-1 was impaired at December 31, 1998, resulting in a write-down of $518 million (pre-tax) to reflect TMI-1's fair market value. Of the amount written down for TMI-1, $508 million was reestablished as a regulatory asset because management believes it is probable of recovery in the restructuring process and $10 million (the FERC jurisdictional portion) was charged to expense as an extraordinary item in 1998. Windfall Profits Tax Write-off: In 1997, the Government of the United Kingdom imposed a windfall profits tax on privatized utilities, including Midlands. As a result, a one-time charge to income of $109.3 million, or $0.90 per share, was taken in 1997. 34 GPU 1999 FINANCIAL REPORT 94 7. Acquisitions Empresa Distribuidora Electrica Regional, S.A.: in March 1999, GPU Electric acquired Empresa Distribuidora Electrica Regional, S.A. (Emdersa) for US $375 million. The fair value of the assets acquired totaled approximately $320 million and the amount of liabilities assumed totaled approximately $153 million, including debt of $76 million. Emdersa owns three electric distribution companies that serve three provinces in northwest Argentina. The acquisition was financed through the issuance of commercial paper by GPU Capital, guaranteed by GPU, Inc., and a $50 million capital contribution from GPU, Inc. The acquisition has been accounted for under the purchase method of accounting. The total acquisition cost exceeded the estimated value of net assets by approximately $208 million. This excess is considered goodwill and is being amortized on a straight-line basis over 40 years. Transmission Pipelines Australia: In June 1999, GPU Electric acquired Transmission Pipelines Australia (TPA), a natural gas transmission business, from the State of Victoria, Australia for A$1.025 billion (approximately US $675 million). TPA has been renamed GPU GasNet. The fair value of the assets acquired totaled approximately US $704 million and the amount of liabilities assumed totaled approximately US $116 million. The acquisition was financed through: (1) an A$750 million (approximately US $495 million) senior credit facility, which is non-recourse to GPU, Inc.; and (2) an equity contribution from GPU Capital of A$275 million (approximately US $180 million) provided through the issuance of commercial paper guaranteed by GPU, Inc. The acquisition has been accounted for under the purchase method. The total acquisition cost exceeded the estimated value of net assets acquired by approximately $88 million. This excess is considered goodwill and is being amortized on a straight-line basis over 40 years. Midlands Electricity plc: In July 1999, GPU Electric acquired Cinergy's 50% ownership interest in Avon, which owns Midlands, for (pound sterling) 452.5 million (approximately US $714 million). GPU and Cinergy had jointly formed Avon in 1996 to acquire Midlands. The fair value of the assets acquired totaled approximately US $2.1 billion and the liabilities totaled approximately US$1.5 billion, including debt of US $1 billion. GPU Electric financed the acquisition through a combination of equity and debt. The equity was funded from: (1) a US $250 million contribution from GPU, Inc., and (2) the issuance of US $50 million of commercial paper by GPU Capital, which is guaranteed by GPU, Inc. The debt has been provided through a two-year (pound sterling) 245 million (approximately US $382 million) credit agreement entered into by EI UK Holdings, of which GPU, Inc. has guaranteed approximately US $100 million. As a result of GPU's purchase of Cinergy's 50% ownership in Midlands, effective in the third quarter of 1999, GPU began accounting for Midlands as a consolidated entity, rather than under the equity method of accounting as was previously the practice. Consequently, Goodwill, net on the Consolidated Balance Sheet increased by approximately $1.8 billion in the third quarter of 1999. Of this amount, $1.7 billion relates to the previous 1996 acquisition of Midlands by GPU and Cinergy and approximately $119 million represents goodwill resulting from GPU's purchase of Cinergy's 50% share of Midlands. The goodwill is being amortized on a straight-line basis over 40 years. Concurrent with GPU's July 1999 acquisition of the 50% of Midlands which it did not already own, GPU began to evaluate existing restructuring plans and formulate additional plans to reduce operating expenses and achieve ongoing cost reductions. As of December 31, 1999, GPU had identified and approved a cost reduction plan. At the acquisition date, Midlands had recorded a liability of $28.6 million related to previous cost reduction plans. GPU retained $25.7 million of this liability, related to contractual termination and other severance benefits for 276 employees identified in a 1999 business process reengineering project. GPU identified an additional 355 employees (234 in Engineering Services, 38 in metering, 21 in Network Services and 62 from other specific functions) to be terminated as part of the plan and recorded an additional liability of $39.3 million. A net charge of $18.2 million for GPU's 50% share of these adjustments is included in expense and the other 50% was recorded as a purchase accounting adjustment. As of December 31, 1999, $7.2 million of severance benefits had been paid to 172 of these employees. The remaining severance liability of $29.5 million for the remaining 459 employees is included in Other current liabilities, and $28.3 million to be funded out of pension plan assets is included as a pension liability. Management expects the plan will be substantially completed by June 2000. 35 GPU 1999 FINANCIAL REPORT 95 The following unaudited pro forma consolidated results of operations for the years 1999 and 1998 presents information assuming Emdersa, GPU GasNet and the 50% of Midlands GPU did not already own were acquired January 1, 1998. The pro forma amounts include certain adjustments, primarily to recognize interest expense, amortization of goodwill and depreciation of assets having stepped-up bases, and are not necessarily indicative of the actual results that would have been realized had the acquisitions occurred on the assumed date of January 1, 1998, nor are they necessarily indicative of future results. The pro forma operating results are for information purposes only and are as follows:
1999 1998 -------------------------------------------------------------------------------------------------------------------------- (IN THOUSANDS, EXCEPT PER SHARE DATA) AS REPORTED PRO FORMA* AS REPORTED PRO FORMA* -------------------------------------------------------------------------------------------------------------------------- Revenues $4,757,124 $6,030,514 $4,248,792 $6,901,012 Income before extraordinary item $ 459,014 $ 493,449 $ 385,881 $ 441,776 Net income $ 459,014 $ 493,449 $ 360,126 $ 416,021 Basic and Diluted earnings per share before extraordinary item $ 3.66 $ 3.94 $ 3.03 $ 3.47 Basic and Diluted earnings per share $ 3.66 $ 3.94 $ 2.83 $ 3.27 --------------------------------------------------------------------------------------------------------------------------
*Unaudited GPU PowerNet: In 1997, GPU Electric acquired the business of GPU PowerNet from the State of Victoria, Australia for A$2.6 billion (approximately US $1.9 billion). The fair value of the assets acquired totaled approximately US $2 billion and the amount of liabilities assumed totaled approximately US $142.9 million. GPU PowerNet owns and operates the high-voltage electricity transmission system in the State of Victoria serving an area of approximately 87,900 square miles and a population of approximately 4.5 million. The acquisition was financed through: (1) a senior debt credit facility of A$1.9 billion (approximately US $1.4 billion), which is non-recourse to GPU, Inc.; (2) a five-year US $450 million bank credit agreement which is guaranteed by GPU, Inc.; and (3) an equity contribution from GPU, Inc. of US $50 million. The acquisition was accounted for under the purchase method of accounting. The total acquisition costs exceeded the estimated value of net assets by A$877 million (approximately US $537 million). This excess is considered goodwill and is being amortized on a straight-line basis over 40 years. GPU PowerNet has been included in GPU's consolidated financial statements since its purchase on November 6, 1997. The unaudited consolidated pro forma information for 1997, assuming debt financing and an acquisition date of January 1, 1997, is as follows: operating revenues of $4.32 billion; net income of $327 million; basic comings per share of $2.71 and; diluted earnings per share of $2.70. The pro forma results, which are for information purposes only, are not necessarily indicative of the actual results that would have been realized had the acquisition occurred on the assumed date of January 1,1997, nor are they necessarily indicative of future results. Planned Acquisition of MYR Group Inc.: In December 1999, GPU, Inc., and MYR Group Inc. (MYR) entered into an agreement under which GPU has agreed to acquire the utility infrastructure construction firm for $215 million cash, or $30.10 per share of MYR common stock. Following the acquisition, MYR would become a wholly-owned subsidiary of GPU, Inc. The acquisition, which is subject to approval by the SEC and other conditions, is expected to be completed in the first quarter of 2000. The acquisition will be initially financed through short-term debt and will be accounted for under the purchase method of accounting. 36 GPU 1999 FINANCIAL REPORT 96 8. Income Taxes As of December 31, 1999 and 1998, Regulatory assets, net, on the Consolidated Balance Sheets reflected $296 million and $450 million, respectively, of Income taxes recoverable through future rates (primarily related to liberalized depreciation), and Income taxes refundable through future rates of $28 million and $53 million, respectively (related to unamortized ITC). These net regulatory assets are substantially due to the recognition of amounts not previously recorded with the adoption of Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes," in 1993. A summary of the components of deferred taxes as of December 31, 1999 and 1998 follows:
(IN MILLIONS) DEFERRED TAX ASSETS -------------------------------------------------------------------------------------------- 1999 1998 -------------------------------------------------------------------------------------------- Current: Unbilled revenue $ 12 $ 31 Deferred energy -- -- Other 60 16 -------------------------------------------------------------------------------------------- Total $ 72 $ 47 ============================================================================================ Noncurrent: Unamortized ITC $ 36 $ 70 Decommissioning 77 151 Contributions in aid of construction 28 26 Cumulative translation adjustment 22 29 Above-market NUGs 798 748 Customer transition charge 533 534 Revenue subject to refund 47 23 Generation revenue requirements 47 44 Net gain on generation asset sales 499 -- Other 441 379 -------------------------------------------------------------------------------------------- Total $2,528 $2,004 ============================================================================================ DEFERRED TAX LIABILITIES ------------------------------------------------------------------------------------------- 1999 1998 ------------------------------------------------------------------------------------------- Current: Revenue taxes $ 5 $ 8 Deferred energy 3 4 ------------------------------------------------------------------------------------------- Total $ 8 $ 12 =========================================================================================== Noncurrent: Liberalized Depreciation: Previously flowed through $ 222 $ 202 Future revenue requirements 147 155 ------------------------------------------------------------------------------------------- Subtotal 369 357 Liberalized depreciation 659 719 Customer transition charge 1,451 1,684 Net loss on generation asset sales 218 -- Other 866 285 ------------------------------------------------------------------------------------------- Total $3,563 $3,045 ===========================================================================================
The reconciliations of net income to book income subject to tax and of the federal statutory rate to combined federal and state effective tax rates are as follows:
(IN MILLIONS) 1999 1998 1997 ---------------------------------------------------------------------------------------------- Net income $ 459 $ 360 $ 335 Preferred stock dividends 9 11 13 Loss on preferred stock reacquisition 2 -- -- Income tax expense 294 250 234 ---------------------------------------------------------------------------------------------- Book income subject to tax $ 764* $ 621* $ 582* ============================================================================================== Federal statutory rate 35% 35% 35% State tax, net of federal benefit 5 5 4 Amortization of ITC (6) (1) (2) Other, net 4 1 3 ---------------------------------------------------------------------------------------------- Effective income tax rate 38% 40% 40% ==============================================================================================
* Includes pre-tax foreign operations income of $331 million, $238 million and $34 million, of which $85 million, $88 million and $20 million, respectively for 1999, 1998 and 1997, are included in Equity in undistributed earnings/(loss) of affiliates in the Consolidated Statements of Income. 37 GPU 1999 FINANCIAL REPORT 97 Federal and state income tax expense is comprised of the following:
(IN MILLIONS) 1999 1998 1997 ----------------------------------------------------------------------------------------------------------------------------------- Provisions for taxes currently payable: Domestic $ 775 $ 290 $ 206 Foreign 60 22 40 ----------------------------------------------------------------------------------------------------------------------------------- Total provision for taxes $ 835 $ 312 $ 246 Deferred income taxes: Liberalized depreciation $(252) $ 2 $ 14 Foreign deferred taxes 80 31 4 Unbilled revenues 19 -- (8) Gain/(Loss) on sole of properly (406) -- -- Decommissioning 87 (19) (5) PA Restructuring (FAS 71) 61 (15) -- Global Settlement 2 (8) -- Pension expense/Voluntary Enhanced Retirement Programs (1) (8) (10) Nonutility generation contract buyout costs (14) (11) 5 Provision for rote refunds (47) (10) -- OPEBs 2 (12) 5 Other (25) (3) (7) ----------------------------------------------------------------------------------------------------------------------------------- Deferred income taxes, net (494) (53) (2) ----------------------------------------------------------------------------------------------------------------------------------- Amortization of ITC, net (47) (9) (10) ----------------------------------------------------------------------------------------------------------------------------------- Income tax expense $ 294 $ 250 $ 234 -----------------------------------------------------------------------------------------------------------------------------------
The foreign taxes in the above table for 1999, 1998 and 1997, include $53 million ($16 million Current; $37 million Deferred), $27 million ($10 million Current; $17 million Deferred) and $41 million ($37 million Current; $4 million Deferred) in foreign tax expense which is netted in Equity in undistributed earnings/(loss) of affiliates in the Consolidated Statements of Income. Included in the ITC Amortization is the recognition of $36 million of ITC benefit resulting from the sale of generation plants. The Internal Revenue Service (IRS) has completed its examinations of GPU's federal income tax returns through 1995. 9. Supplementary Income Statement Information Maintenance expense and other taxes charged to operating expenses consisted of the following:
(IN MILLIONS) 1999 1998 1997 ---------------------------------------------------------------------------------------------------------------------------------- MAINTENANCE $210 $202 $216 ---------------------------------------------------------------------------------------------------------------------------------- Other taxes: New Jersey Transitional Energy Facility Assessment $ 59 $ 67 -- New Jersey unit tax -- -- $211 Pennsylvania state gross receipts 54 79 81 Real estate and personal property 39 23 27 Value Added and Stamp taxes (U.K.) 6 -- -- Other 33 50 39 ---------------------------------------------------------------------------------------------------------------------------------- Total $191 $219 $358 ----------------------------------------------------------------------------------------------------------------------------------
38 GPU 1999 FINANCIAL REPORT 98 10. Employee Benefits Pension Plans and Other Postretirement Benefits: GPU maintains defined benefit pension plans covering substantially all employees. GPU also provides certain retiree health care and life insurance benefits for substantially all US employees who reach retirement age while working for GPU. The following tables provide a reconciliation of the changes in the plans' benefit obligation and fair value of assets for the years ended December 31, 1999 and 1998, a statement of the funded status of the plans, the amounts recognized in the Consolidated Balance Sheets as of December 31, 1999 and 1998 and the weighted average assumptions used in the measurement of the benefit obligation. The pension benefit disclosure amounts for the year 1999 reflect the acquisition of the remaining 50% of Midlands stock by GPU in July of that year. Accordingly, the July 1999 benefit obligation and fair value of plan assets balances for Midlands are shown next to the line items entitled "Acquisitions" and the post-acquisition amounts occurring in the second half of 1999 are included in the tables.
OTHER POSTRETIREMENT (IN MILLIONS) PENSION BENEFITS BENEFITS ------------------------------------------------------------------------------------------------- ------------------------- 1999 1998 1999 1998 ------------------------------------------------------------------------------------------------- ------------------------- Change in benefit obligation: Benefit obligation at January 1: $ 1,897.0 $ 1,791.7 $ 790.5 $ 798.0 Acquisitions 1,502.5 -- -- -- Service cost 46.2 36.1 15.9 16.4 Interest cost 158.0 121.6 52.2 54.4 Plan amendments 2.5 9.6 -- (6.0) Actuarial (gain)/loss and other items (182.8) 26.2 (36.9) (55.7) Currency exchange (4.0) -- -- -- Benefits paid (171.0) (123.9) (39.8) (30.2) Curtailments and settlements (139.4) 6.8 (44.8) 12.5 Termination benefits 48.8 28.9 -- 1.1 ------------------------------------------------------------------------------------------------------------------------------- Benefit obligation at December 31: $ 3,157.8 $ 1,897.0 $ 737.1 $ 790.5 ------------------------------------------------------------------------------------------------------------------------------- Change in plan assets: Fair value of plan assets at January 1: $ 2,258.8 $ 2,033.3 $ 507.1 $ 403.0 Acquisitions 1,710.2 -- -- -- Actual return on plan assets 579.4 342.9 61.0 78.9 Employer contributions 1.8 6.5 15.0 55.4 Benefits paid (171.0) (123.9) (39.8) (30.2) Currency exchange (5.8) -- -- -- Settlement and other items (30.0) -- -- -- ------------------------------------------------------------------------------------------------------------------------------- Fair value of plan assets at December 31: $ 4,343.4 $ 2,258.8 $ 543.3 $ 507.1 ------------------------------------------------------------------------------------------------------------------------------- Funded Status: Funded status at December 31: $ 1,185.6 $ 361.8 $ (193.8) $ (283.4) Unrecognized net actuarial (gain)/loss (953.0) (439.5) (54.2) (37.8) Unrecognized prior service cost 21.5 27.6 2.9 4.3 Unrecognized net transition (asset)/obligation (1.4) (1.9) 143.3 210.7 ------------------------------------------------------------------------------------------------------------------------------- Net amount recognized $ 252.7 $ (52.0) $ (101.8) $ (106.2) ------------------------------------------------------------------------------------------------------------------------------- Amounts recognized in the Consolidated Balance Sheet at December 31: Prepaid benefit cost $ 297.2 $ 42.0 $ 24.2 $ 43.8 Accrued benefit liability (45.3) (103.0) (126.0) (150.0) Intangible asset 0.8 -- -- -- Accumulated other comprehensive income -- 5.3 -- -- Deferred income taxes -- 3.7 -- -- ------------------------------------------------------------------------------------------------------------------------------- Net amount recognized $ 252.7 $ (52.0) $ (101.8) $ (106.2) ------------------------------------------------------------------------------------------------------------------------------- Weighted average assumptions as of December 31: Discount rate 7.0% 6.75% 7.5% 6.75% Expected return on plan assets 8.1% 8.5% 8.5% 8.5% Rate of compensation increase 4.7% 4.5% -- --
39 GPU 1999 FINANCIAL REPORT 99 The following tables provide the components of net periodic pension and other postretirement benefit costs. As previously discussed, the 1999 net periodic pension cost reflects post-acquisition amounts related to Midlands for the second half of the year.
PENSION PLANS (IN MILLIONS) 1999 1998 1997 ----------------------------------------------------------------------------------------------------------------------------- Service cost $ 46.2 $ 36.1 $ 31.1 Interest cost 158.0 121.6 122.2 Expected return on plan assets (198.0) (140.1) (131.5) Amortization of transition (asset)/obligation (0.5) (0.5) (0.5) Other amortization 2.1 1.1 0.2 ------------------------------------------------------------------------------------------------------------------------------ Net periodic pension cost $ 7.8 $ 18.2 $ 21.5 ------------------------------------------------------------------------------------------------------------------------------
In 1999, the effect of increasing the discount rate assumption for the US pension plans from 6.75% to 7.5% resulted in a $162 million decrease in the benefit obligation as of December 31, 1999. In 1998, the effect of decreasing the discount rate assumption from 7% to 6.75% was partially offset by the effect of decreasing the salary scale assumption from 5% to 4.5% and resulted in a $35 million increase in the benefit obligation as of December 31, 1998. The above net periodic pension cost amount for 1999 excludes pre-tax credits of $31 million, of which $30 million was deferred for return to customers, resulting from employee terminations related to generation asset divestiture. The above net periodic pension cost amount for 1998 excludes pre.tax charges of $3O million, of which $22 million was deferred pending future rate recovery, resulting from early retirement programs in 1998.
OTHER POSTRETIREMENT BENEFITS (IN MILLIONS) 1999 1998 1997 ---------------------------------------------------------------------------------------------------------------------------------- Service cost $ 15.9 $ 16.4 $ 10.7 Interest cost 52.2 54.4 51.7 Expected return on plan assets (37.5) (29.5) (23.7) Amortization of transition (asset)/obligation 14.6 15.8 16.8 Other amortization 1.6 5.0 2.3 ---------------------------------------------------------------------------------------------------------------------------------- Net periodic postretirement benefit cost 46.8 62.1 57.8 Deferred for future recovery -- -- (13.0) ---------------------------------------------------------------------------------------------------------------------------------- Postretirement benefit cost, net of deferrals $ 46.8 $ 62.1 $ 44.8 ----------------------------------------------------------------------------------------------------------------------------------
In 1999, the effect of increasing the assumption associated with medical inflation rates was partially offset by the effect of increasing the discount rate assumption from 6.75% to 73% and resulted in a$45 million increase in the benefit obligation as of December 31, 1999. In 1998, the effect of decreasing the assumption relating to the long-term medical cost of managed care plans was partially offset by the effect of decreasing the discount rate assumption from 7% to 6.75% and resulted in a $40 million decrease in the benefit obligation as of December 31, 1998. The benefit obligation was determined by application of the terms of the medical and life insurance plans, including the effects of established maximums on covered costs, together with relevant actuarial assumptions and health-care cost trend rates of 10% for those not eligible for Medicare and 11% for those eligible for Medicare, then decreasing gradually to 6% in 2010 and thereafter. These costs also reflect the implementation of an annual cost-cap of 6% for individuals who retire after December 31, 1995 and reach age 65. The effect of a 1% change in these assumed cost trend rates would increase or decrease the benefit obligation by $39.2 million or $36.9 million, respectively. In addition, such a 1% change would increase or decrease the aggregate service and interest cost components of net periodic postretirement health-care cost by $3.5 million or $3.4 million, respectively. The above net periodic postretirement benefit cost amount for 1999 excludes pre-tax charges of $3 million, which was deferred pending future rate recovery, resulting from employee terminations related to generation asset divestiture. The above net periodic postretirement benefit cost amount for 1998 excludes pre-tax charges of $20 million, of which $12 million was deferred pending future rate recovery, resulting from early retirement programs in 1998. In JCP&L's 1993 base rate proceeding, the NJBPU allowed JCP&L to collect $3 million annually for incremental postretirement benefit costs, charged to expense, and recognized as a result of FAS 106. Based on the final order, and in accordance with EITF Issue 92-12, "Accounting for OPEB Costs by Rate-Regulated Enterprises," JCP&L has deferred the amounts above that level. A 1997 Stipulation of Final Settlement (Final 40 GPU 1999 FINANCIAL REPORT 100 Settlement) allows JCP&L to recover and amortize the deferred balance at December 31, 1997 over a fifteen-year period. In addition, the Final Settlement allows JCP&L to recover current amounts accrued pursuant to FAS 106, including amortization of the transition obligation. Met-Ed has deferred the incremental postretirement benefit costs associated with the adoption of FAS 106 and in accordance with EITF Issue 92-12, as authorized by the PaPUC in its 1993 base rate order. In accordance with EITF Issue 92-12, effective January 1998, Met-Ed has ceased deferring these costs. The approximately one-third generation-related portion of the deferred balance at December 31, 1997 is to be recovered in rates over a twelve-year period pursuant to the PaPUC's Restructuring Orders. The remaining two-thirds for the transmission and distribution-related portion is to be amortized over a fourteen-year period beginning January 1999, pursuant to the Restructuring Orders. In 1994, Penelec determined that its FAS 106 costs, including costs deferred since January 1993, were not probable of recovery and charged those deferred costs to expense. Savings Plans: GPU also maintains savings plans for substantially all US employees. These plans provide for employee contributions up to specified limits and various levels of employer matching contributions. The matching contributions for GPU for 1999, 1998 and 1997 were $14 million, $13.6 million and $12.6 million, respectively. 11. Leases GPU Energy companies: The GPU Energy companies' capital leases consist primarily of leases for nuclear fuel. Nuclear fuel capital lease obligations at December 31, 1999 and 1998 totaled $48 million and $126 million, respectively. Prior to the sale of TMI-1 to AmerGen in December 1999, the GPU Energy companies had nuclear fuel lease agreements with nonaffiliated fuel trusts for the plant. Upon the sale of TMI-1, the related fuel leases were terminated and all outstanding amounts due under the related credit facility were paid. The Oyster Creek fuel lease agreement will be terminated upon the sale of Oyster Creek to AmerGen. Lease expense consists of an amount designed to amortize the cost of the nuclear fuel as consumed plus interest costs. For the years ended December 31, 1999, 1998 and 1997, these amounts were $53 million, $54 million and $49 million, respectively. Met-Ed and JCP&L have sold and leased back a portion of their respective ownership interests in the Merrill Creek Reservoir project. The annual minimum lease payments under these operating leases, which have remaining terms of 33 years, range from approximately $3.6 million to $6.7 million over the next five years, net of reimbursements from sublessees. Met-Ed believes that its Merrill Creek lease payments will be a recoverable stranded cost in Phase II rate proceedings pending before the PaPUC. JCP&L is recovering its Merrill Creek lease payments, net of reimbursements, through distribution rates. GPUI Group: A subsidiary of GPU International sold and leased back an electric cogeneration facility for on initial term of eleven years (facility lease) for which GPU, Inc. has guaranteed payments of up to $8.1 million. In addition, a 20-year site lease was entered into commencing in 1993. The leases are accounted for as operating leases and rent expense is recorded on a straight-line basis over the initial 11-year term of the facility lease. Rent expense at December 31, 1999 and 1998 totaled $12.3 million and $11.3 million, respectively. The minimum lease payments for 2000, 2001, 2002, 2003 and 2004 are $13.4 million, $14.1 million, $14.8 million, $15.8 million and $12 million, respectively. 12. Commitments and Contingencies Competition and the Changing Regulatory Environment: Generation Asset Divestiture: In 1999, the GPU Energy companies completed the sales of TMI-1 and substantially all of their fossil and hydroelectric generating stations. For additional information on the completed sales, see Note 6, Accounting for Extraordinary and Non-recurring Items. In October 1999, JCP&L agreed to sell Oyster Creek to AmerGen for $10 million and reimbursement of the cost (estimated at $88 million) of the next scheduled refueling outage. This transaction is subject to the receipt of various federal and state regulatory approvals. JCP&L and Public Service Electric & Gas Company (PSE&G) each hold a 50% undivided ownership interest in Yards Creek Pumped Storage Facility (Yards Creek). In December 1998, JCP&L filed a petition with the NJBPU seeking a declaratory order that PSE&G's right of first refusal to purchase JCP&L's ownership interest at its current book value under a 1964 agreement between the companies is void and unenforceable. Management believes that the fair market value of JCP&L's ownership interest in Yards Creek is substantially in excess of its December 31, 1999 book value of $22 million. There can be no assurance as to the outcome of this matter. 41 GPU 1999 FINANCIAL REPORT 101 Stranded Costs and Regulatory Restructuring Orders: With the current market price of electricity being below the cost of some utility-owned generation and power purchase commitments, and the ability of customers to choose their energy suppliers, certain costs, which generally would be recoverable in a regulated environment, may not be recoverable in a competitive environment. These costs are generally referred to as stranded costs. In 1998, the PaPUC issued Restructuring Orders to Met-Ed and Penelec which, among other things, provide for Met-Ed and Penelec's recovery of a substantial portion of what otherwise would have become stranded costs, and provide for a Phase II proceeding following the completion of their generation divestitures to make a final determination of the extent of that stranded cost recovery. An appeal by one intervenor in the restructuring proceedings is pending before the Pennsylvania Supreme Court. There can be no assurance as to the outcome of this appeal. In April 1999, JCP&L entered into a settlement agreement with several parties to its stranded cost and rate unbundling proceedings, pending before the NJBPU. In May 1999, the NJBPU issued a Summary Order, approving the settlement with certain modifications. Among other things, the Summary Order provides for full recovery of JCP&L's stranded costs. The Summary Order did not address the pending sale of Oyster Creek, because at the time the Summary Order was issued, it was uncertain whether the plant would be sold or retired early. As a result of the NJBPU's actions, in the second quarter of 1999, JCP&L recorded a reduction in operating revenues of $115 million reflecting JCP&L's obligation to make refunds to customers. JCP&L is awaiting a final order from the NJBPU. For additional information, see Note 6, Accounting for Extraordinary and Non-recurring Items. Under the NJBPU and the PaPUC restructuring orders, the GPU Energy companies are required to provide generation service to customers who do not choose an alternate supplier. As noted above, the GPU Energy companies have sold or agreed to sell substantially all of their generation assets. Consequently, there will be increased market risks associated with providing generation service since the GPU Energy companies will have to supply energy almost entirely from contracted and open market purchases. Under the Summary Order, JCP&L is permitted to recover reasonable and prudently incurred costs associated with providing basic generation service and to defer the portion of these costs that cannot be recovered currently. The PaPUC's Restructuring Orders, however, generally do not allow Met-Ed and Penelec to recover their costs, including their energy costs in excess of established rate caps. An inability of the GPU Energy companies to supply electricity to customers who do not choose an alternate supplier at a cost recoverable under their capped rates, would have an adverse effect, which may be material, on GPU's results of operations. Generation Agreements: The emerging competitive generation market has created uncertainty regarding the forecasting of the GPU Energy companies' energy supply needs, which has caused the GPU Energy companies to seek shorter-term agreements offering more flexibility. The GPU Energy companies' supply plan focuses on short- to intermediate-term commitments (one month to three years) covering times of expected high energy price volatility (that is, peak demand periods) and reliance on spot market purchases during other periods. As of December 31, 1999, the GPU Energy companies have entered into agreements with third party suppliers to purchase capacity and energy. Payments pursuant to these agreements, which include firm commitments as well ascertain assumptions regarding, among other things, call/put arrangements and the timing of the pending Oyster Creek sale, are estimated to be $709 million in 2000, $565 million in 2001, $328 million in 2002, $144 million in 2003 and $44 million in 2004. Pursuant to the mandates of the federal Public Utility Regulatory Policies Act and state regulatory directives, the GPU Energy companies have been required to enter into power purchase agreements with NUGs for the purchase of energy and capacity which have remaining terms of up to 21 years. The rates under virtually all of the GPU Energy companies' NUG agreements are substantially in excess of current and projected prices from alternative sources. The projected cost of energy from new generation supply sources has also decreased due to improvements in power plant technologies and lower forecasted fuel prices. The following table shows actual payments from 1997 through December 31, 1999, and estimated payments thereafter through 2004. PAYMENTS UNDER NUG AGREEMENTS (IN MILLIONS) TOTAL JCP&L MET-ED PENELEC ------------------------------------------------------------ 1997 759 384 172 203 1998 788 403 174 211 1999 774 388 167 219 2000 794 405 157 232 2001 778 410 154 214 2002 799 422 158 219 2003 802 413 163 226 2004 808 407 168 233 42 GPU 1999 FINANCIAL REPORT 102 The NJBPU Summary Order and PaPUC Restructuring Orders provide the GPU Energy companies assurance of full recovery of their NUG costs (including above-market NUG costs and certain buyout costs). Accordingly, the GPU Energy companies have recorded, on a present value basis, a liability for above-market NUG costs of $3.2 billion on the Consolidated Balance Sheets which is fully offset by Regulatory assets, net. In addition, JCP&L recorded a liability of $64 million for above-market utility power purchase agreements with a corresponding offset to Regulatory assets, net, since there is also assurance of full recovery of these costs. The GPU Energy companies are continuing efforts to reduce the above-market costs of these agreements and will, where beneficial, attempt to renegotiate the prices of the agreements, offer contract buyouts and attempt to convert must-run agreements to dispatchable agreements. There can be no assurance as to the extent to which these efforts will be successful. In 1997, the NJBPU approved a Stipulation of Final Settlement which, among other things, provided for the recovery of costs associated with the buyout of the Freehold Cogeneration power purchase agreement (Freehold buyout). The NJBPU approved the cost recovery of up to $135 million, over a seven-year period, on an interim basis subject to refund. The NJBPU's Summary Order provides for the continued recovery of the Freehold buyout in the MTC, but has not altered the interim nature of such recovery, pending a final decision by the NJBPU. There can be no assurance as to the outcome of this matter. Accounting Matters: JCP&L, in 1999, and Met-Ed and Penelec in 1998, discontinued the application of FAS 71, and adopted the provisions of FAS 101, and EITF Issue 97-4 with respect to their electric generation operations. The transmission and distribution portion of the GPU Energy companies' operations continue to be subject to the provisions of FAS 71. Regulatory assets, net as reflected in the December 31, 1999 and December 31, 1998 Consolidated Balance Sheets in accordance with the provisions of FAS 71 and EITF Issue 97-4 were as follows:
(IN THOUSANDS) 1999 1998 ------------------------------------------------------------------------------------------------------------- Market transition charge (MTC)/basic generation service (NJ) $ 2,358,844 $ -- Competitive transition charge (CTC) (PA) 803,064 1,023,815 Reserve for generation divestiture 536,904 1,527,985 Power purchase contract loss not in CTC (PA) 369,290 369,290 Costs recoverable through distribution rates (NJ) 296,841 -- Income taxes recoverable through future rates, net 280,268 396,937 Three Mile Island Unit 2 (TMI-2) decommissioning costs 100,794 119,571 Societal benefits charge (NJ) 116,941 -- Other postretirement benefits 25,335 73,770 Nonutility generation contract buyout costs -- 123,208 Unamortized property losses (NJ) -- 80,287 Net investment in TMI-2 (NJ) -- 65,787 Environmental remediation (NJ) -- 50,214 Above market NUC deferral costs (252,348) (16,067) Other, net 76,721 126,032 ------------------------------------------------------------------------------------------------------------- Total regulatory assets, net $ 4,712,654 $ 3,940,829 -------------------------------------------------------------------------------------------------------------
Statement of Financial Accounting Standards No. 133 (FAS 133), "Accounting for Derivative Instruments and Hedging Activities," establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. FAS 133 requires that companies recognize all derivatives as either assets or liabilities on the balance sheet and measure those instruments at fair value. GPU will be required to include its derivative transactions on its balance sheet at fair value, and recognize the subsequent changes in fair value as either gains or losses in earnings or report them as a component of other comprehensive income, depending upon the intended use and designation of the derivative as a hedge. FAS 133 is effective for all fiscal quarters of fiscal years beginning after June 15, 2000. GPU will adopt FAS 133 in the first quarter of 2001 and is in the process of evaluating the impact of the implementation of this statement. GPU's use of derivative instruments is intended to manage the risk of interest rate, foreign currency and commodity price fluctuations and may include such transactions as electricity and natural gas forward and futures contracts, foreign currency swaps, interest rate swaps and options. GPU does not intend to hold or issue derivative instruments for trading purposes. 43 GPU 1999 FINANCIAL REPORT 103 Nuclear Facilities: Investments: In December 1999, the GPU Energy companies sold TMI-1 to AmerGen for approximately $100 million. In addition, JCP&L has agreed to sell Oyster Creek to AmerGen for $10 million and reimbursement of the cost (estimated at $88 million) of the next refueling outage. TMI-2, which was damaged during a 1979 accident, is jointly owned by JCP&L, Met-Ed and Penelec in the percentages of 25%, 50% and 25%. JCP&L's net investment in TMI-2 at December 31, 1999 and 1998 was $61 million and $66 million, respectively. JCP&L is collecting revenues for TMI-2 on a basis which provides for the recovery of its remaining investment in the plant by 2008. Met-Ed and Penelec's remaining investments in TMI-2 were written off in 1998 after receiving the PaPUC's Restructuring Orders. Costs associated with the operation, maintenance and retirement of nuclear plants have continued to be significant and less predictable than costs associated with other sources of generation, in large part due to changing regulatory requirements, safety standards, availability of nuclear waste disposal facilities and experience gained in the construction and operation of nuclear facilities. Also, not all risks associated with the ownership or operation of nuclear facilities may be adequately insured or insurable. Consequently, the recovery of costs associated with nuclear projects, including replacement power, any unamortized investment at the end of each plant's useful life (whether scheduled or premature), the carrying costs of that investment and retirement costs, is not assured. TMI-2: As a result of the 1979 TMI-2 accident, individual claims for alleged personal injury (including claims for punitive damages), which are material in amount, were asserted against GPU, Inc. and the GPU Energy companies. Approximately 2,100 of such claims were filed in the US District Court for the Middle District of Pennsylvania. Some of the claims also seek recovery for injuries from alleged emissions of radioactivity before and after the accident. At the time of the TMI-2 accident, as provided for in the Price-Anderson Act, the GPU Energy companies had (a) primary financial protection in the form of insurance policies with groups of insurance companies providing an aggregate of $140 million of primary coverage, (b) secondary financial protection in the form of private liability insurance under an industry retrospective rating plan providing for up to an aggregate of $335 million in premium charges under such plan, and (c) an indemnity agreement with the Nuclear Regulatory Commission (NRC) for up to $85 million, bringing their total financial protection up to an aggregate of $560 million. Under the secondary level, the GPU Energy companies are subject to a retrospective premium charge of up to $5 million per reactor, or a total of $15 million. In 1995, the US Court of Appeals for the Third Circuit ruled that the Price-Anderson Act provides coverage under its primary and secondary levels for punitive as well as compensatory damages, but that punitive damages could not be recovered against the Federal Government under the third level of financial protection. In so doing, the Court of Appeals referred to the "finite fund" (the $560 million of financial protection under the Price-Anderson Act) to which plaintiffs must resort to get compensatory as well as punitive damages. The Court of Appeals also ruled that the standard of care owed by the defendants to a plaintiff was determined by the specific level of radiation which was released into the environment, as measured at the site boundary, rather than as measured at the specific site where the plaintiff was located at the time of the accident (as the defendants proposed). The Court of Appeals also held that each plaintiff still must demonstrate exposure to radiation released during the TMI-2 accident and that such exposure had resulted in injuries. In 1996, the US Supreme Court denied petitions filed by GPU, Inc. and the GPU Energy companies to review the Court of Appeals' rulings. In 1996, the District Court granted a motion for summary judgment filed by GPU, Inc. and the GPU Energy companies, and dismissed the ten initial "test cases," which had been selected for a test case trial as well as all of the remaining 2,100 pending claims. The Court ruled that there was no evidence which created a genuine issue of material fact warranting submission of plaintiffs' claims to a jury. The plaintiffs appealed the District Court's ruling to the Court of Appeals for the Third Circuit. In November 1999, the Third Circuit affirmed the District Court's dismissal of the ten "test cases," but set aside the dismissal of the additional pending claims, remanding them to the District Court for further proceedings. In remanding these claims, the Third Circuit held that the District Court had erred in extending its summary judgment decision to the other plaintiffs and imposing on these plaintiffs the District Court's finding that radiation exposures below 10 rems were too speculative to establish a causal link to cancer. The Court of Appeals stated that the non-test case plaintiffs should be permitted to present their own individual evidence that exposure to radiation from the accident caused their cancers. GPU, Inc. and the GPU Energy companies believe that the Third Circuit has misinterpreted the record before the District Court as it applies to the non-test case plaintiffs, and in November 1999, filed petitions seeking a rehearing and reconsideration of the Court's decision regarding the remaining claims. The "test case" plaintiffs also requested a rehearing of the Court's decision upholding the dismissal of their claims. In January 2000, the Court of Appeals denied both petitions. The "test case" plaintiffs have stated that they intend to seek, and GPU, Inc. and the GPU Energy companies are considering whether to seek, Supreme Court review of the District Court's decision. There can be no assurance as to the outcome of this litigation. 44 GPU 1999 FINANCIAL REPORT 104 GPU, Inc. and the GPU Energy companies believe that any liability to which they might be subject by reason of the TMI-2 accident will not exceed their financial protection under the Price-Anderson Act. Nuclear Plant Retirement Costs: Retirement costs for nuclear plants include decommissioning the radiological portions of the plants and the cast of removal of nonradiological structures and materials. The disposal of spent nuclear fuel is covered separately by contracts with the DOE. In 1995,a consultant to GPUN performed site-specific studies of TMI-2 and Oyster Creek (updated in 1998), that considered various decommissioning methods and estimated the cost of decommissioning the radiological portions and the cost of removal of the nonradiological portions of each plant, using the prompt removal/dismantlement method. GPUN management has reviewed the methodology and assumptions used in these studies, is in agreement with them, and believes the results are reasonable. Under NRC regulations, JCP&L is making periodic payments to complete the funding for Oyster Creek retirement costs by the end of the plant's license term of 2009. The TMI-2 funding completion date is 2014, consistent with TMI-2's remaining in long-term storage. The NRC may require an acceleration of the decommissioning funding for Oyster Creek if the pending sale is not completed and the plant is retired early. The retirement cost estimates under the 1995 site-specific studies, assuming decommissioning of TMI-2 and Oyster Creek in 2014 and 2009, respectively, areas follows (in 1999 dollars): OYSTER (IN MILLIONS) TMI-2 CREEK --------------------------------------------------------------- Radiological decommissioning $435 $591 Nonradiological cost of removal 34* 32 --------------------------------------------------------------- Total $469 $623 --------------------------------------------------------------- * Net of $12.6 million spent as of December 31, 1999. Each of the GPU Energy companies is responsible for retirement costs in proportion to its respective ownership percentage. The ultimate cost of retiring the GPU Energy companies' nuclear facilities may be different from the cost estimates contained in these site-specific studies. Also, the cost estimates contained in these site-specific studies are significantly greater than the decommissioning funding targets established by the NRC. The 1995 Oyster Creek site-specific study was updated in 1998 in response to the previously announced potential early closure of the plant in 2000. An early shutdown would increase the retirement costs shown above to $632 million ($600 million for radiological decommissioning and $32 million for nonradiological cost of removal). Both estimates include substantial spending for an on-site dry storage facility for spent nuclear fuel and significant costs for storing the fuel until the DOE complies with the Nuclear Waste Policy Act of 1982. For additional information, see OTHER COMMITMENTS AND CONTINGENCIES section. Upon the sale of TMI-1, AmerGen assumed all TMI-1 decommissioning liabilities and the GPU Energy companies transferred $320 million to AmerGen for decommissioning. The agreements to sell Oyster Creek to AmerGen provide, among other things, that upon financial closing, JCP&L will transfer $430 million in decommissioning trust funds to AmerGen, which will assume all liability for decommissioning Oyster Creek. The GPU Energy companies charge to depreciation expense and accrue retirement costs based on amounts being collected from customers. Customer collections are contributed to external trust funds. These deposits, including the related earnings, are classified as Nuclear decommissioning trusts, at market on the Consolidated Balance Sheets. The NJBPU has granted JCP&L annual revenues for Oyster Creek retirement costs of $223 million based on the 1995 site-specific study. In August 2000, the recovery of Oyster Creek retirement cost escalates to $34.4 million annually if the plant is retired in 2000. In the Restructuring Orders, the PaPUC granted Met-Ed and Penelec recovery of TMI-1 decommissioning costs of $103.4 million and $67.8 million, respectively, as part of the CTC. These amounts, which are computed on a present value basis, ore based on the 1 995 site-specific study and will be adjusted in Phase Il of Met-Ed and Penelec's restructuring proceedings, once the net proceeds from the generation asset divestiture are determined. In the event JCP&L does not complete the pending sole of Oyster Creek, management believes that any retirement costs, in excess of those currently recognized for ratemaking purposes, should be recoverable from customers. 45 GPU 1999 FINANCIAL REPORT 105 The estimated liabilities for TMI-2 future retirement costs (reflected as Three Mile Island Unit 2 future costs on the Consolidated Balance Sheets) as of December 31, 1999 and December 31, 1998 are $497 million and $484 million, respectively. These amounts are based upon the 1995 site-specific study estimates (in 1999 and 1998 dollars, respectively) discussed above and an estimate for remaining incremental monitored storage costs of $27 million as of December 31, 1999 and $29 million as of December 31, 1998, as a result of TMI-2's entering long-term monitored storage in 1993. The GPU Energy companies are incurring annual incremental monitored storage costs of approximately $1.8 million. Offsetting the $497 million liability at December 31, 1999 is $193 million which management believes is probable of recovery from customers and included in Regulatory assets, net on the Consolidated Balance Sheets, and $355 million in trust funds for TMI-2 and included in Nuclear decommissioning trusts, at market on the Consolidated Balance Sheets. Earnings on trust fund deposits are included in amounts shown on the Consolidated Balance Sheets under Regulatory assets, net. TMI-2 decommissioning costs charged to depreciation expense in 1999 amounted to $14.3 million. The NJBPU has granted JCP&L revenues for TMI-2 retirement costs based on the 1995 site-specific estimates. In addition, JCP&L is recovering its share of TMI-2 incremental monitored storage costs. The PaPUC Restructuring Orders granted Met-Ed and Penelec recovery of TMI-2 decommissioning costs as part of the CTC, but also allowed Met-Ed and Penelec to defer as a regulatory asset those amounts that are above the level provided for in the CTC. At December 31, 1999, the accident-related portion of TMI-2 radiological decommissioning costs is considered to be $77 million, which is based on the 1995 site-specific study estimate (in 1999 dollars). In connection with rate case resolutions at the time, JCP&L, Met-Ed and Penelec have made contributions to irrevocable external trusts relating to their shares of the accident-related portions of the decommissioning liability in the amounts of $15 million, $40 million and $20 million, respectively. These contributions were not recoverable from customers and have been expensed. The GPU Energy companies will not pursue recovery from customers for any amounts contributed in excess of the $77 million accident-related portion referred to above. JCP&L intends to seek recovery far any increases in TMI-2 retirement costs, and Met-Ed and Penelec intend to seek recovery for any increases in the nonaccident-related portion of such costs, but recognize that recovery cannot be assured. Insurance: GPU has insurance (subject to retentions and deductibles) for its operations and facilities including coverage for property damage, liability to employees and third parties, and loss of use and occupancy (primarily incremental replacement power costs). There is no assurance that GPU will maintain all existing insurance coverages. Losses or liabilities that are not completely insured, unless allowed to be recovered through ratemaking, could have a material adverse effect on the financial position of GPU. The decontamination liability, premature decommissioning and property damage insurance coverage for Oyster Creek totals $2.75 billion. In addition, GPU has purchased property and decontamination insurance coverage for TMI-2 totaling $150 million. In accordance with NRC regulations, these insurance policies generally require that proceeds first be used for stabilization of the reactors and then to pay for decontamination and debris removal expenses. Any remaining amounts available under the policies may then be used for repair and restoration costs and decommissioning costs. Consequently, there can be no assurance that in the event of a nuclear incident, property damage insurance proceeds would be available for the repair and restoration of that station. The Price-Anderson Act limits GPU's liability to third parties for a nuclear incident at Oyster Creek to approximately $9.5 billion. Coverage for the first $200 million of such liability is provided by private insurance. The remaining coverage, or secondary financial protection, is provided by retrospective premiums payable by all nuclear reactor owners. Under secondary financial protection, a nuclear incident at any licensed nuclear power reactor in the country, including Oyster Creek, could result in an assessment of up to $88 million per incident, subject to an annual maximum payment of $10 million per incident per reactor. Although TMI-2 is exempt from this assessment, the plant is still covered by the provisions of the Price-Anderson Act. In addition to the retrospective premiums payable under the Price-Anderson Act, the GPU Energy companies are also subject to retrospective premium assessments of up to $10.5 million for insurance policies currently in effect applicable to nuclear operations and facilities. The GPU Energy companies are also subject to other retrospective premium assessments related to policies applicable to TMI-1 prior to the sale of the plant to AmerGen. JCP&L has insurance coverage for incremental replacement power costs should an accident-related outage at Oyster Creek occur. Coverage would commence after a 12-week waiting period at $2.1 million per week for 52 weeks, decreasing to 80% of such amount for the next 110 weeks. Environmental Matters: As a result of existing and proposed legislation and regulations, and ongoing legal proceedings dealing with environmental matters, including but not limited to acid rain, water quality, ambient air quality, global warming, electromagnetic fields, and storage and disposal of hazardous 46 GPU 1999 FINANCIAL REPORT 106 and/or toxic wastes, GPU may be required to incur substantial additional costs to construct new equipment, modify or replace existing and proposed equipment, remediate, decommission or cleanup waste disposal and other sites currently or formerly used by it, including formerly owned manufactured gas plants (MGP), coal mine refuse piles and generation facilities. GPU has been formally notified by the EPA and state environmental authorities that it is among the potentially responsible parties (PRPs) who may be jointly and severally liable to pay for the costs associated with the investigation and remediation at 11 hazardous and/or toxic waste sites. In addition, certain of the GPU companies have been requested to participate in the remediation or supply information to the EPA and state environmental authorities on several other sites for which they hove not been formally named as PRPs, although the EPA and state authorities may nevertheless consider them as PRPs. Certain of the GPU companies have also been named in lawsuits requesting damages (which are material in amount) for hazardous and/or toxic substances allegedly released into the environment. The ultimate cost of remediation will depend upon changing circumstances as site investigations continue, including (a) the existing technology required for site cleanup, (b) the remedial action plan chosen and (c) the extent of site contamination and the portion attributed to the GPU companies involved. In 1997, the EPA filed a complaint against GPU, Inc. in the US District Court for the District of Delaware for enforcement of its Unilateral Order (Order) issued against GPU, Inc. to clean up the former Dover Gas Light Company (Dover) manufactured gas production site (Site) in Dover, Delaware. Dover was part of the AGECO/AGECORP group of companies from 1929 until 1942; GPU, Inc. emerged from the AGECO/AGECORP reorganization proceedings in 1946. All of Dover's common stock, which was sold in 1942 to an unaffiliated entity, was subsequently acquired by Chesapeake, which merged with Dover in 1960. Chesapeake is currently performing the cleanup at the Site. According to the complaint, the EPA is seeking (1) enforcement of the Order against GPU; (2) recovery of its past response costs, (3) a declaratory judgment that GPU is liable for any remaining cleanup costs of the Site and (4) statutory penalties for noncompliance with the Order. The EPA has stated that it has incurred approximately $1 million of past response costs as of December 31, 1999. The EPA estimates the total Site cleanup costs at approximately $4.2 million. Consultants to Chesapeake have estimated the remaining remediation groundwater costs at approximately $10.5 million. In accordance with its penalty policy, and in discussions with GPU, the EPA has demanded penalties calculated at daily rate of $8,800, rather than the statutory maximum of $27,500 per day. At December 31,1999, if the statutory maximum is applied, the total amount of penalties would be approximately $34 million. GPU believes that it has meritorious defenses as to why no penalty should be assessed or if a penalty is assessed, why it should be at a lower daily rate. Chesapeake has also sued GPU, Inc. for contribution to the cleanup of the Dover Site. The US District Court for the District of Delaware has consolidated the case filed by Chesapeake with the case filed by the EPA and discovery is proceeding. There can be no assurance as to the outcome of these proceedings. In connection with the sale of its Seward Generation Station to Sithe, Penelec has assumed up to $6 million of remediation costs associated with certain coal mine refuse piles which are the subject of an earlier consent decree with the Pennsylvania Department of Environmental Protection. Penelec expects recovery of these remediation costs in Phase II of its restructuring proceeding and has recorded a corresponding regulatory asset of approximately $6 million at December 31, 1999. JCP&L has entered into agreements with the New Jersey Department of Environmental Protection for the investigation and remediation of 17 formerly owned MGP sites. JCP&L has also entered into various cost-sharing agreements with other utilities for most of the sites. As of December 31, 1999, JCP&L has spent approximately $36 million in connection with the cleanup of these sites. In addition, JCP&L has recorded on estimated environmental liability of $52 million relating to expected future costs of these sites (as well as two other properties). This estimated liability is based upon ongoing site investigations and remediation efforts, which generally involve capping the sites and pumping and treatment of ground water. Moreover, the cost to clean up these sites could be materially in excess of $52 million due to significant uncertainties, including changes in acceptable remediation methods and technologies. In addition, federal and state law provides for payment by responsible parties for damage to natural resources. In 1997, the NJBPU approved JCP&L's request to establish a Remediation Adjustment Clause for the recovery of MGP remediation costs. As a result of the NJBPU's Summary Order, effective August 1, 1999, the recovery of these costs was transferred to the Societal Benefits Charge. At December 31, 1999, JCP&L had recorded on its Consolidated Balance Sheet a regulatory asset of $44 million. JCP&L is continuing to pursue reimbursement from its insurance carriers for remediation costs already spent and for future estimated costs. In 1994, JCP&L commenced litigation in the New Jersey Superior Court against several of its insurance carriers, relative to these MGP sites, and has settled with all but one of those insurance companies. 47 GPU 1999 FINANCIAL REPORT 107 Other Commitments and Contingencies: Class Action Litigation: GPU Energy: In July 1999, New Jersey experienced a severe heat storm that resulted in major power outages and temporary service interruptions including in JCP&L's service territory. As a result, the NJBPU has initiated an investigation into the reliability of the transmission and distribution systems of all New Jersey utilities and their response to power outages. In addition, two class action lawsuits have been commenced in New Jersey Superior Court against GPU, Inc. and the GPU Energy companies, seeking both compensatory and punitive damages for alleged losses suffered due to service interruptions. The GPU defendants originally requested the Court to stay or dismiss the litigation in deference to the NJBPU's primary jurisdiction. The Court denied the motion, but in January 2000 the Appellate Division agreed to review the Court's decision. In response to GPU's demand for a statement of damages, the plaintiffs have stated that they are seeking damages of $700 million, subject to the results of pre-trial discovery. GPU has notified its insurance carriers who have reserved their rights to contest coverage under GPU's insurance policies for losses which GPU may incur. There can be no assurance as to the outcome of these matters. GPU Electric: As a result of the fire and explosion in September 1998, at the Longford natural gas plant in Victoria, Australia, three class actions have been brought in Australian Federal Court against Esso Australia Limited and its affiliate (Esso), the owner and operator of the plant, for losses suffered due to the lack of natural gas supply and related damages. Plaintiffs claim that Esso was, among other things, negligent in designing, maintaining and operating the Longford plant and also assert claims under various Australian fair trade practices laws. Esso has joined as third party defendants the State of Victoria (State) and various State-owned entities which operated the Victorian gas industry prior to its privatization, including TPA and its affiliate Transmission Pipelines (Assets) Australia (TPAA). GPU, Inc. through GPU GasNet acquired the assets of TPA and the shares of TPAA from the State in June 1999. Esso has also named GPU GasNet as a third party defendant. Under the acquisition agreement with the State, GPU GasNet has indemnified TPA and the State against third party claims. Esso is seeking contribution and indemnity from the third party defendants for any damages for which Esso maybe found liable. In addition, Esso has asserted several separate claims against the State and the farmer State-owned entities for damages, and contends that GPU GasNet assumed TPA's liabilities as part of the State's privatization process. GPU GasNet and TPAA have filed answers denying liability, which could be material and have moved to dismiss portions of Esso's claims. GPU GasNet and TPAA have also notified their insurance carriers of this action. The insurers have reserved their rights to deny coverage. There can be no assurance as to the outcome of this master. Investments and Guarantees: GPU, Inc.: GPU, Inc. has made significant investments in foreign businesses and facilities through its subsidiaries, GPU Electric and the GPUI Group. At December 31, 1999, GPU, Inc.'s investment in GPU Electric and the GPUI Group was $1.06 billion and $232 million, respectively. As of that date, GPU, Inc. has also guaranteed an additional $1.04 billion and $29.9 million (including $8.7 million of guarantees related to domestic operations) of GPU Electric and GPUI Group outstanding obligations, respectively. Although management attempts to mitigate the risks of investing in certain foreign countries by, among other things, securing political risk insurance, GPU faces additional risks inherent to operating in such locations, including foreign currency fluctuations. GPU Electric: Midlands has a 40% ownership interest in a 586 MW power project in Pakistan (the Uch Power Project), which was originally scheduled to begin commercial operation in late 1998, but testing and commercial operation have been delayed. In June 1999, certain Project lenders issued notices of default to the Project sponsors (including Midlands) for, among other things, failure to pay principal and interest under various loon agreements. In November 1999, the Project sponsors and lenders reached an agreement under which repayment of the construction loan will be extended, principal and interest payments deferred, and the sponsors will fund the completion of the plant through the remaining equity contribution commitments. Midlands' investment in the Uch Power Project at December 31, 1999 was approximately $43 million, and its share of the projected completion costs represents an additional $8 million commitment. Cinergy has agreed to fund up to an aggregate of $20 million of the required capital contributions and/or certain future "cash losses" which could be incurred on the Uch Power Project. Cinergy has reimbursed Midlands $3 million of capital contributions as of December 31, 1999, leaving a remaining commitment of up to $17 million. Testing of the plant has begun and the start of commercial operations is now anticipated in 2000. There can be no assurance as to the outcome of this master. As part of the sale of the Midlands' supply business and the purchase of the 50% of Midlands GPU did not already own, certain long-term obligations under natural gas supply contracts were retained. Most of these contracts were at fixed prices in excess of the market price of gas as of December 31, 1999. A liability was previously established far the estimated loss under such contracts, which extend to September 2005. The estimated liability at December 31, 1999 was $55.1 million. 48 GPU 1999 FINANCIAL REPORT 108 GPUI Group: On July 9, 1999, DIAN (the Columbian national tax authority) issued a "Special Requirement" on the Termobarranquilla S.A., Empresa de Servicios Publicos (TEBSA, an investment in which GPU Power has a 29% interest) 1996 income tax return which challenges the exclusion from taxable income of an inflation adjustment related to the value of assets used for power generation. The failure to give notice of this Special Requirement to the US Export Import Bank may be asserted as a technical event of default under the loan agreement. An event of default would entitle TEBSA's lenders to accelerate the payment of outstanding loans of TEBSA and require payment of certain standby equity commitments by TEBSA's shareholders and equity guarantors, which include a subsidiary of GPU Power and GPU, Inc. respectively. The lenders have not asserted that an event of default has occurred or indicated whether they will pursue remedies under the project financing documents. As of December 31, 1999, GPU Power has an investment of approximately $79 million in TEBSA and GPU, Inc. has guaranteed $21.3 million in standby equity commitments. There can be no assurance as to the outcome of these matters. Other: GPU AR has entered into contracts to supply electricity to retail customers through May 2001. In connection with meeting its supply obligations, GPU AR has entered into firm purchase commitments for energy and capacity with payment obligations totaling approximately $27 million as of December 31, 1999. GPU, Inc. has guaranteed up to $19 million of these payments. In accordance with the Nuclear Waste Policy Act of 1982 (NWPA), the GPU Energy companies hove entered into contracts with, and have been paying fees to, the DOE for the future disposal of spent nuclear fuel in a repository or interim storage facility. AmerGen has assumed all liability for disposal costs related to spent fuel generated after its purchase of TMI-1 and has agreed to assume this liability for Oyster Creek following its purchase of that plant. In 1996, the DOE notified the GPU Energy companies and other standard contract holders that it will be unable to begin acceptance of spent nuclear fuel for disposal by 1998, as mandated by the NWPA. The DOE requested recommendations from contract holders for handling the delay. The DOE's inability to accept spent nuclear fuel could have a material impact on GPU's results of operations, as additional costs may be incurred to build and maintain interim on-site storage at Oyster Creek. In June 1997, a consortium of electric utilities, including GPUN, filed a license application with the NRC seeking permission to build on interim above-ground disposal facility for spent nuclear fuel in Utah. There can be no assurance as to the outcome of these matters. GPU, Inc. and consolidated affiliates have approximately 10,800 employees worldwide, of which 6,100 are employed in the US and 3,700 are employed in the United Kingdom. The majority of the US workforce is employed by the GPU Energy companies, of which approximately 4,000 are represented by unions for collective bargaining purposes. In the United Kingdom, approximately 2,800 Midlands employees are represented by unions; terms and conditions of the various bargaining agreements are generally reviewed annually, on April 1. JCP&L, Met-Ed and Penelec's collective bargaining agreements with the International Brotherhood of Electrical Workers expire on October 31,2002, April 30, 2000 and May 14, 2002, respectively. Penelec's collective bargaining agreement with the Utility Workers Union of America expires on June 30,2001. During the normal course of the operation of its businesses, in addition to the matters described above, GPU is from time to time involved in disputes, claims and, in some cases, as a defendant in litigation in which compensatory and punitive damages are sought by the public, customers, contractors, vendors and other suppliers of equipment and services and by employees alleging unlawful employment practices. While management does not expect that the outcome of these matters will have a material effect on GPU's financial position or results of operations, there can be no assurance that this will continue to be the case. 13. Segment Information The following is presented in accordance with Statement of Financial Accounting Standards No. 131, "Disclosures about Segments of an Enterprise and Related Information." GPU's reportable segments are strategic business units that are managed separately due to their different operating and regulatory environments. GPU's management evaluates the performance of its business units based upon income before extraordinary and non-recurring items. For the purpose of providing segment information, domestic electric utility operations (GPU Energy) is comprised of the three electric utility operating companies serving customers in New Jersey and Pennsylvania, as well as GPU Generation, Inc. (sold in late 1999), GPUN, GPU Telcom and GPUS. For additional information on GPU's organizational structure and businesses, see preface to the Notes to Consolidated Financial Statements. 49 GPU 1999 FINANCIAL REPORT 109 Business Segment Data
DEPRECIATION INTEREST CHARGES INCOME TAX OPERATING AND AND PREFERRED EXPENSE/ (IN THOUSANDS) REVENUES AMORTIZATION DIVIDENDS (BENEFIT)(a) ------------------------------------------------------------------------------------------------------------------------ 1999 Domestic Segments: Electric Utility Operations (GPU Energy) $3,685,821 $409,345 $209,769 $238,591 Independ Power Prod (GPU International) 83,434 9,401 1,044 9.478 Electric Retail Energy Sales (GPU AR) 84.681 - - (2,393) ------------------------------------------------------------------------------------------------------------------------ Subtotal 3,853,936 418,746 210,813 245,676 ------------------------------------------------------------------------------------------------------------------------ Foreign Segments: Electric/Gas Utility Operations: (GPU Electric) Electric Distribution-United Kingdom 504,826 52,847 91,433 21,208 Electric Distribution-Argentina 135,938 15,273 23,414 (960) Electric Transmission-Australia 193,366 42,850 110,059 (1,171) Gas Transmission-Australia 31,326 6,933 28,821 (12,156) Independent Power Prod-S. America (GPU Power) 37,732 6,290 3,560 5,152 ------------------------------------------------------------------------------------------------------------------------ Subtotal 903,188 124,193 257,287 12,073 ------------------------------------------------------------------------------------------------------------------------ Corporate and Eliminations - - 14,397 - ------------------------------------------------------------------------------------------------------------------------ Consolidated Total $4,757,124 $542,939 $482,497 $257,749 ======================================================================================================================== 1998 Domestic Segments: Electric Utility Operations (GPU Energy) $3,953,254 $469,623 $241,886 $271,336 Independ Power Prod (GPU International) 72,256 4,560 748 9,103 Electric Retail Energy Sales (GPU AR) 10,938 - - (1,201) ------------------------------------------------------------------------------------------------------------------------ Subtotal 4,036,448 474,183 242,634 279,238 ------------------------------------------------------------------------------------------------------------------------ Foreign Segments: Electric/Gas Utility Operations: (GPU Electric) Electric Distribution-United Kingdom 944 1,226 30,859 (6,489) Electric Transmission-Australia 181,059 40,841 108,227 11,421 Independ Power Prod-S. America (GPU Power) 33,136 5,844 4,219 719 ------------------------------------------------------------------------------------------------------------------------ Subtotal 215,139 47,911 143,305 5,651 ------------------------------------------------------------------------------------------------------------------------ Corporate and Eliminations (2,795) - 3,293 - ------------------------------------------------------------------------------------------------------------------------ Consolidated Total $4,248,792 $522,094 $389,232 $284,889 ======================================================================================================================== 1997 Domestic Segments: Electric Utility Operations (GPU Energy) $4,045,233 $451,009 $249,015 $249,184 Independ Power Prod (GPU International) 38,727 778 713 (3,115) Electric Retail Energy Sales (GPU AR) 1,339 - - (2,576) ------------------------------------------------------------------------------------------------------------------------ Subtotal 4,085,299 451,787 249,728 243,493 ------------------------------------------------------------------------------------------------------------------------ Foreign Segments: Electric/Gas Utility Operations: (GPU Electric) Electric Distribution-United Kingdom - 354 39,312 (44,438) Electric Transmission & Distribution- Australia 30,339 9,412 23,397 (5,184) Independ Power Prod-S. America (GPU Power) 29,174 6,161 3,202 (335) ------------------------------------------------------------------------------------------------------------------------ Subtotal 59,513 15,927 65,911 (49,957) ------------------------------------------------------------------------------------------------------------------------ Corporate and Eliminations (1,433) - 3,682 - ------------------------------------------------------------------------------------------------------------------------ Consolidated Total $4,143,379 $467,714 $319,321 $193,536 ========================================================================================================================
INCOME BEFORE EXTRAORDINARY AND INVESTMENTS NON-RECURRING TOTAL AND CAPITAL (IN THOUSANDS) ITEMS ASSETS EXPENDITURES(b) ---------------------------------------------------------------------------------------------------------- 1999 Domestic Segments: Electric Utility Operations (GPU Energy) $440,983 $13,244,301 $291,391 Independ Power Prod (GPU International) 11,337 359,374 1,225 Electric Retail Energy Sales (GPU AR) (4,558) 24,630 - ---------------------------------------------------------------------------------------------------------- Subtotal 447,762 13,628,305 292,616 ---------------------------------------------------------------------------------------------------------- Foreign Segments: Electric/Gas Utility Operations: (GPU Electric) Electric Distribution-United Kingdom 54,836(c) 4,687,476 727,793 Electric Distribution-Argentina (1,778) 579,907 407,225 Electric Transmission-Australia (6,715) 1,824,309 19,889 Gas Transmission-Australia (39) 795,527 653,747 Independent Power Prod-S. America (GPU Power) 8,116 238,644 30,421 ---------------------------------------------------------------------------------------------------------- Subtotal 54,420 8,125,863 1,839,075 ---------------------------------------------------------------------------------------------------------- Corporate and Eliminations (18,068) (36,086) - ---------------------------------------------------------------------------------------------------------- Consolidated Total $484,114 $21,718,082 $2,131,691 ======================================================================================================================== 1998 Domestic Segments: Electric Utility Operations (GPU Energy) $369,752 $13,298,257 $ 328,418 Independ Power Prod (GPU International) 11,622 397,523 21,375 Electric Retail Energy Sales (GPU AR) (2,231) 2,651 34 ---------------------------------------------------------------------------------------------------------- Subtotal 379,143 13,698,431 349,827 ---------------------------------------------------------------------------------------------------------- Foreign Segments: Electric/Gas Utility Operations: (GPU Electric) Electric Distribution-United Kingdom 37,249(d) 617,737 - Electric Transmission-Australia 18,885 1,788,877 58,549 Independ Power Prod-S. America (GPU Power) 2,499 237,162 59,847 ---------------------------------------------------------------------------------------------------------- Subtotal 58,633 2,643,776 118,396 ---------------------------------------------------------------------------------------------------------- Corporate and Eliminations (11,818) (54,098) - ---------------------------------------------------------------------------------------------------------- Consolidated Total $425,958 $16,288,109 $ 468,223 ======================================================================================================================== 1997 Domestic Segments: Electric Utility Operations (GPU Energy) $388,030 $ 9,850,784 $ 356,416 Independ Power Prod (GPU International) (13,362) 318,592 111,700 Electric Retail Energy Sales (GPU AR) (4,782) 5,122 - ---------------------------------------------------------------------------------------------------------- Subtotal 369,886 10,174,498 468,116 ---------------------------------------------------------------------------------------------------------- Foreign Segments: Electric/Gas Utility Operations: (GPU Electric) Electric Distribution-United Kingdom 78,463(d) 568,997 449 Electric Transmission & Distribution- Australia 12,631 1,967,946 1,800,072 Independ Power Prod-S. America (GPU Power) (2,301) 145,859 - ---------------------------------------------------------------------------------------------------------- Subtotal 88,793 2,682,802 1,800,521 ---------------------------------------------------------------------------------------------------------- Corporate and Eliminations (14,278) (34,366) - ---------------------------------------------------------------------------------------------------------- Consolidated Total $444,401 $12,822,934 $2,268,637 ========================================================================================================================
(a) Represents income lazes on income before extraordinary and non-recurring items. (b) Includes acquisitions, net of cash acquired of $1,671 million in 1999 (Midlands $653 million; Emdersa $369 million; GPU GasNet $649 million) and $1,798 million in 1997 (GPU PowerNet). (c) Includes equity in net income of investee accounted for under the equity method of $74 million, for the period prior to the consolidation of Midlands. (d) Includes equity in net income of investee accounted for under the equity method of $62 million in 1998 and $74 million in 1997. 50 GPU 1999 FINANCIAL REPORT 110 GPU, Inc. and Subsidiary Companies COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS GPU, Inc. owns all the outstanding common stock of three domestic electric utilities -- Jersey Central Power & Light Company (JCP&L), Metropolitan Edison Company (Met-Ed) and Pennsylvania Electric Company (Penelec). The customer service function, transmission and distribution operations and the operations of the remaining non-nuclear generating facilities of these electric utilities are conducting business under the name GPU Energy. JCP&L, Met-Ed and Penelec considered together are referred to as the "GPU Energy companies." The nuclear generation operations of GPU Energy are conducted by GPU Nuclear, Inc. (GPUN). GPU Capital, Inc. and GPU Electric, Inc. and their subsidiaries own, operate and fund the acquisition of electric distribution and gas transmission systems in foreign countries, and are referred to as "GPU Electric." GPU International, Inc. and GPU Power, Inc. and their subsidiaries develop, own and operate generation facilities in the United States (US) and foreign countries and are referred to as the "GPUI Group." Other subsidiaries of GPU, Inc. include G?U Advanced Resources, Inc. (GPU AR), which is involved in retail energy sales; GPU Telcom Services, Inc. (GPU Telcom), which is engaged in telecommunications-related businesses; MYR Group Inc. (MYR), which is a utility infrastructure construction services company; and GPU Service, Inc. (GPUS), which provides legal, accounting, financial and other services to the GPU companies. All of these companies considered together are referred to as "GPU." These notes should be read in conjunction with the notes to consolidated financial statements included in the 1999 Annual Report on Form 10-K. The December 31, 1999 balance sheet data contained in the attached financial statements was derived from audited financial statements. For disclosures required by accounting principles generally accepted in the US, see the 1999 Annual Report on Form 10-K. 1. COMMITMENTS AND CONTINGENCIES COMPETITION AND THE CHANGING REGULATORY ENVIRONMENT Stranded Costs and Regulatory Restructuring Orders: --------------------------------------------------- With the current market price of electricity being below the cost of some utility-owned generation and power purchase commitments, and the ability of customers to choose their energy suppliers, certain costs, which generally would be recoverable in a regulated environment, may not be recoverable in a competitive environment. These costs are generally referred to as stranded costs. In 1998, the Pennsylvania Public Utility Commission (PaPUC) issued Restructuring Orders to Met-Ed and Penelec which, among other things, provide for Met-Ed and Penelec's recovery of a substantial portion of what otherwise would have become stranded costs, and provide for a Phase II proceeding following the completion of their generation divestitures to make a final determination of the extent of that stranded cost recovery. The Pennsylvania Supreme Court has denied an appeal filed by one intervenor in the proceeding. GPU Energy does not know whether the intervenor will seek review by the US Supreme Court. 40 111 On January 31, 2000, Met-Ed and Penelec submitted Phase II Reports to the PaPUC addressing actual net divestiture proceeds and reconciliation of stranded costs pursuant to the 1998 Restructuring Orders. The PaPUC and other parties, which participated in the 1998 Restructuring Orders, are currently reviewing the Reports. There can be no assurance as to the outcome of this matter. In May 1999, the NJBPU issued a Summary Order with respect to JCP&L's rate unbundling, stranded cost and restructuring filings. The Summary Order provides for, among other things, customer choice of electric generation supplier beginning August 1, 1999 and full recovery of stranded costs. The Summary Order did not address the pending sale of Oyster Creek, because at the time the Summary Order was issued, it was uncertain whether the plant would be sold or retired early. JCP&L is awaiting a final order from the NJBPU. During 1999, the NJBPU issued final electric restructuring and generation-related securitization orders to Public Service Electric and Gas Company (PSE&G), a non-affiliated utility. Several parties appealed these orders on a variety of grounds, including the use of deferred accounting associated with above market NUG costs and the Societal Benefit Charge, which includes recovery of nuclear decommissioning costs. In April 2000, the Appellate Division of the New Jersey Superior Court affirmed the orders. The Appellate Division's decision has been appealed to the New Jersey Supreme Court which is not expected to issue a decision before January 2001. While JCP&L's Summary Order has not been appealed, JCP&L is unable to determine the impact, if any, the appeals to PSE&G's orders will have on its restructuring order and petition for securitization or its use of deferred accounting. As a result of the NJBPU and the PaPUC restructuring decisions, the GPU Energy companies are required to supply electricity to customers who do not choose an alternate supplier. Given that the GPU Energy companies have essentially divested their generation business, there will be increased market risks associated with supplying that electricity, since the GPU Energy companies will have to supply electricity to non-shopping customers entirely from contracted and open market purchases. While JCP&L is permitted to recover reasonable and prudently incurred costs associated with providing basic generation service to non-shopping customers, Met-Ed and Penelec are generally unable to recover their energy costs in excess of established rate caps. Management has implemented an energy risk management program, but there can be no assurance that the GPU Energy companies will be able to fully recover the costs to supply electricity to customers who do not choose an alternate supplier. Generation Agreements: ---------------------- The evolving competitive generation market has created uncertainty regarding the forecasting of the GPU Energy companies' energy supply needs, which has caused the GPU Energy companies to seek shorter-term agreements offering more flexibility. The GPU Energy companies' supply plan focuses on short- to intermediate-term commitments (one month to three years) covering times of expected high energy price volatility (that is, peak demand periods) and reliance on spot market purchases during other periods. 41 112 The GPU Energy companies have entered into agreements with third party suppliers to purchase capacity and energy. Payments pursuant to these agreements, which include firm commitments as well as certain assumptions regarding, among other things, call/put arrangements and the timing of the pending Oyster Creek sale, are estimated to be $650 million in 2000, $651 million in 2001, $323 million in 2002, $138 million in 2003 and $44 million in 2004. Pursuant to the mandates of the federal Public Utility Regulatory Policies Act and state regulatory directives, the GPU Energy companies have been required to enter into power purchase agreements with non-utility generators (NUGs) for the purchase of energy and capacity, which agreements have remaining terms of up to 20 years. The rates under virtually all of the GPU Energy companies' NUG agreements are substantially in excess of current and projected prices from alternative sources. The following table shows actual payments from 1998 through June 30, 2000, and estimated payments thereafter through 2005: Payments Under NUG Agreements (in millions) Total JCP&L Met-Ed Penelec 1998 788 403 174 211 1999 774 388 167 219 2000 741 385 141 215 2001 733 392 138 203 2002 736 394 141 201 2003 752 400 145 207 2004 767 404 150 213 2005 751 392 153 206 The NJBPU Summary Order provides JCP&L assurance of full recovery of its NUG costs (including above-market NUG costs and certain buyout costs), whereas the PaPUC Restructuring Orders provide Met-Ed and Penelec assurance of full recovery of their above-market NUG costs and certain NUG buyout costs. The GPU Energy companies have recorded, on a present value basis, a total liability of $3.1 billion (JCP&L $1.5 billion; Met-Ed $0.7 billion; Penelec $0.9 billion) on the Consolidated Balance Sheets for above-market NUG costs which is offset by a corresponding regulatory asset. The GPU Energy companies are continuing efforts to reduce the above-market costs of these agreements. There can be no assurance as to the extent to which these efforts will be successful. In 1997, the NJBPU approved a Stipulation of Final Settlement which, among other things, provided for the recovery of costs associated with the buyout of the Freehold Cogeneration power purchase agreement (Freehold buyout). The NJBPU approved the cost recovery of up to $135 million, over a seven-year period, on an interim basis subject to refund. The NJBPU's Summary Order provides for the continued recovery of the Freehold buyout in the Market Transition Charge (MTC), but has not altered the interim nature of such recovery, pending a final decision by the NJBPU. There can be no assurance as to the outcome of this matter. ACCOUNTING MATTERS JCP&L, in 1999, and Met-Ed and Penelec in 1998, discontinued the application of Statement of Financial Accounting Standards No. 71 (FAS 71), 42 113 "Accounting for the Effects of Certain Types of Regulation," and adopted the provisions of Statement of Financial Accounting Standards No. 101, "Regulated Enterprises - Accounting for the Discontinuation of Application of FASB Statement No. 71," and Emerging Issues Task Force (EITF) Issue 97-4, "Deregulation of the Pricing of Electricity - Issues Related to the Application of FAS 71 and FAS 101", with respect to their electric generation operations. The transmission and distribution portion of the GPU Energy companies' operations continue to be subject to the provisions of FAS 71. Regulatory assets, net as reflected in the June 30, 2000 and December 31, 1999 Consolidated Balance Sheets in accordance with the provisions of FAS 71 and EITF Issue 97-4 were as follows: GPU, Inc. and Subsidiary Companies
(in thousands) ----------------------------- June 30, December 31, ------------ ------------- Market transition charge (MTC) / basic generation service $2,287,449 $2,359,529 Competitive transition charge (CTC) 756,406 803,064 Reserve for generation divestiture 530,912 536,904 Power purchase contract loss not in CTC 369,290 369,290 Income taxes recoverable through future rates, net 283,636 280,268 Costs recoverable through distribution rates 281,363 296,842 Three Mile Island Unit 2 (TMI-2) decommissioning costs 100,869 100,794 Societal benefits charge 100,643 116,941 Net divestiture proceeds recoverable through MTC 58,077 37,542 Above-market deferred NUG costs (196,276) (252,348) Other, net 67,584 67,420 ---------- ---------- Total regulatory assets, net $4,639,953 $4,716,246 ========== ========== JCP&L MTC-basic generation service $2,287,449 $2,359,529 Costs recoverable through distribution rates 281,363 296,842 Societal benefits charge 100,643 116,941 Net divestiture proceeds recoverable through MTC 58,077 37,542 ---------- ---------- Total regulatory assets, net $2,727,532 $2,810,854 ========== ========== Met-Ed CTC $ 583,441 $ 591,316 Power purchase contract loss not in CTC 271,270 271,270 Reserve for generation divestiture 142,179 137,037 Income taxes recoverable through future rates, net 122,955 115,713 TMI-2 decommissioning costs 64,608 65,455 Other, net 67,711 52,074 ---------- ---------- Total regulatory assets, net $1,252,164 $1,232,865 ========== ========== Penelec Reserve for generation divestiture $ 388,733 $ 399,867 Above-market deferred NUG costs (213,312) (252,893) CTC 172,965 211,748 Income taxes recoverable through future rates, net 160,681 164,555 Power purchase contract loss not in CTC 98,020 98,020 Other, net 53,170 51,230 ---------- ---------- Total regulatory assets, net $ 660,257 $ 672,527 ========== ==========
43 114 Statement of Financial Accounting Standards 133, "Accounting for Derivative Instruments and Hedging Activities", as amended by FAS 137, "Accounting for Derivative Instruments and Hedging Activities - Deferral of the Effective Date of FASB Statement No. 133" and FAS 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities - An Amendment of FASB Statement No. 133" (collectively, FAS 133), establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. In general, FAS 133 requires that companies recognize all derivatives as either assets or liabilities on the balance sheet and measure those instruments at fair value. FAS 133 (as amended) excludes from its scope certain contracts that qualify as normal purchases and sales. To qualify for this exclusion, it must be probable that the contract will result in physical delivery. GPU's use of derivative instruments is intended to manage the risks of commodity price, interest rate and foreign currency fluctuations, and may include such transactions as electricity and natural gas forwards and futures contracts, foreign currency swaps, interest rate swaps and options. GPU does not intend to hold or issue derivative instruments for trading purposes. To the extent that GPU's energy-related contracts fall within the scope of FAS 133, GPU will be required to include them on its balance sheet at fair value, and recognize the subsequent changes in fair value as either gains or losses in earnings or report them as a component of other comprehensive income, depending upon their intended use and designation as a hedge. GPU will adopt this statement on January 1, 2001 and is currently in the process of evaluating the impact of its implementation. NUCLEAR FACILITIES Investments: ------------ In December 1999, the GPU Energy companies sold TMI-1 to AmerGen for approximately $100 million. In addition, in October 1999, JCP&L agreed to sell Oyster Creek to AmerGen for $10 million and reimbursement of the cost (estimated at $88 million) of the next refueling outage. JCP&L's net investment, including nuclear fuel, in Oyster Creek as of June 30, 2000 and December 31, 1999 was $10 million, reflecting the impairment write-down from the pending sale. JCP&L, Met-Ed and Penelec jointly own TMI-2, which was damaged during a 1979 accident, in the percentages of 25%, 50% and 25%. JCP&L's net investment in TMI-2 as of June 30, 2000 and December 31, 1999 was $58 million and $61 million, respectively. JCP&L is collecting revenues for TMI-2 on a basis which provides for the recovery of its remaining investment in the plant by 2008. Met-Ed and Penelec's remaining investments in TMI-2 were written off in 1998 after receiving the PaPUC's Restructuring Orders. TMI-2: ------ As a result of the 1979 TMI-2 accident, individual claims for alleged personal injury (including claims for punitive damages), which are material in amount, were asserted against GPU, Inc. and the GPU Energy companies. Approximately 2,100 of such claims were filed in the US District Court for the Middle District of Pennsylvania. Some of the claims also seek recovery for injuries from alleged emissions of radioactivity before and after the accident. 44 115 At the time of the TMI-2 accident, as provided for in the Price-Anderson Act, the GPU Energy companies had (a) primary financial protection in the form of insurance policies with groups of insurance companies providing an aggregate of $140 million of primary coverage, (b) secondary financial protection in the form of private liability insurance under an industry retrospective rating plan providing for up to an aggregate of $335 million in premium charges under such plan and (c) an indemnity agreement with the Nuclear Regulatory Commission (NRC) for up to $85 million, bringing their total financial protection up to an aggregate of $560 million. Under the secondary level, the GPU Energy companies are subject to a retrospective premium charge of up to $5 million per reactor, or a total of $15 million. In 1995, the US Court of Appeals for the Third Circuit ruled that the Price-Anderson Act provides coverage under its primary and secondary levels for punitive as well as compensatory damages, but that punitive damages could not be recovered against the Federal Government under the third level of financial protection. In so doing, the Court of Appeals referred to the "finite fund" (the $560 million of financial protection under the Price-Anderson Act) to which plaintiffs must resort to get compensatory as well as punitive damages. The Court of Appeals also ruled that the standard of care owed by the defendants to a plaintiff was determined by the specific level of radiation which was released into the environment, as measured at the site boundary, rather than as measured at the specific site where the plaintiff was located at the time of the accident (as the defendants proposed). The Court of Appeals also held that each plaintiff still must demonstrate exposure to radiation released during the TMI-2 accident and that such exposure had resulted in injuries. In 1996, the US Supreme Court denied petitions filed by GPU, Inc. and the GPU Energy companies to review the Court of Appeals' rulings. In 1996, the District Court granted a motion for summary judgment filed by GPU, Inc. and the GPU Energy companies, and dismissed the ten initial "test cases," which had been selected for a test case trial as well as all of the remaining 2,100 pending claims. The Court ruled that there was no evidence which created a genuine issue of material fact warranting submission of plaintiffs' claims to a jury. The plaintiffs appealed the District Court's ruling to the Court of Appeals for the Third Circuit. In November 1999, the Third Circuit affirmed the District Court's dismissal of the ten "test cases," but set aside the dismissal of the additional pending claims, remanding them to the District Court for further proceedings. In remanding these claims, the Third Circuit held that the District Court had erred in extending its summary judgment decision to the other plaintiffs and imposing on these plaintiffs the District Court's finding that radiation exposures below 10 rems were too speculative to establish a causal link to cancer. The Court of Appeals stated that the non-test case plaintiffs should be permitted to present their own individual evidence that exposure to radiation from the accident caused their cancers. In June 2000, the US Supreme Court denied petitions by GPU, Inc., the GPU Energy companies and the plaintiffs. GPU, Inc. and the GPU Energy companies believe that any liability to which they might be subject by reason of the TMI-2 accident will not exceed their financial protection under the Price-Anderson Act. 45 116 NUCLEAR PLANT RETIREMENT COSTS Retirement costs for nuclear plants include decommissioning the radiological portions of the plants and the cost of removal of nonradiological structures and materials. The disposal of spent nuclear fuel is covered separately by contracts with the US Department of Energy (DOE). In 1995, a consultant to GPUN performed site-specific studies of TMI-2 and Oyster Creek (updated in 1998), that considered various decommissioning methods and estimated the cost of decommissioning the radiological portions and the cost of removal of the nonradiological portions of each plant, using the prompt removal/dismantlement method. GPUN management has reviewed the methodology and assumptions used in these studies, is in agreement with them, and believes the results are reasonable. Under NRC regulations, JCP&L is making periodic payments to complete the funding for Oyster Creek retirement costs by the end of the plant's license term of 2009. The TMI-2 funding completion date is 2014, consistent with TMI-2 remaining in long-term storage. The NRC may require an acceleration of the decommissioning funding for Oyster Creek if the pending sale is not completed and the plant is retired early. The retirement cost estimates under the 1995 site-specific studies, assuming decommissioning of TMI-2 and Oyster Creek in 2014 and 2009, respectively, are $443 million and $601 million for radiological decommissioning and $35 million and $33 million for non-radiological removal costs (net of $12.6 million spent as of June 30, 2000) (in 2000 dollars) Each of the GPU Energy companies is responsible for retirement costs in proportion to its respective ownership percentage. The ultimate cost of retiring the GPU Energy companies' nuclear facilities may be different from the cost estimates contained in these site-specific studies. Also, the cost estimates contained in these site-specific studies are significantly greater than the decommissioning funding targets established by the NRC. The 1995 Oyster Creek site-specific study was updated in 1998 in response to the previously announced potential early closure of the plant in 2000. An early shutdown would increase the retirement costs shown above to $643 million ($610 million for radiological decommissioning and $33 million for nonradiological cost of removal). Both estimates include substantial spending for an on-site dry storage facility for spent nuclear fuel and significant costs for storing the fuel until the DOE complies with the Nuclear Waste Policy Act of 1982. For additional information, see OTHER COMMITMENTS AND CONTINGENCIES section. The agreements to sell Oyster Creek to AmerGen provide, among other things, that upon financial closing, JCP&L will transfer $430 million in decommissioning trust funds to AmerGen, which will assume all liability for decommissioning Oyster Creek. . The NJBPU has granted JCP&L annual revenues for Oyster Creek retirement costs of $22.5 million based on the 1995 site-specific study. In August 2000, the recovery of Oyster Creek retirement costs escalates to $34.4 million annually if the plant is retired in 2000. In the event JCP&L does not complete the pending sale of Oyster Creek, management believes that any retirement costs, in excess of those currently recognized for ratemaking purposes, should be recoverable from customers. 46 117 The estimated liabilities for TMI-2 future retirement costs (reflected as Three Mile Island Unit 2 future costs on the Consolidated Balance Sheets) as of June 30, 2000 and December 31, 1999 are $504 million (JCP&L $126 million; Met-Ed $252 million; Penelec $126 million) and $497 million (JCP&L $124 million; Met-Ed $249 million; Penelec $124 million), respectively. These amounts are based upon the 1995 site-specific study estimates (in 2000 and 1999 dollars, respectively) discussed above and an estimate for remaining incremental monitored storage costs of $27 million (JCP&L $7 million; Met-Ed $13 million; Penelec $7 million) as of June 30, 2000 and December 31, 1999, as a result of TMI-2 entering long-term monitored storage in 1993. Offsetting the $504 million liability as of June 30, 2000 is $182 million (JCP&L $13 million; Met-Ed $133 million; Penelec $36 million), which management believes is probable of recovery from customers and included in Regulatory assets, net on the Consolidated Balance Sheets, and $366 million (JCP&L $116 million; Met-Ed $151 million; Penelec $99 million) in trust funds for TMI-2 and included in Nuclear decommissioning trusts, at market on the Consolidated Balance Sheets. The NJBPU has granted JCP&L revenues for TMI-2 retirement costs based on the 1995 site-specific estimates. In addition, JCP&L is recovering its share of TMI-2 incremental monitored storage costs. The PaPUC Restructuring Orders granted Met-Ed and Penelec recovery of TMI-2 decommissioning costs as part of the CTC, but also allowed Met-Ed and Penelec to defer as a regulatory asset those amounts that are above the level provided for in the CTC. As of June 30, 2000, the accident-related portion of TMI-2 radiological decommissioning costs is considered to be $78 million (JCP&L $19.5 million; Met-Ed $39 million; Penelec $19.5 million), which is based on the 1995 site-specific study estimates (in 2000 dollars). JCP&L intends to seek recovery for any increases in TMI-2 retirement costs, and Met-Ed and Penelec intend to seek recovery for any increases in the nonaccident-related portion of such costs, but recognize that recovery cannot be assured. INSURANCE GPU has insurance (subject to retentions and deductibles) for its operations and facilities including coverage for property damage, liability to employees and third parties, and loss, of use and occupancy (primarily incremental replacement power costs). There is no assurance that GPU will maintain all existing insurance coverages. Losses or liabilities that are not completely insured, unless allowed to be recovered through ratemaking, could have a material adverse effect on the financial position of GPU. The decontamination liability, premature decommissioning and property damage insurance coverage for Oyster Creek totals $2.75 billion. In addition, GPU has purchased property and decontamination insurance coverage for TMI-2 totaling $150 million. In accordance with NRC regulations, these insurance policies generally require that proceeds first be used for stabilization of the reactors and then to pay for decontamination and debris removal expenses. Any remaining amounts available under the policies may then be used for repair and restoration costs and decommissioning costs. Consequently, there can be no assurance that in the event of a nuclear 47 118 incident, property damage insurance proceeds would be available for the repair and restoration of that station. The Price-Anderson Act limits GPU's liability to third parties for a nuclear incident at Oyster Creek to approximately $9.5 billion. Coverage for the first $200 million of such liability is provided by private insurance. The remaining coverage, or secondary financial protection, is provided by retrospective premiums payable by all nuclear reactor owners. Under secondary financial protection, a nuclear incident at any licensed nuclear power reactor in the country, including Oyster Creek, could result in an assessment of up to $88 million per incident, subject to an annual maximum payment of $10 million per incident per reactor. Although TMI-2 is exempt from this assessment, the plant is still covered by the provisions of the Price-Anderson Act. In addition to the retrospective premiums payable under the Price-Anderson Act, the GPU Energy companies are also subject to retrospective premium assessments of up to $9.5 million for insurance policies currently in effect applicable to nuclear operations and facilities. The GPU Energy companies are also subject to other retrospective premium assessments related to policies applicable to TMI-1 and Oyster Creek (GPU anticipates the sale of Oyster Creek to be completed in August 2000) prior to their sales to AmerGen. JCP&L has insurance coverage for incremental replacement power costs should an accident-related outage at Oyster Creek occur. Coverage would commence after a 12-week waiting period at $2.1 million per week for 52 weeks, decreasing to 80% of such amount for the next 110 weeks. ENVIRONMENTAL MATTERS As a result of existing and proposed legislation and regulations, and ongoing legal proceedings dealing with environmental matters, including but not limited to acid rain, water quality, ambient air quality, global warming, electromagnetic fields, and storage and disposal of hazardous and/or toxic wastes, GPU may be required to incur substantial additional costs to construct new equipment, modify or replace existing and proposed equipment, remediate, decommission or cleanup waste disposal and other sites currently or formerly used by it, including formerly owned manufactured gas plants (MGP), coal mine refuse piles and generation facilities. In addition, federal and state law provides for payment by responsible parties for damage to natural resources. GPU has been formally notified by the Environmental Protection Agency (EPA) and state environmental authorities that it is among the potentially responsible parties (PRPs) who may be jointly and severally liable to pay for the costs associated with the investigation and remediation at hazardous and/or toxic waste sites in the following number of instances (in some cases, more than one company is named for a given site): JCP&L MET-ED PENELEC GPUN GPU, INC. TOTAL ----- ------ ------- ---- --------- ----- 6 4 2 1 1 11 In addition, certain of the GPU companies have been requested to participate in the remediation or supply information to the EPA and state environmental authorities on several other sites for which they have not been 48 119 formally named as PRPs, although the EPA and/or state authorities may nevertheless consider them as PRPs. Certain of the GPU companies have also been named in lawsuits requesting damages (which are material in amount) for hazardous and/or toxic substances allegedly released into the environment. As of June 30, 2000, a liability of approximately $6 million was recorded for nine PRP sites where it is probable that a loss has been incurred and the amount could be reasonably estimated. The ultimate cost of remediation of all these and other hazardous waste sites will depend upon changing circumstances as site investigations continue, including (a) the existing technology required for site cleanup, (b) the remedial action plan chosen and (c) the extent of site contamination and the portion attributed to the GPU companies involved. In 1997, the EPA filed a complaint against GPU, Inc. in the US District Court for the District of Delaware for enforcement of its Unilateral Order (Order) issued against GPU, Inc. to clean up the former Dover Gas Light Company (Dover) manufactured gas production site (Site) in Dover, Delaware. Dover was part of the AGECO/AGECORP group of companies from 1929 until 1942; GPU, Inc. emerged from the AGECO/AGECORP reorganization proceedings in 1946. All of Dover's common stock, which was sold in 1942 to an unaffiliated entity, was subsequently acquired by Chesapeake Utilities Corporation (Chesapeake), which merged with Dover in 1960. Chesapeake is currently performing the cleanup at the Site. According to the complaint, the EPA is seeking (1) enforcement of the Order against GPU; (2) recovery of its past response costs; (3) a declaratory judgment that GPU is liable for any remaining cleanup costs of the Site; and (4) statutory penalties for noncompliance with the Order. The EPA has stated that it has incurred approximately $1 million of past response costs as of December 31, 1999. The EPA estimates the total Site cleanup costs at approximately $4.2 million. Consultants to Chesapeake have estimated the remaining remediation ground water costs to be approximately $11.3 million to $19 million. In accordance with its penalty policy, and in discussions with GPU, the EPA has demanded penalties calculated at a daily rate of $8,800, rather than the statutory maximum of $27,500 per day. As of June 30, 2000, if the statutory maximum were applied, the total amount of penalties would be approximately $39 million. GPU believes that it has meritorious defenses to the imposition of penalties, or that if a penalty is assessed, it should be at a lower daily rate. Chesapeake has also sued GPU, Inc. for contribution to the cleanup of the Dover Site. The US District Court for the District of Delaware has consolidated the case filed by Chesapeake with the case filed by the EPA and discovery is proceeding. There can be no assurance as to the outcome of these proceedings. In connection with the 1999 sale of its Seward Generation Station to Sithe Energies, Penelec has assumed up to $6 million of remediation costs associated with certain coal mine refuse piles which are the subject of an earlier consent decree with the Pennsylvania Department of Environmental Protection. Penelec expects recovery of these remediation costs in Phase II of its restructuring proceeding and has recorded a corresponding regulatory asset. JCP&L has entered into agreements with the NJDEP for the investigation and remediation of 17 formerly owned MGP sites. JCP&L has also entered into various cost-sharing agreements with other utilities for most of the sites. As of June 30, 2000, JCP&L has spent approximately $38 million in connection 49 120 with the cleanup of these sites. In addition, JCP&L has recorded an estimated environmental liability of $54 million relating to expected future costs of these sites (as well as two other properties) . This estimated liability is based upon ongoing site investigations and remediation efforts, which generally involve capping the sites and pumping and treatment of ground water. Moreover, the cost to clean up these sites could be materially in excess of the $54 million due to significant uncertainties, including changes in acceptable remediation methods and technologies. In 1997, the NJBPU approved JCP&L's request to establish a Remediation Adjustment Clause for the recovery of MGP remediation costs. As a result of the NJBPU's Summary Order, effective August 1, 1999, the recovery of these costs was transferred to the Societal Benefits Charge. As of June 30, 2000, JCP&L had recorded on its Consolidated Balance Sheet a regulatory asset of $46 million. JCP&L is continuing to pursue reimbursement from its insurance carriers for remediation costs already spent and for future estimated costs. In 1994, JCP&L filed a complaint with the Superior Court of New Jersey against several of its insurance carriers, relative to these MGP sites, and has settled with all but one of those insurance carriers. OTHER COMMITMENTS AND CONTINGENCIES Class Action Litigation: ------------------------ GPU Energy In July 1999, New Jersey experienced a severe heat storm that resulted in major power outages and temporary service interruptions, which affected JCP&L's service territory. As a result, the NJBPU initiated an investigation into the reliability of the transmission and distribution systems of all New Jersey utilities and their response to power outages. This investigation was completed in April 2000, resulting in Phase I and Phase II Reports. Both Reports contain, among other things, recommendations as to certain actions that should be undertaken by JCP&L, and were adopted by NJBPU orders requiring JCP&L to act on the recommendations and to report back on such implementation. JCP&L has begun to act on these recommendations. The NJBPU order adopting the Phase II Report stated that there is not a prima facie case demonstrating that overall JCP&L provided unsafe, inadequate or improper service to its customers. In addition, two class action lawsuits were commenced in New Jersey Superior Court in July 1999 against GPU, Inc. and JCP&L, seeking both compensatory and punitive damages for alleged losses suffered due to service interruptions. The GPU defendants originally requested the Court to stay or dismiss the litigation in deference to the NJBPU's primary jurisdiction. The Court denied the motion, consolidated the two actions, and certified them as class actions on behalf of a class that includes JCP&L customers as well as "all dependents, tenants, employees, and other intended beneficiaries of customers who suffered damages as a result" of the outages. In January 2000, the Appellate Division agreed to review the trial court's decision on primary jurisdiction. In June 2000, the Appellate Division affirmed the trial court's decision recognizing, however, that future developments in the case may require a reference of certain issues to the NJBPU. The Appellate Division also stated that the NJBPU's findings could be probative but not determinative of at least some issues in the 50 121 litigation. In response to GPU's demand for a statement of damages, the plaintiffs have stated that they are seeking damages of $700 million, subject to the results of pre-trial discovery. GPU has notified its insurance carriers of the plaintiffs' allegations. The primary insurance carrier has stated that while the substance of the plaintiffs' allegations are covered under GPU's policy, it is reserving its rights concerning coverage as circumstances develop. There can be no assurance as to the outcome of these matters. GPU Electric As a result of the September 1998 fire and explosion at the Longford natural gas plant in Victoria, Australia, Victorian gas users (plaintiffs) have brought a class action in the Australian Federal Court against Esso Australia Limited and its affiliate (Esso), the owner and operator of the plant, for losses suffered due to the lack of natural gas supply and related damages. The plaintiffs claim that Esso was, among other things, negligent in designing, maintaining and operating the Longford plant and also assert claims under Australian fair trade practices law. Esso has joined as third party defendants the State of Victoria (State) and various State-owned entities which operated the Victorian gas industry prior to its privatization, including Transmission Pipelines Australia (TPA) and its affiliate Transmission Pipelines (Assets) Australia (TPAA) . GPU, Inc., through GPU GasNet, acquired the assets of TPA and the shares of TPAA from the State in June 1999. Esso asserts that the State and the gas industry were negligent in that, among other things, they failed to ensure that the gas system would provide a secure supply of gas to users and also asserts claims under the Australian fair trade practices law. In addition, GPU GasNet and other private entities (Buyers) that purchased the Victorian gas assets from the State have joined Esso as third party defendants. Esso asserts that if the gas industry is liable as alleged, that liability has been transferred to the Buyers as part of the State's privatization process. Under the acquisition agreement with the State, GPU GasNet has indemnified TPA and the State against third party claims arising out of, among other things, the operation of TPA'S business. TPA and the State have commenced proceedings against GPU GasNet to enforce the indemnity in respect of any liability that may flow to TPA as a result of Esso's claim. GPU GasNet and TPAA have filed answers denying liability to Esso, the State and TPA, which could be material. GPU GasNet and TPAA have notified their insurance carriers of this action. The insurers have reserved their rights to deny coverage. There can be no assurance as to the outcome of this matter. Investments and Guarantees: --------------------------- GPU, Inc. GPU, Inc. has made significant investments in foreign businesses and facilities through its subsidiaries, GPU Electric and the GPUI Group. As of June 30, 2000, GPU, Inc. `s investment in GPU Electric and the GPUI Group was $569 million and $252 million, respectively. As of that date, GPU, Inc. has also guaranteed an additional $998 million and $30 million (including $9 51 122 million of guarantees related to domestic operations) of GPU Electric and GPUI Group outstanding obligations, respectively. Although management attempts to mitigate the risks of investing in certain foreign countries by, among other things, securing political risk insurance, GPU faces additional risks inherent to operating in such locations, including foreign currency fluctuations. GPU Electric In June 2000, GPU sold GPU PowerNet for A$2.1 billion (US$1.26 billion). For further information, see Note 2, Acquisitions and Dispositions. GPU had previously announced its intention to sell all, or at least 50%, of the Australian companies, for which it paid approximately US $1.9 billion (GPU PowerNet) and US $675 million (GPU GasNet) in 1997 and 1999, respectively. GPU is still considering the possible sale of GPU GasNet. On June 2, 2000, repayment of approximately $218 million of maturing GPU GasNet bank debt was extended to September 2, 2000. GPU GasNet may further extend this loan to October 2, 2000. GPU GasNet is in the process of establishing a commercial paper program and a medium term note program to refinance this debt. GPU, Inc. has agreed to guarantee this loan, under certain conditions, if it is not repaid by August 25, 2000. Midlands Electricity plc (Midlands) (conducting business under the name GPU Power UK) has a 40% equity interest in a 586 MW power project in Pakistan (the Uch Power Project), which was originally scheduled to begin commercial operation in late 1998. In June 1999, certain Project lenders for the Uch Power Project issued notices of default to the Project sponsors (including Midlands for, among other things, failure to pay principal and interest under various loan agreements. In November 1999, the Project sponsors and lenders reached an agreement under which repayment of the construction loan will be extended, principal and interest payments deferred, and the sponsors will fund the completion of the plant through the remaining equity contribution commitments. Testing of the plant has begun, but the start of commercial operations has been further delayed pending the resolution of certain technical problems, which are being addressed. Uch has renegotiated several of the project agreements with the Government of Pakistan and its agencies. In April 2000, Uch signed a Memorandum of Understanding with Pakistani authorities, in which it agreed, among other things, to accept a reduction in the power purchase tariff averaging approximately 8% over the project term. The agreement includes options to extend the term of the project from 23 to 30 years. Commercial operations are now planned to commence by the end of August, 2000. There remains a risk that project revenues may be delayed due to the poor economic situation in Pakistan. GPU's investment in the Uch Power Project as of June 30, 2000 was approximately $37.1 million, plus a guarantee letter of credit of $5.2 million, and its share of the projected completion costs represents an additional $3.9 million commitment. Cinergy Corp. has agreed to fund up to an aggregate of $20 million of the required capital contributions and/or certain future "cash losses," which could be incurred on the Uch Power Project. Cinergy has reimbursed GPU Electric for $4.9 million of capital contributions through June 30, 2000, leaving a remaining commitment of up to $15.1 million. There can be no assurance as to the outcome of this matter. As part of the 1999 sale of the GPU Power UK supply business and the purchase of the 50% of GPU Power UK that GPU did not already own, certain 52 123 long-term purchase obligations under natural gas supply contracts were retained. Most of these contracts, which extend to September 2005, were at fixed prices in excess of the market price of gas, and a liability was established for the estimated loss under such contracts. However, as a result of increasing gas prices during the second quarter of 2000, GPU Power UK was able to enter into matching forward sale contracts for the majority of the gas purchases, resulting in a reduction in the estimated liability and a credit to income of $15.9 million pre-tax. The estimated liability as of June 30, 2000 was $25 million, of which approximately $19 million was "locked-in" under new forward sale contracts. GPU Power UK was still exposed to future price risk on the remaining $6 million of liabilities as of June 30, 2000. In a recent English court decision involving two unaffiliated utilities (National Grid and National Power), the court held that utilities improperly used a pension plan surplus in the UK Electricity Supply Pension Scheme to eliminate scheduled payments in respect of early retirement costs and employer contributions. The Court found that, in the case of National Grid and National Power, procedures had not been strictly followed, and as such, a liability may now exist. At a subsequent hearing, the Court refused to consider the validity or effectiveness of retrospective amendments to the plan. National Grid and National Power have appealed the Court's decision to the House of Lords. Pending the outcome of the Appeal, the requirement for any payments has been stayed. If a similar complaint were to be made against GPU Power UK, GPU Power UK's potential liability is estimated to be a maximum of British pound 63 million (US$96 million), exclusive of any applicable interest charges or penalties. The GPU Power UK section of the Electricity Supply Pension Scheme remains in substantial surplus and any payment to the plan that might ultimately prove to be necessary would be accounted for as an increase in pension assets, and would not have an immediate impact on income. However, any related penalties or interest (which could be assessed, though none are currently proposed) would adversely affect income. There can be no assurance as to the outcome of this matter. Emdersa's operating companies are subject to a number of government claims related to Value-added tax liabilities and to Social Security taxes collected in their electric rates, which aggregate approximately $22 million. The claims are generally related to transitional issues surrounding the privatization of Argentina's electricity industry. There can be no assurance as to the outcome of these matters. GPUI Group On July 9, 1999, DIAN (the Colombian national tax authority) issued a "Special Requirement" on the Termobarranquilla S.A., Empresa de Servicios Publicos (TEBSA) 1996 income tax return, which challenges the exclusion from taxable income of an inflation adjustment related to the value of assets used for power generation (EI Barranquilla, a wholly owned subsidiary of GPU Power, ABB Barranquilla, Corporacion Electrica de la Costa Atlantica and Distral Group have a 28.7%, 28.7%, 42.5% and 0.1% interest in TEBSA, respectively). The failure to give notice of this Special Requirement to the US Export Import Bank (EXIM Bank) is an event of default under the loan agreement. GPU Power also believes that other events of default exist under the loan agreements with project lenders including the Overseas Private Investments Corporation (OPIC) and a commercial bank syndicate. As a result, certain required certifications have not been delivered to EXIM Bank, OPIC and the other project lenders, which failure is, itself, an event of default 53 124 under the loan agreements. These issues are currently being discussed with EXIM Bank and the other project lenders. GPU Power also expects that it will be necessary to address these issues with the Government of Colombia, as well as the other partners in the TEBSA project. As of June 30, 2000, GPU Power has an investment of approximately $84.4 million in TEBSA and is committed to make additional standby equity contributions of $21.3 million, which GPU, Inc. has guaranteed. The total outstanding senior debt of the TEBSA project is $399 million and, in addition, GPU International has guaranteed the obligations of the operators of the TEBSA project, up to a maximum of $5 million, under the project's operations and maintenance agreement. There can be no assurance as to the outcome of these matters. GPU Telcom In March 2000, GPU, Inc. announced its participation in America's Fiber Network LLC (AFN), of which GPU, Inc. anticipates owning 25%. AFN is a high-speed fiber optics company with a network of more than 7,000 route miles, or 140,000 fiber miles, connecting major markets in the eastern US to secondary markets with a growing need for broadband access. GPU, Inc. anticipates investing approximately $40 million (of which $1.9 million has been invested as of June 30, 2000) in AFN through GPU Telcom, which includes existing and new fiber routes and electronic equipment. In April 2000, GPU, Inc. announced the formation of Telergy Mid-Atlantic (TMA), a joint venture between GPU Telcom and Telergy, Inc. TMA combines established telecommunication services and marketing expertise with utilities' existing fiber networks and natural positioning in serving retail markets. GPU, Inc. has invested $20 million in Telergy, Inc. through GPU Telcom. Other: ------ JCP&L and Public Service Electric & Gas Company (PSE&G) each hold a 50% undivided ownership interest in Yards Creek Pumped Storage Facility (Yards Creek). In December 1998, JCP&L filed a petition with the New Jersey Board of Public Utilities (NJBPU) seeking a declaratory order that PSE&G's right of first refusal to purchase JCP&L's ownership interest at its current book value under a 1964 agreement between the companies is void and unenforceable. Management believes that the fair market value of JCP&L's ownership interest in Yards Creek is substantially in excess of its June 30, 2000 book value of $22 million. There can be no assurance as to the outcome of this matter. Concurrent with GPU's July 1999 acquisition of the 50% of GPU Power UK which it did not already own, GPU began to evaluate existing restructuring plans and formulate additional plans to reduce operating expenses and achieve ongoing cost reductions. As of December 31, 1999, GPU had identified and approved a cost reduction plan. At the acquisition date, GPU Power UK had recorded a liability of $28.6 million related to previous cost reduction plans. GPU retained $25.7 million of this liability, related to contractual termination and other severance benefits for 276 employees identified in a 1999 business process reengineering project. GPU identified an additional 355 employees (234 in Engineering Services, 38 in metering, 21 in Network Services and 62 from other specific functions) to be terminated as part of the plan and recorded an additional liability of $39.3 million. A net charge of $18.2 million for GPU's 50% share of these adjustments was included in expense in 1999 and the other 50% was recorded in Goodwill as a purchase accounting adjustment. 54 125 In 2000, a change in the investment return assumptions, due to better than expected investment performance, resulted in a reduction of approximately $6.9 million to $22.6 million in the estimated liability for the remaining 459 employees at December 31, 1999. Consequently, goodwill was credited for $3.4 million (50% of the change in estimate) and $3.5 million was credited to income. Also in 2000, $14.2 million was paid to 338 employees. The remaining severance liability of $7.5 million at June 30, 2000 reflects the above transactions as well as currency translation adjustments and the impact of five employees who were retained and is included in Other current liabilities on the Consolidated Balance Sheets. Management expects the plan will be substantially completed by September 2000. GPU AR has entered into contracts to supply electricity to retail customers through June 2002. In connection with meeting its supply obligations, GPU AR has entered into purchase commitments for energy and capacity with payment obligations totaling approximately $22.5 million as of June 30, 2000. GPU, Inc. has guaranteed up to $19.1 million of these payments. In accordance with the Nuclear Waste Policy Act of 1982 (NWPA), the GPU Energy companies have entered into contracts with, and have been paying fees to, the DOE for the future disposal of spent nuclear fuel in a repository or interim storage facility. AmerGen has assumed all liability for disposal costs related to spent fuel generated after its purchase of TMI-1 and has agreed to assume this liability for Oyster Creek following its purchase of that plant. In 1996, the DOE notified the GPU Energy companies and other standard contract holders that it would be unable to begin acceptance of spent nuclear fuel for disposal by 1998, as mandated by the NWPA. The DOE requested recommendations from contract holders for handling the delay. The DOE's inability to accept spent nuclear fuel could have a material impact on GPU's results of operations, as additional costs may be incurred to build and maintain interim on-site storage at Oyster Creek. In June 1997, a consortium of electric utilities, including GPUN, filed a license application with the NRC seeking permission to build an interim above-ground disposal facility for spent nuclear fuel in Utah. There can be no assurance as to the outcome of these matters. GPU, Inc. and consolidated affiliates have approximately 15,500 employees worldwide, of whom 11,500 are employed in the US, 3,500 are in the United Kingdom (UK) and the remaining 500 are in South America and Australia. The majority of the US workforce is employed by the GPU Energy companies (5,600) and MYR (5,500), of which approximately 3,300 and 4,800, respectively, are represented by unions for collective bargaining purposes. In the UK, approximately 3,100 GPU Power UK employees are represented by unions, and the terms and conditions of various bargaining agreements are generally reviewed annually, on April 1. JCP&L, Met-Ed and Penelec's collective bargaining agreements with the International Brotherhood of Electrical Workers expire on October 31, 2002, May 1, 2003 and May 14, 2002, respectively. Penelec's collective bargaining agreement with the Utility Workers Union of America expires on June 30, 2001. During the normal course of the operation of its businesses, in addition to the matters described above, GPU is from time to time involved in disputes, claims and, in some cases, as a defendant in litigation in which compensatory and punitive damages are sought by the public, customers, contractors, vendors and other suppliers of equipment and services and by employees alleging unlawful employment practices. While management does not expect that the outcome of these matters will have a material effect on GPU's 55 126 financial position or results of operations, there can be no assurance that this will continue to be the case. 2. ACQUISITIONS AND DISPOSITIONS MYR Group Inc. Acquisition In April 2000, GPU, Inc. completed its acquisition of MYR Group Inc. (MYR) for approximately $217.5 million. The fair value of the assets acquired totaled approximately $154.7 million and the amount of liabilities assumed totaled approximately $99.7 million. MYR, a suburban Chicago-based infrastructure construction services company, is the fifth largest specialty contractor in the US. MYR provides a complete range of power line and commercial/industrial electrical construction services for electric utilities, telecommunications providers, commercial and industrial facilities and government agencies across the US. MYR also builds cellular towers for the wireless communications market. The acquisition was partially financed through the issuance of GPU, Inc. short-term debt and was accounted for under the purchase method of accounting. The total acquisition cost exceeded the estimated value of net assets by $162.5 million. This excess is considered goodwill and is being amortized on a straight-line basis over 40 years. The following is a summary of significant accounting policies for MYR's construction services business: Revenue Recognition ------------------- MYR recognizes revenue on construction contracts using the percentage-of-completion accounting method determined in each case by the ratio of cost incurred to date on the contract (excluding uninstalled direct materials) to management's estimate of the contract's total cost. Contract cost includes all direct material, subcontract and labor costs and those indirect costs related to contract performance, such as supplies, tool repairs and depreciation. MYR charges selling, general, and administrative costs, including indirect costs associated with maintaining district offices, to expense as incurred. Provisions for estimated losses on uncompleted contracts are recorded in the period in which such losses are determined. Changes in estimated revenues and costs are recognized in the periods in which such estimates are revised. Significant claims are included in revenue in accordance with industry practice. The asset, "Costs and estimated earnings in excess of billings on uncompleted contracts," represents revenues recognized in excess of amounts billed. The liability, "Billings in excess of costs and estimated earnings on uncompleted contracts," represents amounts billed in excess of revenues recognized. Classification of Current Assets and Current Liabilities -------------------------------------------------------- The length of MYR's contracts vary, with some larger contracts exceeding one year. In accordance with industry practice, MYR includes in current assets and current liabilities amounts realizable and payable under contracts which may extend beyond one year. 56 127 GPU PowerNet Sale On June 30, 2000, GPU, Inc. sold GPU PowerNet to Singapore Power International (SPI) for A$2.1 billion (approximately US $1.26 billion). As part of the sales price, SPI assumed liability for A$230 million (US$137.8 million) of medium term notes. GPU applied the net proceeds from the sale as follows: A$1,288 million (US$772 million) was used to repay debt; and $A579 million (US$347 million) was placed in a trust (which is included in Special deposits on the Consolidated Balance Sheets) to provide for the repayment of the remaining medium term notes (A$174 million/US$104 million) and outstanding commercial paper (A$405 million/US$243 million) at maturity. As a result of the sale, GPU recorded in Operating expenses on the Consolidated Statements of Income, a pre-tax loss in the quarter ended June 30, 2000 of $372 million($295 million after-tax, or $2.43 per share), including a $94 million foreign currency loss. Pending Sale of Oyster Creek In 1999, the GPU Energy companies sold Three Mile Island Unit 1 (TMI-1) nuclear generating station and substantially all of their fossil and hydroelectric generating stations. In October 1999, JCP&L agreed to sell Oyster Creek to AmerGen Energy Company, LLC (AmerGen), a joint venture of PECO Energy and British Energy, for $10 million and reimbursement of the cost (estimated at $88 million) of the next scheduled refueling outage. The Oyster Creek plant was written down to its fair market value in 1999, consistent with its sale price. The write-down of the plant asset was deferred as a regulatory asset pending separate and further review by the NJBPU. 3. ACCOUNTING FOR DERIVATIVE INSTRUMENTS GPU's use of derivative instruments is intended primarily to manage the risk of interest rate, foreign currency and commodity price fluctuations. GPU does not intend to hold or issue derivative instruments for trading purposes. Commodity Derivatives: ---------------------- The GPU Energy companies use futures contracts to manage the risk of fluctuations in the market price of electricity and natural gas. These contracts qualify for hedge accounting treatment under current accounting rules since price movements of the commodity derivatives are highly correlated with the underlying hedged commodities and the transactions are designated as hedges at inception. Accordingly, under the deferral method of accounting, gains and losses related to commodity derivatives are recognized in Power purchased and interchanged in the Consolidated Statements of Income when the hedged transaction closes or if the commodity derivative is no longer sufficiently correlated. Prior to income or loss recognition, deferred gains and losses relating to these transactions are recorded in Current Assets or Current Liabilities in the Consolidated Balance Sheets. Interest Rate Swap Agreements: ------------------------------ GPU Electric uses interest rate swap agreements to manage the risk of increases in variable interest rates. As of June 30, 2000, these agreements covered approximately $549 million of debt, including commercial paper, and were scheduled to expire on various dates through November 2007. Differences 57 128 between amounts paid and received under interest rate swaps are recorded as adjustments to the interest expense of the underlying debt since the swaps are related to specific assets, liabilities or anticipated transactions. All of the agreements effectively convert variable rate debt, including commercial paper, to fixed rate debt. For the quarter ended June 30, 2000, fixed rate interest expense incurred in connection with the swap agreements exceeded the variable rate interest expense that would have been incurred had the swaps not been in place by approximately $380 thousand. Due to the sale of GPU PowerNet, the amount of debt subject to interest rate swaps at GPU Electric declined from $1,299 million at March 31, 2000 to $549 million at June 30, 2000. Swap positions associated with the retired debt were closed out, and swap breakage costs of $2.1 million pre-tax were included as part of the loss on the sale of GPU PowerNet. In April 2000, Penelec issued a total of $50 million of variable rate senior notes as unsecured medium-term notes. These variable rate securities were converted to fixed rate obligations through interest rate swap agreements. Currency Swap Agreements: ------------------------- GPU Electric uses currency swap agreements to manage currency risk caused by fluctuations in the US dollar exchange rate related to debt issued in the US by Avon Energy Partners Holdings (Avon). These swap agreements effectively convert principal and interest payments on this US dollar debt to fixed sterling principal and interest payments, and expire on the maturity dates of the bonds. Interest expense is recorded based on the fixed sterling interest rate. As of June 30, 2000, these currency swap agreements covered British pound 561 million (US $850 million) of debt. Interest expense would have been British pound 9.4 million (US $14.3 million) as compared to British pound 9.8 million (US $14.9 million) for the quarter ended June 30, 2000 had these agreements not been in place. Gain on Forward Foreign Exchange Contracts: ------------------------------------------- In connection with its previously announced intention to sell its Australian assets, GPU Electric entered into forward foreign exchange contracts in order to lock in the then-current A$/US$ exchange rate on the projected remittance of Australian dollar proceeds arising from the expected sale of GPU PowerNet and GPU GasNet. On May 24, 2000, GPU announced that it had declined all bids submitted in connection with the sale process. Consequently, GPU Electric closed out its forward foreign exchange positions, and recognized a pre-tax gain of $4.5 million in the second quarter of 2000. Indexed Swap Agreement: ----------------------- In June 1998, Onondaga Cogeneration L.P. (Onondaga), a GPU International, Inc. subsidiary, and Niagara Mohawk Power Corporation (NIMO) renegotiated their existing power purchase agreement and entered into a 10-year power put indexed swap agreement. The power put agreement gives Onondaga the right, but not the obligation, to sell energy and capacity to NIMO at a proxy market price up to the specified contract quantity. 58 129 Under the indexed swap agreement, Onondaga pays NIMO the market price of energy and capacity and NIMO pays Onondaga a contract price which is fixed for the first two years and then adjusted monthly, according to an indexing formula, for the remaining term. As of June 30, 2000, the unamortized balance of the swap contract was valued at $51.7 million, and was included in Other - Deferred Debits and Other Assets on the Consolidated Balance Sheets. This valuation was derived using the discounted estimated cash flows related to payments expected to be received by Onondaga. A corresponding amount was recorded in deferred revenue (which is included in Other - Current Liabilities on the Consolidated Balance Sheets) and will be recognized to income over a period not to exceed 10 years. Concurrent with the establishment of a competitive market for electricity in New York (Power Exchange) and meeting specific trading volume criteria, certain rights between Onondaga and NIMO expire under the power put agreement. As a result, in 2000, GPU International, Inc. expects to recognize in income all unamortized deferred revenue, including that from the indexed swap agreement, which will be largely offset by an impairment of the Onondaga facility and a provision for out-of-market gas transportation costs. 4. SEGMENT INFORMATION The following is presented in accordance with Statement of Financial Accounting Standards No. 131, "Disclosures about Segments of an Enterprise and Related Information." GPU's reportable segments are strategic business units that are managed separately due to their different operating and regulatory environments. GPU's management evaluates the performance of its business units based upon income before extraordinary and non-recurring items. For the purpose of providing segment information, domestic electric utility operations (GPU Energy) is comprised of the three electric utility operating companies serving customers in New Jersey and Pennsylvania, as well as GPU Generation, Inc. (sold in late 1999), GPUN, GPU Telcom and GPUS. For additional information on GPU's organizational structure and businesses, see preface to the Notes to Consolidated Financial Statements. 59 130
Business Segment Data (in thousands) Interest Depreciation Charges and Income Tax Operating and Preferred Expense/ Revenues Amortization Dividends (Benefit) -------- ------------ --------- ----------- For the six months ended June 30, 2000 Domestic Segments: Electric Utility Operations (GPU Energy) $ 1,730,089 $ 169,356 $ 102,847 $ 102,722 Independ Power Prod (GPU International) 43,692 4,700 416 73 Electric Retail Energy Sales (GPU AR) 39,874 - - 848 Construction Services (MYR) (e) 99,532 1,311 2,389 1,147 ----------- ---------- ---------- --------- Subtotal 1,913,187 175,367 105,652 104,790 ----------- ---------- ---------- --------- Foreign Segments: Electric/Gas Utility Operations: (GPU Electric) Electric Distribution - United Kingdom 325,106 52,376 91,451 29,795 Electric Distribution - Argentina 81,614 7,663 12,749 6,881 Electric Transmission - Australia (d) 90,007 19,947 46,822 (10,921) Gas Transmission - Australia 27,183 5,520 21,114 (6,675) Independ Power Prod - S. America (GPU Power) 21,082 3,154 2,183 2,408 ----------- ---------- ---------- --------- Subtotal 544,992 88,660 174,319 21,488 ----------- ---------- ---------- --------- Corporate and Eliminations (1,361) - 4,805 - ----------- ---------- ---------- --------- Consolidated Total $ 2,456,818 $ 264,027 $ 284,776 $ 126,278 =========== ========== ========== ========= For the six months ended June 30, 1999 Domestic Segments: Electric Utility Operations (GPU Energy) $ 1,712,716 $ 206,963 $ 114,519 $ 163,060 Independ Power Prod (GPU International) 42,197 4,649 619 182 Electric Retail Energy Sales (GPU AR) 37,521 - - 1,032 ----------- ---------- ---------- --------- Subtotal 1,792,434 211,612 115,138 164,274 ----------- ---------- ---------- --------- Foreign Segments: Electric/Gas Utility Operations: (GPU Electric) Electric Distribution - United Kingdom 603 - 9,835 2,171 Electric Distribution - Argentina 48,999 6,190 8,008 1,986 Electric Transmission - Australia (d) 95,912 21,367 52,526 4,462 Gas Transmission - Australia 5,721 1,227 3,589 422 Independ Power Prod - S. America (GPU Power) 17,734 2,699 1,363 2,272 ----------- ---------- ---------- --------- Subtotal 168,969 31,483 75,321 11,313 ----------- ---------- ---------- --------- Corporate and Eliminations - - 481 - ----------- ---------- ---------- --------- Consolidated Total $ 1,961,403 $ 243,095 $ 190,940 $ 175,587 =========== ========== ========== =========
(a) Represents income taxes on income before extraordinary and non-recurring items. (b) The comparative 1999 Total Assets is as of December 31, 1999. (c) Includes equity in net income of investee accounted for under the equity method of $73.5 million, for the period prior to the consolidation of GPU Power UK. (d) Represents GPU PowerNet, which was sold in June 2000. (e) MYR was acquired in May 2000. 60 131 5. COMPREHENSIVE INCOME For the six months ended June 30, 2000 and 1999, comprehensive income is summarized below.
(in thousands) Six months Ended June 30, GPU, Inc. and Subsidiary Companies 2000 1999 ---------------------------------- ---- ---- Net income/(loss) $ (79,815) $ 237,981 ---------- ---------- Other comprehensive income/(loss), net of tax: Net unrealized gains/(loss) on investments 13,028 (4,758) Foreign currency translation (41,852) 8,169 ---------- ---------- Total other comprehensive income/(loss) (28,824) 3,411 ---------- ---------- Comprehensive income! (loss) $(108, 639) $ 241,392 ========== ========== JCP&L Net income $ 90,004 $ 47,842 ---------- ---------- Other comprehensive income/(loss), net of tax: Net unrealized gains/(loss) on investments - - ---------- ---------- Comprehensive income $ 90,004 $ 47,842 ========== ========== Met-Ed Net income $ 35,160 $ 51,974 ---------- ---------- Other comprehensive income/(loss), net of tax: Net unrealized gains/(loss) on investments (2,141) 2,816 ---------- ---------- Comprehensive income $ 33,019 $ 54,790 ========== ========== Penelec Net income $ 31,481 $ 85,435 ---------- ---------- Other comprehensive income/(loss), net of tax: Net unrealized gains/(loss) on investments (1,076) 1,337 ---------- ---------- Comprehensive income $ 30,405 $ 86,772 ========== ==========
61 132 PART II ITEM 1 - LEGAL PROCEEDINGS Information concerning the current status of certain legal proceedings instituted against GPU, Inc. and the GPU Energy companies discussed in Part I of this report in Combined Notes to Consolidated Financial Statements is incorporated herein by reference and made a part hereof. ITEM 6 - EXHIBITS AND REPORTS ON FORM 8-K (a) Exhibits (4) Instruments defining the rights of security holders, including indentures A - First Supplemental Indenture between Met-Ed and United States Trust Company of New York, dated August 1, 2000. B - First Supplemental Indenture between Penelec and United States Trust Company of New York, dated August 1, 2000. (12) Statements Showing Computation of Ratio of Earnings to Fixed Charges and Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends Based on SEC Regulation S-K, Item 503 A - JCP&L B - Met-Ed C - Penelec (27) Financial Data Schedules A - GPU, Inc. and Subsidiary Companies B - JCP&L C - Met-Ed D - Penelec (b) Reports on Form 8-K GPU, Inc.: ---------- 133 EXHIBIT E Income statement for the most recent 12 month period only, on an actual and on a pro forma basis in the form prescribed for Statement C of FERC Form No. 1. 134 FIRSTENERGY CORP./GPU INC. PRO FORMA COMBINED INCOME STATEMENT FOR THE YEAR ENDED DECEMBER 31, 1999
OHIO CLEVELAND TOLEDO PENNSYLVANIA EDISON ELECTRIC EDISON POWER ------ -------- ------ ----- Operating Revenues $2,365,964,220 $1,849,561,714 $921,158,988 $ 315,731,137 Operating Expenses 1,924,843,906 1,470,176,587 757,382,166 280,378,886 -------------- -------------- ------------ ------------- Net Operating Income 441,120,314 379,385,127 163,776,822 35,352,251 Net Other Income 44,098,260 23,306,399 12,737,848 (1,850,983) -------------- -------------- ------------ ------------- Income Before Net Interest Charges 485,218,574 402,691,526 176,514,670 33,501,268 Net interest Charges 187,529,210 208,602,718 76,569,731 20,853,276 -------------- -------------- ------------ ------------- Net Income 297,689,364 194,088,808 99,944,939 12,647,992 Preferred Stock Dividend Requirements 0 0 0 0 -------------- -------------- ------------ ------------- Earnings on Common Stock $ 297,689,364 $ 194,088,808 $ 99,944,939 $ 12,647,992 ============== ============== ============ =============
JERSEY CENTRAL METROPOLITAN PENNSYLVANIA POWER & LIGHT EDISON ELECTRIC YORK HAVEN COMPANY COMPANY COMPANY POWER COMPANY ------- ------- ------- ------------- Operating Revenues $2,018,208,667 $902,697,284 $921,964,651 $ 5,201,850 Operating Expenses 1,740,204,057 730,544,562 774,460,913 3,738,108 -------------- ------------ ------------ ----------- Net Operating Income 278,004,610 172,152,722 147,503,738 l,463,742 Net Other Income 1,023,436 (14,569,687) 50,081,756 161,868 -------------- ------------ ------------ ----------- Income Before Net Interest Charges 279,028,046 157,583,035 197,585,494 1,625,610 Net interest Charges 106,648,828 62,459,768 45,093,993 3,227 -------------- ------------ ------------ ----------- Net Income 172,379,218 95,123,267 152,491,501 1,622,383 Preferred Stock Dividend Requirements 0 0 0 0 -------------- ------------ ------------ ----------- Earnings on Common Stock $ 172,379,218 $ 95,123,267 $152,491,501 $ 1,622,383 ============== ============ ============ ===========
CURRENT FIRSTENERGY MERGER FIRSTENERGY OTHER & GPU PRO FORMA PRO FORMA SUBSIDIARIES ELIMINATIONS ADJUSTMENTS COMBINED ------------ ------------ ----------- -------- Operating Revenues $3,657,808,770 ($2,923,012,328) $ 0 $10,035,284,953 Operating Expenses 2,948,196,047 (2,459,216,804) (94,475,000) 8,076,233,428 -------------- --------------- ------------- --------------- Net Operating Income 709,612,723 (463,795,524) 94,475,000 1,959,051,525 Net Other Income 780,614,447 (701,099,558) 0 194,503,786 -------------- --------------- ------------- --------------- Income Before Net Interest Charges 1,490,227,170 (1,164,895,082) 94,475,000 2,153,555,311 Net interest Charges 346,330,776 (24,441,171) 193,849,000 1,223,499,356 -------------- --------------- ------------- --------------- Net Income 1,143,896,394 (1,140,453,911) (99,374,000) 930,055,955 Preferred Stock Dividend Requirements 0 0 0 0 -------------- --------------- ------------- --------------- Earnings on Common Stock $1,143,896,394 ($1,140,453,911) ($99,374,000) $ 930,055,955 ============== =============== ============= ===============
135 EXHIBIT F An analysis of retained earnings for the period covered by the income statements referred to in Exhibit E. 136 FIRSTENERGY CORP./GPU, INC. PRO FORMA COMBINED STATEMENT OF RETAINED EARNINGS FOR THE YEAR ENDED DECEMBER 31, 1999
MERGER FIRSTENERGY FIRSTENERGY ELIMINATIONS PRO FORMA CORP. GPU, INC. & ADJUSTMENTS COMBINED --------------- -------------- --------------- ------------- Balance - Beginning of Year (1/1/99) $ 718,409,346 $2,189,947,916 ($2,189,947,916) (a) $ 718,409,346 Net Income 568,299,454 461,130,501 (99,374,000) (b) 930,055,955 --------------- -------------- --------------- ------------- 1,286,708,800 2,651,078,417 (2,289,321,916) 1,648,465,301 Dividends Declared - Common Stock (341,468,277) (263,088,657) 263,088,657 (c) (464,830,277) (123,362,000) (c) Adjustments to Retained Earnings: Loss on Reacquisition of Preferred Stock - (2,116,272) (2,116,272) Net Unrealized Gain on Investments - 5,838,268 5,838,268 Foreign Currency Translation - 13,859,089 13,859,089 Minimum Pension Liability - 5,266,502 5,266,502 Other Adjustments - (1,194) (1,194) --------------- -------------- --------------- ------------- Balance - End of Year (12/31/99) $ 945,240,523 $2,410,836,153 ($2,149,595,259) $1,206,481,417 =============== ============== =============== ============= NOTES: (a) Represents pro forma elimination of GPU, Inc. accumulated retained earnings as of January 1, 1999. (b) Represents pro forma net income adjustments. (c) Represents adjustment to replace GPU 1999 common stock dividends with pro forma annual dividend of $1.50 paid on 82,241,527 FirstEnergy common shares issued to GPU, Inc. shareholders.
137 FIRST ENERGY CORP/GPU INC. PRO FORMA COMBINED SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS FOR DEPRECIATION, AMORTIZATION AND DEPLETION AS OF DECEMBER 31, 1999
OHIO CLEVELAND TOLEDO PENNSYLVANIA EDISON ELECTRIC EDISON POWER --------------- --------------- --------------- --------------- UTILITY PLANT IN SERVICE: PLANT IN SERVICE (CLASSIFIED) $ 8,824,276,231 $ 3,791,020,858 $ 1,526,730,041 $ 1,008,632,099 PROPERTY UNDER CAPITAL LEASES 164,001,333 7,943,494 1,636,046 4,116,636 PLANT PURCHASED OR SOLD 63,118,344 184,410,076 0 40,567,280 COMPLETED CONSTRUCTION NOT CLASSIFIED 231,637,462 302,366,906 129,865,924 32,487,849 EXPERIMENTAL PLANT NOT CLASSIFIED 0 0 0 0 --------------- --------------- --------------- --------------- TOTAL 7,273,823,370 4,285,443,333 1,657,832,010 1,145,783,904 LEASED TO OTHERS 0 0 0 983,057 HELD FOR FUTURE USE 11,867,916 19,453,151 2,453,748 1,871,382 CONSTRUCTION WORK IN PROGRESS 187,113,405 86,002,026 96,853,900 18,557,920 ACQUISITION ADJUSTMENTS 0 0 0 0 --------------- --------------- --------------- --------------- TOTAL UTILITY PLANT 7,472,804,891 4,350,896,809 1,756,230,657 1,167,216,173 ACCUM PROV FOR DEPR, AMORT & DEPL 3,373,616,555 1,300,720,289 596,332,268 767,521,106 --------------- --------------- --------------- --------------- NET UTILITY PLANT $ 4,099,196,136 $ 2,960,178,220 1,159,907,382 $ 300,005,067 =============== =============== =============== =============== DETAIL OF ACCUMULATED PROVISIONS FOR DEPRECIATION,AMORTIZATION AND DEPLETION IN SERVICE: DEPRECIATION $ 3,164,498,078 $ 1,311,227,017 $ 550,411,532 $ 727,141,223 AMORT. AND DEPL. OF PRODUCTING NATURAL GAS LANDLAND RIGHTS 0 0 0 0 AMORT. OF UNDERGROUND STORAGE LAND AND LAND RIGHTS 0 0 0 0 AMORT OF OTHER UTILITY PLANT 208,098,138 72,094,814 34,788,907 40,248,076 --------------- --------------- --------------- --------------- TOTAL IN SERVICE 3,373,566,216 1,383,321,831 964,181,439 767,368,796 LEASED TO OTHERS: DEPRECIATION 0 0 0 0 AMORTIZATION AND DEPLETION 0 0 0 0 --------------- --------------- --------------- --------------- TOTAL LEASED TO OTHERS 0 0 0 0 HELD FOR FUTURE USE: DEPRECIATION 30,330 16,396,456 2,150,826 131,808 AMORTIZATION 0 0 0 0 --------------- --------------- --------------- --------------- TOTAL HELD FOR FUTURE USE 30,330 16,396,456 2,150,826 131,808 ABANDONMENT OF LEASES (NATURAL GAS) AMORT OF PLANT ACQUISITION ADJ. 0 0 0 0 --------------- --------------- --------------- --------------- TOTAL ACCUMULATED PROVISIONS $ 3,373,616,866 $ 1,303,720,200 $ 800,332,206 $ 787,821,108 =============== =============== =============== =============== JERSEY METROPOLITAN PENNSYLVANIA YORK CENTRAL EDISON ELECTRIC HAVEN --------------- --------------- --------------- --------------- UTILITY PLANT IN SERVICE: PLANT IN SERVICE (CLASSIFIED) $ 4,186,230,526 $ 1,499,028,875 $ 1,732,370,611 $ 23,231,721 PROPERTY UNDER CAPITAL LEASES 0 0 2,176,778 0 PLANT PURCHASED OR SOLD 0 (160,362) O O COMPLETED CONSTRUCTION NOT CLASSIFIED 0 0 0 0 EXPERIMENTAL PLANT NOT CLASSIFIED 0 0 0 0 --------------- --------------- --------------- --------------- TOTAL 4,186,230,526 1,490,000,613 1,734,547,589 23,231,721 LEASED TO OTHERS 0 0 0 0 HELD FOR FUTURE USE 15,402,271 806,326 527,551 0 CONSTRUCTION WORK IN PROGRESS 80,671,006 21,216,332 30,326,546 4,112,397 ACQUISITION ADJUSTMENTS 0 0 0 0 --------------- --------------- --------------- --------------- TOTAL UTILITY PLANT 4,292,312,803 1,620,081,171 1,785,403,806 27,344,119 ACCUM PROV FOR DEPR, AMORT & DEPL 2,456,999,052 456,205,770 862,449,183 7,803,054 --------------- --------------- --------------- --------------- NET UTILITY PLANT $ 1,826,346,151 $ 1,068,476,401 $ 1,212,954,703 $ 19,841,054 =============== =============== =============== =============== DETAIL OF ACCUMULATED PROVISIONS FOR DEPRECIATION,AMORTIZATION AND DEPLETION IN SERVICE: DEPRECIATION $ 2,456,966,852 $ 456,205,770 $ 552,449,183 $ 7,503,064 AMORT. AND DEPL. OF PRODUCTING NATURAL GAS LANDLAND RIGHTS 0 0 0 0 AMORT. OF UNDERGROUND STORAGE LAND AND LAND RIGHTS 0 0 0 0 AMORT OF OTHER UTILITY PLANT 0 0 0 0 --------------- --------------- --------------- --------------- TOTAL IN SERVICE 2,456,966,852 455,205,770 552,449,183 7,503,064 LEASED TO OTHERS: DEPRECIATION 0 0 0 0 AMORTIZATION AND DEPLETION 0 0 0 0 --------------- --------------- --------------- --------------- TOTAL LEASED TO OTHERS 0 0 0 0 HELD FOR FUTURE USE: DEPRECIATION 0 0 0 0 AMORTIZATION 0 0 0 0 --------------- --------------- --------------- --------------- TOTAL HELD FOR FUTURE USE 0 0 0 0 ABANDONMENT OF LEASES (NATURAL GAS) AMORT OF PLANT ACQUISITION ADJ. 0 0 0 0 --------------- --------------- --------------- --------------- TOTAL ACCUMULATED PROVISIONS $ 2,456,906,052 $ 456,205,770 $ 582,449,183 $ 7,503,064 =============== =============== =============== =============== CURRENT FIRST ENERGY MERGER FIRST ENERGY OTHER & GPU PRO FORMA PRO FORMA SUBSIDIARIES ELIMINATIONS ADJUSTMENTS COMBINED --------------- --------------- --------------- --------------- UTILITY PLANT IN SERVICE: PLANT IN SERVICE (CLASSIFIED) $ 4,910,948,248 $ 0 ($ 450,000,000) $25,112,470,300 PROPERTY UNDER CAPITAL LEASES 0 0 0 180,364,296 PLANT PURCHASED OR SOLD 0 0 0 277,825,307 COMPLETED CONSTRUCTION NOT CLASSIFIED 0 0 0 800,060,141 EXPERIMENTAL PLANT NOT CLASSIFIED 0 0 0 0 --------------- --------------- --------------- --------------- TOTAL 4,910,948,248 0 (450,000,000) 26,286,828,114 LEASED TO OTHERS 0 0 0 983,057 HELD FOR FUTURE USE 0 0 0 62,172,355 CONSTRUCTION WORK IN PROGRESS 33,967,050 0 0 526,843,380 ACQUISITION ADJUSTMENTS 0 0 0 0 --------------- --------------- --------------- --------------- TOTAL UTILITY PLANT 4,944,935,098 0 (450,000,000) 26,848,838,806 ACCUM PROV FOR DEPR, AMORT & DEPL 1,042,716,280 0 0 10,052,030,144 --------------- --------------- --------------- --------------- NET UTILITY PLANT $ 3,902,220,638 0 (450,000,000) $16,194.906,762 =============== =============== =============== =============== DETAIL OF ACCUMULATED PROVISIONS FOR DEPRECIATION,AMORTIZATION AND DEPLETION IN SERVICE: DEPRECIATION $ 1,042,715,280 $ 0 $ 0 $ 0 AMORT. AND DEPL. OF PRODUCTING NATURAL GAS LANDLAND RIGHTS 0 0 0 0 AMORT. OF UNDERGROUND STORAGE LAND AND LAND RIGHTS 0 0 0 0 AMORT OF OTHER UTILITY PLANT 0 0 0 356,210,834 --------------- --------------- --------------- --------------- TOTAL IN SERVICE $ 1,042,715,280 0 0 356,210,834 LEASED TO OTHERS: DEPRECIATION 0 0 0 0 AMORTIZATION AND DEPLETION 0 0 0 0 --------------- --------------- --------------- --------------- TOTAL LEASED TO OTHERS 0 0 0 0 HELD FOR FUTURE USE: DEPRECIATION 0 0 0 10,711,431 AMORTIZATION 0 0 0 0 --------------- --------------- --------------- --------------- TOTAL HELD FOR FUTURE USE 0 0 0 10,711,431 ABANDONMENT OF LEASES (NATURAL GAS) AMORT OF PLANT ACQUISITION ADJ. 0 0 0 0 --------------- --------------- --------------- --------------- TOTAL ACCUMULATED PROVISIONS $ 1,042,715,280 $ 0 $ 0 $ 374,822,365 =============== =============== =============== =============== FE GPU TOTAL OTHER OTHER OTHER SUBSIDIARIES SUBSIDIARIES SUBSIDIARIES --------------- --------------- --------------- UTILITY PLANT IN SERVICE: IN SERVICE: PLANT IN SERVICE (CLASSIFIED) $ 888,185 $ 4,910,280,063 $ 4,910,948,248 PROPERTY UNDER CAPITAL LEASES 0 0 0 PLANT PURCHASED OR SOLD 0 0 0 COMPLETED CONSTRUCTION NOT CLASSIFIED 0 0 0 EXPERIMENTAL PLANT NOT CLASSIFIED 0 0 0 --------------- --------------- --------------- TOTAL 888,195 4,910,280,063 4,910,948,248 LEASED TO OTHERS 0 0 0 HELD FOR FUTURE USE 0 0 0 CONSTRUCTION WORK IN PROGRESS 0 33,987,850 33,967,050 ACQUISITION ADJUSTMENTS 0 0 0 --------------- --------------- --------------- TOTAL UTILITY PLANT 888,185 4,944,267,713 4,944,935,896 ACCUM PROV FOR DEPR, AMORT & DEPL 333,124 1,042,382,136 1,042,718,260 --------------- --------------- --------------- NET UTILITY PLANT $ 336,061 $ 3,901,996,577 $ 3,002,220,038 =============== =============== =============== DETAIL OF ACCUMULATED PROVISIONS FOR DEPRECIATION,AMORTIZATION AND DEPLETION IN SERVICE: DEPRECIATION $ 333,124 $ 1,042,382,138 $ 1,042,715,280 AMORT. AND DEPL. OF PRODUCTING NATURAL GAS LANDLAND RIGHTS 0 0 0 AMORT. OF UNDERGROUND STORAGE LAND AND LAND RIGHTS 0 0 0 AMORT OF OTHER UTILITY PLANT 0 0 0 --------------- --------------- --------------- TOTAL IN SERVICE $ 333,124 $ 1,042,382,138 $ 1,042,715,280 LEASED TO OTHERS: DEPRECIATION 0 0 0 AMORTIZATION AND DEPLETION 0 0 0 --------------- --------------- --------------- TOTAL LEASED TO OTHERS 0 0 0 HELD FOR FUTURE USE: DEPRECIATION 0 0 0 AMORTIZATION 0 0 0 --------------- --------------- --------------- TOTAL HELD FOR FUTURE USE 0 0 0 ABANDONMENT OF LEASES (NATURAL GAS) AMORT OF PLANT ACQUISITION ADJ. 0 0 0 --------------- --------------- --------------- TOTAL ACCUMULATED PROVISIONS $ 333,124 $ 1,042,382,138 $ 1,042,715,280 =============== =============== ===============
138 EXHIBIT G A copy of each application and Exhibit filed with any other Federal or State regulatory body in connection with the proposed transaction, and if action has been taken thereon, a certified copy of each order relating thereto. 139 Copy of Application to the United States Nuclear Regulatory Commission for Indirect Transfers of Control Exhibit Intentionally Omitted. 140 EXHIBIT H A copy of all contracts in respect to the proposed transaction. 141 Copy of Agreement and Plan of Merger Between FirstEnergy Corp. and GPU, Inc. Dated as of August 8, 2000. Exhibit Intentionally Omitted. 142 EXHIBIT I Maps. Exhibit Intentionally Omitted. 143 VERIFICATIONS 144 UNITED STATES OF AMERICA BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION Ohio Edison Company ) The Cleveland Eletric Illuminating ) Company, The Toledo Edison Company, ) Docket No. ECO1-____-000 Pennsylvania Power Company, American ) Transmission Systems, Inc. and their public ) utility affiliates ) ) and ) ) Jersey Central Power & Light Company, ) Metropolitan Edison Company, Pennsylvania ) Electric Company and their public utility affiliates ) VERIFICATION ------------ STATE OF OHIO ) ) COUNTY OF SUMMIT ) NOW, BEFORE ME, the undersigned authority, personally came and appeared, H. Peter Burg, who, after being duly sworn by me, did depose and say: That he is Chairman and Chief Executive Officer of FirstEnergy Corp.; that he has the authority to verify the foregoing Application on behalf of FirstEnergy Corp.; that he has read said Application and knows the contents thereof; and that all of the statements contained in said Application are true and correct to the best of his knowledge and belief. /s/ H. Peter Burg -------------------------------- H. Peter Burg Chairman and Chief Executive Officer FirstEnergy Corp. SUBSCRIBED AND SWORN TO before me this 9th day of November, 2000 /s/ Michael R. Beiting --------------------------------- [NOTARY SEAL] Michael R. Beiting MICHAEL R. BEITING, Attorney at Law Notary Public Notary Public -- State of Ohio My Commission has no expiration date. My Commission has no expiration date Section 147.03 R.C. County of Residency: Summit 145 UNITED STATES OF AMERICA BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION Ohio Edison Company, ) The Cleveland Electric Illuminating ) Company. The Toledo Edison Company, ) Pennsylvania Power Company, American ) Transmission Systems, Inc. and their public ) utility affiliates ) ) and ) Docket No. EC01-__-000 ) Jersey Central Power & Light Company, ) Metropolitan Edison Company, Pennsylvania ) Electric Company and their public ) utility affiliates ) VERIFICATION TERRANCE HOWSON, being duly sworn upon oath, states that he is VICE PRESIDENT, & Treasurer and has read the attached APPLICATION; that he knows the contents thereof; that the statements made therein with respect to Jersey Central Power & Light Company, Metropolitan Edison Company, Pennsylvania Electric Company and their public utility affiliates are true and correct to the best of his knowledge, information and belief; and that he has full power and authority to sign this document on behalf of Jersey Central Power & Light Company, Metropolitan Edison Company, Pennsylvania Electric Company and their public utility affiliates /s/ Terrance G. Howson ----------------------------------- Name: Terrance G. Howson Title: Vice President and Treasurer Subscribed and sworn to before me this 2nd day of Nov., 2000 /s/ Barbara E. Jost ------------------- Notary Public [NOTARY SEAL] My commission expires Barbara E. Jost Notary Public of New Jersey My Commission Expires August 12, 2004 146 NOTICE OF FILING 147 UNITED STATES OF AMERICA FEDERAL ENERGY REGULATORY COMMISSION Ohio Edison Company, ) The Cleveland Electric Illuminating ) Company, The Toledo Edison Company, ) Docket No. EC01-__-000 Pennsylvania Power Company, American ) Transmission Systems, Inc. and their public ) utility affiliates ) ) and ) ) Jersey Central Power & Light Company, ) Metropolitan Edison Company, Pennsylvania ) Electric Company and their public utility affiliates ) NOTICE OF FILING ( ) Take notice that on November 9, 2000 Ohio Edison Company ("OE"), The Cleveland Electric Illuminating Company ("CEI"), The Toledo Edison Company ("TE"), Pennsylvania Power Company ("PP"), American Transmission Systems, Inc. ("ATSI"), and their public utility affiliates (the "FirstEnergy Companies") and Jersey Central Power & Light Company ("JCP&L"), Metropolitan Edison Company ("MetEd"), and Pennsylvania Electric Company ("Penelec"), and their public utility affiliates (the "GPU Companies") (collectively, "Applicants"), tendered for filing an application pursuant to Section 203 of the Federal Power Act and Part 33 of the Commission's regulations, 18 C.F.R. Part 33 (2000), for an order approving the proposed merger of the FirstEnergy Companies and the GPU Companies ("Application"). Applicants request all authorizations necessary to undertake the proposed merger. Upon consummation of the merger, Applicants will form a registered utility holding company system. Applicants request that the Commission approve the merger on an expedited basis and without an evidentiary hearing. Applicants state that they have, by overnight mail, served a copy of the Application on the Ohio Public Utility Commission, the Pennsylvania Public Utility Commission, the New Jersey Board of Public Utilities and on all other interested entities. Any person desiring to be heard or to protest said filing should file a motion to intervene or protest with the Federal Energy Regulatory Commission, 888 First Street, N.E., Washington, D.C. 20426, in accordance with Rules 211 and 214 of the Commission's Rules of Practice and Procedure, 18 C.F.R. Sections 385.211 and 385.214 (2000). All such motions or protests should be 148 2 filed on or before December __, 2000. Protests will be considered by the Commission in determining the appropriate action to be taken, but will not serve to make protestants parties to the proceeding. Any person wishing to become a party must file a motion to intervene. Copies of this filing are on file with the Commission and are available for public inspection. This filing may also be viewed on the Internet at http://www.ferc.fed.us/online/rims/htm (call 202-208-2222 for assistance). David P. Boergers Secretary 149 TESTIMONY AND EXHIBITS 150 UNITED STATES OF AMERICA BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION Ohio Edison Company, ) The Cleveland Electric Illuminating Company, ) The Toledo Edison Company, Pennsylvania ) Power Company, American Transmission ) Docket No. EC01- -000 Systems, Inc. and their public utility affiliates ) ) and ) ) Jersey Central Power & Light Company, ) Metropolitan Edison Company, ) Pennsylvania Electric Company and their ) public utility affiliates ) PREPARED DIRECT TESTIMONY AND EXHIBITS OF ANTHONY J. ALEXANDER ON BEHALF OF APPLICANTS 151 EXHIBIT NO. APP-100 PAGE 1 OF 16 Q. PLEASE STATE YOUR NAME, BUSINESS ADDRESS, AND TITLE. A. Anthony J. Alexander. My business address is 76 South Main Street, Akron, Ohio 44308. I am the President of FirstEnergy Corp. Q. PLEASE DESCRIBE YOUR RECENT EMPLOYMENT HISTORY AND CURRENT RESPONSIBILITIES. A. I was named Senior Vice president and General Counsel in 1991, and Executive Vice President and General Counsel in 1997 of Ohio Edison Company. When FirstEnergy was formed in November 1997, I was named Executive Vice President and General Counsel of FirstEnergy and each of its utility operating companies. I was named President of FirstEnergy Corp. effective February 1, 2000. My responsibilities have included communications, legal, governmental affairs, sales and marketing, business development, power trading and wholesale transactions, and for a short period distribution operations. I also have responsibility over our Heating, Ventilation, and Air Conditioning (HVAC) and natural gas businesses. Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY? A. The purpose of my testimony is to provide the Federal Energy Regulatory Commission ("Commission" or "FERC") with an overview of, and relevant background concerning, the proposed merger involving Ohio Edison Company ("OE"), The Cleveland Electric Illuminating Company ("CEI"), The Toledo Edison Company ("TE"), Pennsylvania Power Company ("PP"), and American Transmission Systems, Inc. ("ATSI") on the one hand (hereinafter, the "FirstEnergy Companies"), and Jersey Central Power & Light Company ("JCP&L"), Metropolitan Edison Company ("MetEd"), and Pennsylvania 152 EXHIBIT NO. APP-100 PAGE 2 OF 16 Electric Company ("Penelec") on the other. The FirstEnergy Companies are wholly-owned direct or indirect subsidiaries of FirstEnergy Corp., an exempt public utility holding company. JCP&L, MetEd and Penelec are wholly-owned direct or indirect subsidiaries of GPU, Inc., a registered public utility holding company. I refer to the public utility subsidiaries of GPU, Inc. (i.e., JCP&L, MetEd and Penelec) collectively as GPU Energy. For brevity, I will not repeat all the information that is included in the application. Q. PLEASE DESCRIBE THE FIRSTENERGY COMPANIES. A. FirstEnergy Corp. was formed when the merger of OE and Centerior Energy Corporation, which owned CEI and TE, became effective on November 8, 1997. FirstEnergy Corp. is a diversified energy services holding company organized and existing under the laws of the state of Ohio. FirstEnergy Corp. is headquartered in Akron, Ohio. FirstEnergy's regulated public utility subsidiaries include OE, CEI, TE, PP, ATSI and FirstEnergy Trading Services, Inc. ("FETS"). An application is pending before the Commission in Docket No. EC01-3-000 seeking authorization to merge FETS into FirstEnergy Services Corp. ("FirstEnergy Services"), an affiliate currently providing retail gas and electricity service in several states. FirstEnergy Corp. also wholly owns other businesses including a regulated gas business and a number of mechanical contractors located throughout the northeastern United States. These enterprises collectively employ about 3,500 people. FirstEnergy also owns 50% of a business engaged in gas exploration and production operations, and pipeline operations. 153 EXHIBIT NO. APP-100 PAGE 3 OF 16 OE, TE, CEI and PP provide regulated retail electric service to 2.2 million customers within 13,200 square miles stretching from northern and central Ohio into western Pennsylvania. OE, TE, CEI, PP and FETS are authorized to sell wholesale power at market-based rates. Effective September 1, 2000, OE, TE, CEI and PP transferred their high voltage transmission facilities to ATSI. Thus, OE, TE, CEI and PP no longer provide transmission service in interstate commerce, Those services are provided by ATSI under ATSI's open access transmission service tariff on file with the Commission. OE, CEI and TE are regulated by the Public Utilities Commission of Ohio ("PUCO"), and PP is regulated by the Pennsylvania Public Utility Commission ("PPUC"). Ohio and Pennsylvania have both restructured their electric utility markets to permit retail competition. Effective January 1, 2001, retail customers in Ohio will be entitled to select their own generation suppliers. In Pennsylvania, retail choice for generation supply has been available in PP's service area since January 1, 1999. In addition, FirstEnergy Services competes for retail electric customers in other states, including New Jersey, Maryland, Pennsylvania and Delaware. By the end of 1999, FirstEnergy Services was already serving more than 20,000 new electric accounts, including 800 federal governmental facilities in New Jersey, such as the Statue of Liberty and Ellis Island. Q. PLEASE DESCRIBE THE FIRSTENERGY COMPANIES' ELECTRIC GENERATING UNITS. A. OE, TE, CEI and PP currently own and operate 16 power plants, which consist of a mix of fossil and combustion turbine generators and nuclear generators, with a total capacity 154 EXHIBIT NO. APP-100 PAGE 4 OF 16 of approximately 12,500 MW. Approximately 30 percent of the capacity is nuclear, and 40 percent of the energy generated by the system is from our nuclear units. FirstEnergy is in the process of increasing the amount of its capacity from 12,500 MW to approximately 13,000 MW by upgrading the Perry station from 1248 MW to 1265 MW and installing up to 425 MW of capacity at West Lorain. Attached as Exhibit No. APP-101 is a listing of the net installed electric generating capacity of each of these plants. We also plan to add another 340 MW of peaking capacity by the end of 2002. Q. DO THE FIRSTENERGY COMPANIES CONTROL THE POTENTIAL SITES FOR NEW GENERATION IN OHIO? A. No. Several other large utility systems, including the AEP System, have generating units located at numerous sites in Ohio. Additionally, merchant plant developers are not finding it difficult to locate new generating projects in Ohio. There are presently at least sixteen applications pending before the Ohio Power Siting Board for new generation facilities in Ohio between now and 2003 that are unaffiliated with the Applicants. These proposed new generation facilities represent over 10,000 MW of capacity. Also. a subsidiary of CME Energy announced plans to construct a new 2,200 MW natural gas fired merchant plant in Lawrence County, Ohio. Although CME has yet to file an application with either the Ohio Power Siting Board or the state's environmental protection agency, CME indicated that it holds an option to purchase 280 acres for the plant site and is in the process of drafting the required state applications. Q. DOES FIRSTENERGY CONTROL FUEL SUPPLIES OR TRANSPORTATION FACILITIES? 155 EXHIBIT NO. APP-100 PAGE 5 OF 16 A. No. FirstEnergy does not own any coal mines or coal transportation facilities, and it procures its coal supplies under a mix of long-term and short-term spot purchase contracts from unaffiliated coal producers. FirstEnergy indirectly owns gas reserves and production, intrastate pipelines, and a small interstate pipeline through its subsidiary, Marbel Energy Corporation ("Marbel"). Marbel owns a small LDC in Ohio (Northeast Ohio Natural Gas Corp.) and Marbel HoldCo, Inc. ("HoldCo"). HoldCo and Range Resources Corporation of Fort Worth, Texas are each fifty-percent owners of Great Lakes Energy Partners, L.L.C. ("Great Lakes"), a joint venture between HoldCo and Range Resources. Great Lakes owns gas reserves and production in the Appalachian Basin. Great Lakes also owns an intrastate pipeline (Ohio Intrastate Gas Transmission Co.) and an interstate pipeline (Gas Transport, Inc.). The intrastate pipeline facilities are located in northeast Ohio. The interstate pipeline, which has a tariff on file with the Commission, is an approximately 100 mile pipeline running between Columbia Gas Transmission Company in West Virginia and Washington County, Ohio. Columbia Gas, Tenneco, Texas Eastern, CNG, and National Fuel dominate the interstate pipeline system in the Appalachian Basin and numerous other parties own gas production facilities in the region. In addition Gas Transport, Inc., Ohio Intrastate Gas Transmission Co., and Northeast Ohio Natural Gas Corp., are subject to open access service requirements. Mr. Frame explains that FirstEnergy's interests in these natural gas production and transportation facilities do not give it the ability to block those that might compete with FirstEnergy in the development of new electric generation. Q. PLEASE DESCRIBE FIRSTENERGY'S TRANSMISSION SYSTEM. 156 EXHIBIT NO. APP-100 PAGE 6 OF 16 A. ATSI owns approximately 7,100 circuit miles of transmission lines of 69 kV or above and 120 substations: 1,153 miles of 345 kV lines; 3,667 miles of 138 kV lines; and 2,279 of 69 kV lines. ATSI now provides open access transmission service over its transmission facilities under a tariff on file with the FERC. OE, CEI, TE and PP receive network integration service from ATSI under the same terms and conditions that are available to all non-affiliated network customers. ATSI has 37 interconnections with six other electric systems, including an interconnection with PJM through Penelec at the Ohio-Pennsylvania border. This interconnection with Penelec is a 345 kV line, known as the Ashtabula-Erie West tie line, and crosses the Ohio and Pennsylvania border. It is approximately 14.9 miles in length and has a summer rating of 1643 MVA and a winter rating of 1781 MVA. OE, TE, CEI, and PP also own approximately 57,000 miles of distribution facilities. The FirstEnergy Companies have been active participants in the formation of the Alliance Regional Transmission Organization ("Alliance"), which is described in the Application and which is the subject of other proceedings before the Commission. FirstEnergy plans to satisfy the Commission's Order No.2000 requirements through participation in the Alliance. Q. PLEASE EXPLAIN WHY FIRSTENERGY AND GPU HAVE DECIDED TO MERGE. A. The merger represents a natural alliance of companies with adjoining service areas and interconnected transmission systems and is a key strategic step in preparing FirstEnergy to be a premier energy services provider in states that have mandated industry 157 EXHIBIT NO. APP-100 PAGE 7 OF 16 restructuring and retail customer choice, including Ohio, Pennsylvania and New Jersey. The advent of retail competition introduces significant new risks and challenges to companies that were until recently service providers in franchised areas. The merger is intended in large part to enhance the Applicants' combined abilities to meet these challenges. Following the merger, FirstEnergy will serve approximately 2 million customers in Ohio, 1.3 million customers in Pennsylvania, and slightly less than 1 million customers in New Jersey. The combined service territories will be more diverse than the individual service territories, reducing exposure to adverse changes in any sector's economic and competitive conditions. Q. PLEASE SUMMARIZE THE STATUS OF RETAIL ELECTRIC COMPETITION IN OHIO AND PENNSYLVANIA. A. In July 1999, the Ohio General Assembly enacted Senate Bill 3, which requires customer choice effective January 1, 2001. In late 1999, OE, TE, and CEI filed retail transition plans with the PUCO as required by Senate Bill 3. In April 2000, the parties to those PUCO proceedings agreed to a Stipulation under which OE, TE, and CEI would implement open access consistent with Senate Bill 3. PUCO approved the Stipulation on July 19, 2000. Beginning January 1, 2001, OE, TE and CEI will provide retail utility service on an unbundled basis and retail customers will have an opportunity to choose among energy suppliers. Also effective January 1, 2001, OE, TE and CEI will freeze their base distribution electric rates through December 31, 2007 and will also lower their unbundled 158 EXHIBIT NO. APP-100 PAGE 8 OF 16 residential tariff rates during a five-year market development period. To ensure the development of a competitive power market, from January 1, 2001 through December 31, 2005, OE, TE, and CEI collectively will make 1,120 MW of power available exclusively for marketers and aggregators to sell to the Companies' retail customers. In addition, OE, TE and CEI will reimburse marketers for certain transmission costs, which will further broaden the market. Further, the Stipulation requires each Company to actively work with the Alliance, the MISO, and other RTO/ISOs and transmission-level customers in the region to develop and implement proposals to address reciprocity and RTO interface/seams issues. The Stipulation also includes "shopping credits" to provide retail customers with an incentive to obtain their power supplies from alternative sources. Senate Bill 3 envisions that at least 20 percent of each company's retail customers will obtain their power supplies from alternative providers. Failure to achieve the 20 per cent threshold level will limit the Companies' recovery of their transition costs. The Stipulation also shortens the period in which the OE, TE and CEI may recover transition costs to December 31, 2006 for OE, June 30, 2007 for TE, and December 31, 2008 for CEI, although these dates are subject to modification in limited circumstances. In December of 1996, the Pennsylvania legislature passed the Electricity Generation, Customer Choice and Competition Act to deregulate the electric industry in Pennsylvania. The Act requires the unbundling of electric services into separate generation, transmission, and distribution services, with open retail competition for generation services. Mr. Bruce Levy, Senior Vice President of GPU, Inc. describes the 159 EXHIBIT NO. APP-100 PAGE 9 OF 16 Pennsylvania restructuring program in more detail. Exhibit No. APP-200 at 8. In sum, the Competition Act required utilities to submit restructuring plans with the PPUC that included an assessment of stranded costs resulting from retail competition. In September 1997, PP filed a comprehensive restructuring plan with the PPUC. In June 1998, the PPUC accepted PP's plan. Under PP's restructuring plan, PP's retail customers are protected from an increase in generation rates until January 1, 2006. On that date, the generation rate will increase by five percent and will remain in effect until January 1, 2007. At that point, PP's retail customers will no longer be subject to a generation rate cap. Q. PLEASE DESCRIBE THE MERGER TRANSACTION, A. Under the Agreement and Plan of Merger, dated August 8, 2000, CPU, Inc. will be merged with and into FirstEnergy Corp., which will be the surviving corporation. Under the Merger Agreement, holders of GPU common stock will be able to choose to receive (i) $36.50 in cash for each share of GPU common stock, or (ii) FirstEnergy common stock, the amount to be determined by an exchange ratio set forth in the Merger Agreement. Under the Merger Agreement, however, unless an adjustment is made as a result of tax considerations, 50 percent of all issued and outstanding shares of GPU common stock must be exchanged for cash and 50 percent must be exchanged for FirstEnergy common stock. The elections of GPU shareholders to receive cash or FirstEnergy common stock are subject to proration because of this provision and also because of a possible adjustment controlled by tax considerations. The merger will be 160 EXHIBIT NO. APP-100 PAGE 10 OF 16 accounted for on a "purchase" accounting basis in accordance with generally accepted accounting principles. Q. PLEASE DESCRIBE THE STRUCTURE OF THE MERGED COMPANY. A. Upon closing of the merger, the GPU Companies will become wholly owned subsidiaries of FirstEnergy Corp. JCP&L, MetEd, and Penelec will continue to operate as separate electric utility operating companies as will OE, CEI, TE and PP. ATSI also will remain a separate subsidiary company of FirstEnergy Corp. With respect to distribution operations, the FirstEnergy utilities will continue to provide service to customers in their respective service territories. Our headquarters will remain in Akron, Ohio. We will maintain offices and presence in Morristown, New Jersey and Reading, Pennsylvania, subject to the authority of the Board of Directors. Attached as Exhibit No. APP-102 is an organizational chart reflecting the anticipated corporate structure of the merged company. Q. ARE THE APPLICANTS MAKING ANY COMMITMENTS TO FACILITATE APPROVAL OF THE MERGER BY THE COMMISSION? A. Yes. I note that these commitments are also described in Section III.B of the Application. The commitments are offered in support of the merger's prompt approval by the Commission without an evidentiary hearing. As to competition and rates, our commitments are: (1) In the event that the Alliance fails to be approved by the Commission, ATSI commits to file an application for approval to participate in another RTO that complies with the RTO Final Rule. 161 EXHIBIT NO. APP-100 PAGE 11 OF 16 (2) The Applicants will hold any and all wholesale requirements customers harmless from any merger-related costs in excess of merger savings. (3) ATSI and GPU Energy will hold any and all transmission customers harmless from any merger-related costs in excess of merger savings. (4) The FirstEnergy Companies will not seek to assert native load preference into PJM as a means to preempt transmission capacity reserved by others. As to regulation, the Applicants waive their OHIO POWER immunity as I explain later in my testimony. These commitments have no adverse impact on the merger commitments the FirstEnergy Companies have agreed to in prior FERC merger proceedings. Q. IS THE MERGER CONSISTENT WITH THE COMMISSION'S GOALS OF OPENING WHOLESALE ELECTRIC MARKETS TO COMPETITION? A. Yes. FirstEnergy and GPU have been supporting the efforts of the FERC to introduce competition to the electric industry. The FirstEnergy Companies are charter members of the Alliance RTO. Likewise, the GPU Companies have been active members of the PJM Interconnection, L.L.C. The prior divestiture by GPU Energy of all but 285 MW of installed generating capacity in combination with the merger significantly advances the Commission's goals because these actions will result in a stronger, larger, more diverse utility company, better able to respond to competition in the restructured utility market, but without raising generation or transmission market power issues. Q. DO THE FIRSTENERGY COMPANIES PLAN TO SELL POWER TO GPU ENERGY AFTER THE MERGER CLOSES TO SERVE ITS LOAD REQUIREMENTS? 162 EXHIBIT NO. APP-100 PAGE 12 OF 16 A. While our plans have not been finalized, it may make economic sense and be possible for us to sell energy to GPU Energy (Penelec, JCP&L and MedEd) during certain off-peak periods. Only off-peak sales are envisioned because FirstEnergy has no capacity to sell on-peak, and even if it did, has no firm transmission reserved to PJM. As I mentioned previously, following completion of the merger, FirstEnergy will compete for firm transmission service into PJM on the same basis as other transmission customers, and will not seek to invoke native load obligations as a means to preempt transmission capacity reserved by other transmission customers. In calculating the competitive effect of the proposed merger, we have asked Mr. Frame to analyze scenarios in which no energy sales are made, and in which off-peak energy sales equivalent to 650 MW during off-peak hours will be made to serve GPU Energy's loads. Q. PLEASE DESCRIBE HOW THE FIRSTENERGY COMPANIES PLAN TO SATISFY THE REQUIREMENTS OF THE FERC'S RTO FINAL RULE. A. As I have mentioned, OE, CEI, TE and PP have already transferred the ownership of their high-voltage transmission facilities to ATSI. ATSI has committed to join the Alliance RTO. On December 20, 1999, the Alliance companies received conditional approval from the Commission to transfer ownership and/or functional control of their jurisdictional transmission facilities to the Alliance RTO subject to acceptance of a later compliance filing. The Alliance companies made a compliance filing on September 15, 2000 to address issues identified by the Commission in its previous orders on the Alliance RTO. The Alliance plans to become an RTO that will achieve full compliance with the RTO Final Rule. 163 EXHIBIT NO. APP-100 PAGE 13 OF 16 Q. ARE THE FIRSTENERGY COMPANIES PLANNING TO RESTRUCTURE THEIR INTERNAL OPERATIONS? A. Yes. Senate Bill 3 requires the FirstEnergy Companies to restructure their operations in Ohio into separate business units. In Pennsylvania, the Competition Act also requires a restructuring of PP's operations. Effective January 1, 2001, the FirstEnergy Companies in Ohio will separate their corporate structures into three units: a Competitive Services Unit, a Corporate Support Services Unit, and a Utility Services Unit. The Competitive Services Unit will hold the companies' generation facilities and all other competitive assets. The Corporate Support Services Unit will provide centralized and common services to the other units, such as accounting, legal, auditing, finance, and human resources. The Utility Services Unit will hold the transmission and distribution facilities. To avoid incurring additional transition costs, the FirstEnergy Ohio Companies are allowed to transfer their generating assets to the Competitive Services Unit on a phased basis. This internal restructuring will be the subject of separate FERC filings to the extent FERC authorization is required. Q. WILL FIRSTENERGY CORP. BECOME A REGISTERED HOLDING COMPANY? A. Yes. FirstEnergy Corp. will become a registered holding company system under the Public Utility Holding Company Act, which is enforced by the Securities and Exchange Commission ("SEC"). Q. ARE YOU AWARE OF THE OHIO POWER DOCTRINE AND THE FERC'S MERGER POLICY WITH RESPECT TO THE PRICING OF NON-POWER 164 EXHIBIT NO. APP-100 PAGE 14 OF 16 GOODS AND SERVICES AMONG AFFILIATES OF A REGISTERED PUBLIC UTILITY HOLDING COMPANY? A. Yes. As to registered holding company systems, the SEC has jurisdiction over non-power intra-affiliate transactions and contracts. Under the OHIO POWER doctrine, in certain instances as to registered holding company systems, FERC cannot disallow the recovery in FERC-jurisdictional rates of any payments made in accordance with SEC-approved transactions. Q. AS A CONDITION OF APPROVAL OF THE MERGER, WILL THE APPLICANTS WAIVE THEIR OHIO POWER IMMUNITY? A. Yes. For rate making purposes, the Applicants agree to follow FERC policy regarding sales of non-power goods and services under contracts between public utility affiliates in a holding company system. The Applicants hereby waive their OHIO POWER immunity. Q. DO THE FIRSTENERGY COMPANIES HAVE ANY RATEPAYERS ENTITLED TO PROTECTION UNDER THE COMMISSION'S MERGER POLICY STATEMENT? A. Yes. We have contracts to provide a small amount of firm power at cost-based rates to a number of municipals and cooperatives in Ohio and to five boroughs in Pennsylvania. ATSI also provides transmission service to these entities. I note also that Mr. Bruce Levy, Senior Vice President of GPU. Inc., will address the two customers that GPU Energy has that are protected customers under FERC's merger policy. 165 EXHIBIT NO. APP-100 PAGE 15 OF 16 Q. WILL THE FIRSTENERGY COMPANIES HOLD THESE CUSTOMERS HARMLESS FROM ANY MERGER-RELATED COST INCREASES? A. Yes. We will hold these customers harmless from any merger-related costs in excess of merger savings, and CPU Energy, as discussed by Mr. Levy, will do the same for its two protected customers. I would note that under the largest wholesale sales agreement that we have, a contact between TE and AMP- OHIO, we have no ability to file for an increase in cost-based rates. Also, the contract is subject to a rate cap for both the base and fuel components of the rate until the end of 2005, at which time base rates are further reduced. Q. WHAT ABOUT ATSI'S TRANSMISSION CUSTOMERS? A. Some of ATSI's transmission dependent customers take service under pre-Order No. 888 grandfathered transmission arrangements. These customers have the right to remain under their grandfathered arrangements in lieu of switching to service under ATSI's open access tariff. Approval of this merger will not affect those arrangements. Such customers will continue to pay the same rates, and have the same rights and obligations, as provided in their grandfathered transmission arrangements. In addition, there are many transmission customers under ATSI's OATT who do not have pre-Order No. 888 transmission rights. The costs underlying ATSI's transmission revenue requirement are unlikely to change materially, if they change at all, as a result of the merger. ATSI commits, however, that it will not seek to include in its 166 EXHIBIT NO. APP-100 PAGE 16 OF 16 transmission revenue requirement under its OATT any merger-related transmission costs in excess of merger savings. When the RTO of which ATSI will be a member implements its OATT, ATSI will extend this commitment to preclude the inclusion of merger-related costs in excess of merger savings from ATSI's revenue requirement in the computation of the RTO's rates. This will ensure that all of ATSI's transmission customers under both ATSI's OATT, and when effective, the RTO's OATT, are held harmless with respect to any adverse cost effects attributable to the merger. Q DOES THIS CONCLUDE YOUR TESTIMONY? A. Yes. 167 AFFIDAVIT STATE OF OHIO ) ) COUNTY OF SUMMIT ) Anthony J. Alexander, being duly sworn, deposes and states: that he prepared the Direct Testimony and Exhibits of Anthony J. Alexander and that the statements contained therein and the Exhibits attached hereto are true and correct to the best of his knowledge and belief. /s/ Anthony J. Alexander ----------------------------------- Anthony J. Alexander President, FirstEnergy Corp. SUBSCRIBED AND SWORN TO BEFORE ME, this the 9th day of November, 2000. /s/ Michael R. Beiting ----------------------------------- Notary Public, State of Printed Name: Michael R. Beiting My Commission has no expiration date [Notary Seal] MICHAEL R. BEITING, Attorney at Law Notary Public -- State of Ohio My Commission has no expiration date. Section 147.03 R.C. 168 EXHIBIT NO. APP-101 169 FIRSTENERGY GENERATING UNIT NDC AND PRIMARY FUEL YEAR IN- NDC PRIMARY PLANT NAME UNIT # SERVICE (MW) FUEL ---------- ------ ------- ---- ------------ ASHTABULA 7 1953 44 Coal ASHTABULA 8 1953 44 Coal ASHTABULA 9 1953 44 Coal ASHTABULA 5 1958 244 Coal ASHTABULA TOTAL 376 BAY SHORE 1 1955 136 Steam BAY SHORE 2 1959 138 Coal BAY SHORE 3 1963 142 Coal BAY SHORE 4 1968 215 Coal BAY SHORE CT 1967 17 #2 Oil BAY SHORE TOTAL 648 BEAVER VALLEY 1 1976 810 Uranium BEAVER VALLEY 2 1987 820 Uranium BEAVER VALLEY TOTAL 1630 R.E. BURGER 3 1950 94 Coal R.E. BURGER 4 1955 156 Coal R.E. BURGER 5 1955 156 Coal R.E. BURGER EMD (3) 1972 7 #2 Oil R.E. BURGER TOTAL 413 DAVIS-BESSE 1 1977 883 Uranium DAVIS-BESSE TOTAL 883 EASTLAKE 1 1953 132 Coal EASTLAKE 2 1953 132 Coal EASTLAKE 3 1954 132 Coal EASTLAKE 4 1956 240 Coal EASTLAKE 5 1972 597 Coal EASTLAKE CT 1973 29 #2 Oil EASTLAKE TOTAL 1262 EDGEWATER 4 1957 100 Gas EDGEWATER CT (2) 1973 48 #2 Oil EDGEWATER TOTAL 148 LAKESHORE 18 1962 245 Coal LAKESHORE EMD (2) 1966 4 #2 Oil LAKESHORE TOTAL 249 MAD RIVER CT (2) 1972 60 #2 Oil MAD RIVER TOTAL 60 MANSFIELD 1 1976 780 Coal MANSFIELD 2 1977 780 Coal MANSFIELD 3 1980 800 Coal MANSFIELD TOTAL 2360 *1 PERRY 1 1987 1265 Uranium PERRY TOTAL 1265 RICHLAND CT (3) 1967 42 Oil/Gas RICHLAND 4 2000 130 Gas RICHLAND 5 2000 130 Gas RICHLAND 6 2000 130 Gas RICHLAND TOTAL 432 SAMMIS 1 1959 180 Coal SAMMIS 2 1960 180 Coal SAMMIS 3 1961 180 Coal SAMMIS 4 1962 180 Coal SAMMIS 5 1967 300 Coal SAMMIS 6 1969 600 Coal SAMMIS 7 1971 600 Coal SAMMIS EMD (5) 1972 13 #2 Oil SAMMIS TOTAL 2233 STRYKER CT 1968 18 #2 Oil STRYKER TOTAL 18 WEST LORAIN CT (2) 1973 120 #2 Oil *2 WEST LORAIN 2 2001 85 #2 Oil *2 WEST LORAIN 3 2001 85 #2 Oil *2 WEST LORAIN 4 2001 85 #2 Oil *2 WEST LORAIN 5 2001 85 #2 Oil *2 WEST LORAIN 6 2001 85 #2 Oil WEST LORAIN TOTAL 545 SENECA 1 1970 210 Hydro SENECA 2 1970 195 Hydro SENECA 3 1970 30 Hydro SENECA TOTAL 435 FIRSTENERGY TOTAL 12957 *1 Reflects uprating from 1248 to 1265 mw expected to occur around March 2001. *2 Reflects units expected to be added by 2001. 170 EXHIBIT NO. APP-102 171 [FIRST ENERGY LOGO] Combined FirstEnergy/GPU Organization Overview
FIRSTENERGY ORGANIZATION FirstEnergy Corp. (FE) | _______________________________________________________________________________________|_________________| | | | __________________________________________________| | | | | - Ohio Edison Company ATSI FirstEnergy Services | | (American Transmission Systems) | | | | | | | | | _________________________|_______________________ | - Pennsylvania Power Company | | | | | | |-- PennPower Energy GPU Capital | | (International Investments) | | | | | | | - Cleveland Electric Illuminating | | |-- FirstEnergy Generation Corp. | Company | | | | | | - Toledo Edison Company | | | | |-- GPU International | | | - Jersey Central Power & Light | | | | |-- GPU Power | | - Metropolitan Edison | | | | - Pennsylvania Electric
[CHART TO CONTINUE BELOW]
FIRSTENERGY ORGANIZATION FirstEnergy Corp. (FE) | _____________________________________________________________________|__________ | | |______________________________________ | | | | FENOC FE Ventures |-- FirstEnergy Facilities (FirstEnergy Nuclear | Services Group Operating Company) | | |-- Marbel Energy Corp. | | | | | |-- MYR Group | | | | | |-- GPU Service, Inc.
172 UNITED STATES OF AMERICA BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION Ohio Edison Company, ) The Cleveland Electric Illuminating Company, ) The Toledo Edison Company, Pennsylvania ) Power Company, American Transmission ) Systems, Inc. and their public utility affiliates ) ) and ) Docket No. EC01- -000 ) Jersey Central Power & Light Company, ) Metropolitan Edison Company, ) Pennsylvania Electric Company and their ) public utility affiliates ) PREPARED DIRECT TESTIMONY OF BRUCE L. LEVY ON BEHALF OF APPLICANTS 173 EXHIBIT NO. APP-200 PAGE 1 OF 11 QUALIFICATIONS AND EMPLOYMENT HISTORY Q. WILL YOU PLEASE STATE YOUR NAME AND BUSINESS ADDRESS? A. My name is Bruce L. Levy. My business address is GPU, Inc., 300 Madison Avenue, Morristown, New Jersey 07962-1911. Q. BY WHOM ARE YOU EMPLOYED AND WHAT IS YOUR PRESENT POSITION? A. I am senior vice president and chief financial officer of GPU, Inc., headquartered in Morristown, New Jersey. In this capacity, I have executive financial oversight for GPU, Inc. and its subsidiary companies. I am also responsible for all domestic and international merger, acquisition and strategic development activities. Q. PLEASE PROVIDE YOUR EDUCATION, PROFESSIONAL QUALIFICATIONS AND EXPERIENCE. A. I was promoted into my current post in 1998 from my previous position as GPU International Group president and chief executive officer and served in that capacity since 1991. I also served as president of GPU Advanced Resources, GPU, Inc.'s non-regulated retail energy subsidiary. I joined GPU, Inc. in 1985 as vice president-business development of the Energy Initiatives subsidiary. I am past president of the Electric Power Supply Association, a national trade association representing competitive power suppliers active in national and international power markets. Prior to joining the GPU system, I held various positions at Stone & Webster Engineering Corporation with 174 EXHIBIT NO. APP-200 PAGE 2 OF 11 responsibility for the design, engineering and construction of utility and industrial power generation facilities. I earned a Bachelor of Engineering Degree from City College of New York and an MBA in finance from New York University. PURPOSE OF DIRECT TESTIMONY Q. WHAT IS THE PURPOSE OF YOUR DIRECT TESTIMONY? A. The purpose of my direct testimony is to support the Section 203 Application filed jointly by FirstEnergy Corp. and GPU, Inc. in this proceeding. The Section 203 Application seeks Commission approval for the merger of FirstEnergy Corp. and GPU, Inc. In particular, my direct testimony describes: (i) the corporate structure of GPU, Inc. and its public utility subsidiaries; (ii) the recent divestiture of substantially all of GPU, Inc.'s generation assets; (iii) the operations of GPU, Inc.'s public utility subsidiaries; and (iv) the effect of the merger on wholesale rates. BACKGROUND Q. PLEASE PROVIDE BACKGROUND TO THE MERGER. A. On August 8, 2000, FirstEnergy Corp. ("FirstEnergy") and GPU, Inc. announced the approval of a definitive merger agreement under which FirstEnergy would acquire all of the outstanding shares of GPU, Inc.'s common stock for approximately $4.5 billion in cash and FirstEnergy common stock. FirstEnergy also would assume approximately $7.4 billion of GPU's debt and preferred stock. Under the agreement, GPU, Inc. shareholders would receive the equivalent of $36.50 for each share of GPU common stock they own, 175 EXHIBIT NO. APP-200 PAGE 3 OF 11 payable in cash or in FirstEnergy common stock, so long as FirstEnergy's common stock price is between $24.24 and $29.63. The combination of FirstEnergy and GPU, Inc. would create the nation's sixth largest investor-owned electric system, based on customers served. As of June 30, 2000, the combined revenues of FirstEnergy and GPU for the previous 12 months totaled $12.0 billion and assets of the companies totaled $38.6 billion. The combined company's principal electric utility operating companies would include FirstEnergy's Ohio Edison Company and its Pennsylvania Power Company subsidiary, The Cleveland Electric Illuminating Company, Toledo Edison Company, and American Transmission Systems, Inc., as well as GPU, Inc.'s electric utility operating companies -- Jersey Central Power & Light Company, Metropolitan Edison Company, and Pennsylvania Electric Company. Together, these companies serve approximately 4.3 million customers within 37,200 square miles of Ohio, Pennsylvania, New Jersey and New York. STRUCTURE OF GPU, INC. Q. BRIEFLY DESCRIBE THE STRUCTURE OF GPU, INC. A. GPU, Inc., headquartered in Morristown, New Jersey, is an electric utility holding company registered under the Public Utility Holding Company Act of 1935. Among other subsidiaries, GPU, Inc. wholly owns three public utility subsidiaries -- Jersey Central Power & Light Company ("Jersey Central"), Metropolitan Edison Company ("MetEd") and Pennsylvania Electric Company ("Penelec") (Jersey Central, MetEd and Penelec do business and are collectively referred to herein as "GPU Energy."). GPU 176 EXHIBIT NO. APP-200 PAGE 4 OF 11 Energy provides retail electric service to residential, industrial, and commercial consumers in portions of Pennsylvania and New Jersey. Penelec, as lessee of the property of the Waverly Electric Light & Power Company, also serves a population of approximately 13,700 in Waverly, New York and vicinity. It also sells electricity at wholesale and provides access to its transmission facilities through the regional open access transmission tariff administered by PJM Interconnection, L.L.C. ("PJM"). The Commission regulates the wholesale rates and services of the companies, and the Pennsylvania Public Utility Commission, the New Jersey Board of Public Utilities and the New York Public Service Commission regulate its retail rates and services in Pennsylvania, New Jersey and New York, respectively. GPU, Inc.'s 1999 revenues were $4.8 billion and its total assets were $21.7 billion. GPU, Inc.'s other subsidiaries include MYR Group Inc., GPU Advanced Resources, Inc., GPU Nuclear, Inc., GPU Service, Inc., GPU Telcom Services, Inc., GPU Power UK in England, Emdersa in Argentina, GPU International Inc. and GPU GasNet. GPU ENERGY'S GENERATION DIVESTITURES Q. HAS GPU ENERGY DIVESTED ITS GENERATION ASSETS? A. Yes. Over the past two years, GPU Energy has divested substantially all of its generating assets through the following transactions: (i) GPU Energy has sold its interest in the Oyster Creek Nuclear Generating Facility to AmerGen Energy Company, LLC ("AmerGen"). The Commission authorized 177 EXHIBIT NO. APP-200 PAGE 5 OF 11 this sale on February 23, 2000. Jersey Central Power & Light Co., et al., 90 FERC (Paragraph) 62,127 (2000); (ii) GPU Energy has sold its interest in 23 generating facilities to Sithe Energies, Inc. The Commission authorized this sale on June 30, 1999. Jersey Central Power & Light Co., et al., 87 FERC (Paragraph) 62,379 (1999); see also Jersey Central Power & Light Co., et al., 88 FERC (Paragraph) 62,223 (1999); (iii) GPU Energy has sold its 20% interest in the Seneca Pumped Storage Hydroelectric Generating Station to The Cleveland Electric Illuminating Company, a subsidiary of FirstEnergy. The Commission authorized this sale on June 24, 1999. Cleveland Electric Illuminating Company, 87 FERC (Paragraph) 62,345 (1999); (iv) GPU Energy has sold its interest in the Three Mile Island Unit 1 Nuclear Generating Facility to AmerGen. The Commission authorized this sale on April 2, 1999. Jersey Central Power & Light Co., et al., 87 FERC (Paragraph) 61,014 (1999); and (v) GPU Energy has sold its 50% interest in the Homer City Generating Station to Mission Energy Westside, Inc. The Commission authorized this sale on January 13, 1999. New York State Electric & Gas Corporation, et al., 86 FERC (Paragraph) 61,020 (1999). In its orders authorizing these sales, the Commission found that the sales would not have an adverse effect on competition, rates or regulation. In fact, as a result of these divestitures, GPU Energy has significantly decreased its ownership of generation, and consequently its share of the generation market. And, although GPU Energy has 178 EXHIBIT NO. APP-200 PAGE 6 OF 11 maintained ownership of its transmission facilities, access to GPU Energy's transmission facilities will continue to be provided through the regional open access transmission tariff administered by PJM. As a result of these sales, GPU Energy now owns only 285 MW of installed capacity. In addition, GPU Energy currently is negotiating the sale of its 50% ownership interest representing approximately 200 MW in the Yards Creek Pumped Storage Facility. Q. WHAT IS THE BACKGROUND TO GPU, INC.'S DECISION TO DIVEST? A. On October 12, 1997, GPU, Inc. announced its intention to begin the process of divesting its generation assets. The announcement reflected a desire to concentrate on GPU, Inc.'s core business of delivering electricity to customers, rather than using resources to expand generation capability enough to be a successful competitor in the merchant generation business. In particular, GPU Inc.'s decision to divest was in response to: (a) the ongoing restructuring of the electric utility industry in the United States, including recent decisions and orders by the Commission promoting additional competition at the wholesale level and open access to transmission facilities; (b) restructuring legislation in Pennsylvania and orders of the Pennsylvania Public Utility Commission requiring the unbundling of different utility functions and the transition to full competition at the retail level; and (c) similar restructuring legislation in New Jersey and orders of the New Jersey Board of Public Utilities. GPU, Inc.'s divestiture received widespread support from the parties participating in the retail restructuring proceedings for GPU Energy in Pennsylvania and New Jersey. 179 EXHIBIT NO. APP-200 PAGE 7 OF 11 GPU ENERGY'S OPERATIONS Q. PLEASE DESCRIBE GPU ENERGY'S CURRENT WHOLESALE OPERATIONS. A. GPU Energy sells energy and capacity at wholesale under cost-based and market-based sales tariffs on file with the Commission. In addition, Penelec has two partial wholesale requirements customers -- Allegheny Electric Cooperative, Inc. ("AEC") and West Penn Power Company ("West Penn"). Penelec sells supplemental "power and energy" to AEC under a 1993 agreement. AEC resells this power and energy to its members, which are retail electric cooperative corporations located in Pennsylvania and New Jersey. In 1999, under the 1993 agreement, Penelec supplied approximately 105 MW of AEC's 313 MW total load. Penelec provides service to West Penn under a 1973 service agreement under Penelec's Tariff No. 1. This service allows West Penn to meet the requirements of approximately 4 MW of isolated load in Clinton County, Pennsylvania. Recently, the Pennsylvania Boroughs of Goldsboro, Lewisberry, Royalton, Berlin, East Conemaugh, Hooversville, Girard, Smethport and Summerhill terminated their wholesale requirements service from GPU Energy. Lewisberry terminated as of May 1, 2000. Goldsboro, Royalton, Berlin, Hooversville, Girard and Smethport terminated as of June 1, 2000. East Conemaugh and Summerhill will terminate as of December 1, 2000. Similarly, the New Jersey Boroughs of Butler, Lavallette, Madison, Pemberton and Seaside Heights terminated their wholesale requirements service from GPU Energy as of June 1, 1999. 180 EXHIBIT NO. APP-200 PAGE 8 OF 11 Q. PLEASE DESCRIBE GPU ENERGY'S RETAIL OPERATIONS AND THE STATUS OF RETAIL ACCESS IN NEW JERSEY AND PENNSYLVANIA. A. As noted above, GPU Energy provides retail electric service to residential, industrial, and commercial consumers in portions of Pennsylvania and New Jersey. In Pennsylvania, MetEd and Penelec (collectively, the "Companies") serve about 1.2 million customers. Retail electric competition was launched in Pennsylvania on January 1, 1997, when the Electricity Generation Customer Choice and Competition Act, 66 Pa. C.S. 2801 et seq., ("Competition Act") became effective. Among other things, the Competition Act: (i) directed the Pennsylvania Public Utility Commission ("PaPUC") to unbundle electric utility rates into separate charges for generation, transmission and distribution; (ii) established "caps" on the generation and transmission and distribution rates electric utilities could charge their customers; and (iii) permitted electric generation suppliers ("EGS's") to provide electric generation services to interested customers over a three-year period commencing January 1, 1999. In accordance with the Competition Act, MetEd and Penelec filed proceedings in 1997 to "restructure" their rates. On October 20, 1998, the PaPUC entered an order in Docket Nos. R-00974008 and R-00974009 which resolved the restructuring proceedings, and approved a comprehensive settlement ("Restructuring Settlement") among the majority of the active parties. Under the terms of the Restructuring Settlement, MetEd's customers received a 2.5% rate reduction effective January 1, 1999 and Penelec's customers received a 3.0% rate reduction effective January 1, 1999. In addition, the Restructuring Settlement also established an initial amount of stranded costs to be recovered from customers via a competitive transition charge through 181 EXHIBIT NO. APP-200 PAGE 9 OF 11 2010. The initial level of stranded costs will be reset based upon the results of GPU, Inc.'s generation divestiture described above. As of the end of September 2000, 812 of the Companies' industrial customers, 12,636 of their commercial customers and 43,544 of their residential customers, representing 29.1% of the Companies' total electric load, had chosen an EGS for their electric supply. In New Jersey, Jersey Central Power & Light Company ("Jersey Central") serves over 950,000 customers. New Jersey's restructuring legislation - the Electric Discount and Energy Competition Act ("EDECA"), N.J.S.A. 48:3-49, ET SEQ. -- became effective on February 9, 1999, and retail competition in New Jersey commenced on August 1, 1999. Among other things, EDECA mandated that all electric public utilities within the State allow customers to purchase energy and capacity from alternative electric suppliers and reduce distribution rates by up to 10%. EDECA also required that the reduced rates remain in effect through a four-year "transition" period ending July 31, 2003. On May 24, 1999, the New Jersey Board of Public Utilities ("Board") approved, with modifications, Jersey Central's Stipulation of Settlement of its restructuring proceedings (BPU Docket Nos. EO97070458, EO97070459 and EO97070460). Consistent with the Board's modification and approval of the Stipulation of Settlement, Jersey Central implemented a 5% rate reduction on that date. Power began to flow from alternative electric suppliers to customers within New Jersey on November 14, 1999. On August 1, 2000, Jersey Central implemented an additional 1% rate reduction. Pursuant to the Board's modification of the Stipulation of Settlement, Jersey Central will implement 182 EXHIBIT NO. APP-200 PAGE 10 OF 11 additional rate reductions of 2% and 3% on August 1, 2001 and August 1, 2002, respectively, resulting in an aggregate 11% rate reduction. This rate reduction will be sustained until the end of the four-year transition period on July 31, 2003, when the rate cap for all electric utilities across New Jersey terminates. As of the end of September 2000, 314 of Jersey Central's industrial customers, 10,962 of Jersey Central's commercial customers and 9,065 of Jersey Central's residential customers, representing 9.2% of Jersey Central's load, had chosen an alternative energy supplier. EFFECT OF THE MERGER ON WHOLESALE RATES Q. WILL THE MERGER ADVERSELY AFFECT WHOLESALE REQUIREMENTS RATES? A. No. The merger will have no affect on GPU Energy's wholesale requirements rates. As noted above, there are only two customers taking wholesale requirements service from GPU Energy - Allegheny Electric Cooperative, Inc. and West Penn Power Company. As described in Section III.B of the Application, in order to ensure that the merger will not adversely affect these two wholesale customers, GPU Energy will hold them harmless from any merger-related costs in excess of merger savings. Q. WILL THE MERGER ADVERSELY AFFECT TRANSMISSION RATES? A. No. First, the merger will have no affect on GPU Energy's transmission rates. After the merger, GPU Energy will remain in PJM and will continue to own its bulk transmission facilities and access to these facilities will continue to be provided through the regional 183 EXHIBIT NO. APP-200 PAGE 11 OF 11 open access transmission tariff administered by PJM. PJM became a fully functional Independent System Operator on January 1, 1998. Moreover, on October 12, 2000 in Docket No. RT01-2-000, PJM and the nine PJM transmission owners jointly filed their Order 2000 Regional Transmission Organization ("RTO") compliance report, seeking Commission certification of PJM as an RTO. This filing sets forth the few enhancements necessary for PJM to meet the Commission's requirements for RTOs. Second, as described in Section III.B of the Application, GPU Energy will hold any and all transmission customers harmless from any merger-related costs in excess of merger savings. Q. THANK YOU. I HAVE NO FURTHER QUESTIONS. 184 EXHIBIT NO. APP-200 STATE OF NEW JERSEY Bruce L. Levy, being duly sworn, deposes and says: that he has read the foregoing questions and answers labeled as his testimony; that if asked the same questions his answers in response would be as shown; and that the facts contained in his answers are true to the best of his knowledge, information and belief. /s/ Bruce Levy ------------------------------------ Bruce L. Levy Sworn to and subscribed before me this 7th day of November, 2000. Elaine R. Evans ---------------------------- Notary Public My Commission expires: 7/11/2001 --------- ELAINE R. EVANS NOTARY PUBLIC OF NEW JERSEY My Commission Expires July 11, 2001 13 185 UNITED STATES OF AMERICA BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION Ohio Edison Company, } The Cleveland Electric Illuminating Company, ) The Toledo Edison Company, } Pennsylvania Power Company, ) American Transmission Systems, Inc. and ) their public utility affiliates ) Docket No. Ec01-___-000 ) ) and ) ) Jersey Central Power & Light Company, ) Metropolitan Edison Company, ) Pennsylvania Electric Company ) and their public utility affiliates ) PREPARED DIRECT TESTIMONY AND EXHIBITS OF RODNEY FRAME ON BEHALF OF APPLICANTS 186 APPLICANTS EXHIBIT NO. APP-300 PAGE i of 75 TABLE OF CONTENTS I. INTRODUCTION 1 -- ------------ II. SUMMARY AND CONCLUSIONS 4 --- ----------------------- III. OVERVIEW OF APPLICANTS' RELEVANT BUSINESS ACTIVITIES 15 ---- ---------------------------------------------------- IV. APPENDIX A SCREENING ANALYSIS AND RELEVANT --- ------------------------------------------ GEOGRAPHIC AND PRODUCT MARKETS 18 ------------------------------ -- A. Relevant Product Markets 19 -- ------------------------ 1. Energy 19 --------- 2. Short term capacity 19 ---------------------- 3. Long term capacity 20 --------------------- 4. Ancillary Services 24 --------------------- 5. Transmission 29 --------------- 6. Retail Electricity 30 --------------------- B. Appendix A Competitive Analysis Screen 30 -- -------------------------------------- C. Destination Markets 34 -- ------------------- V. DATA SOURCES AND ANALYTICAL PROCEDURES 38 -- -------------------------------------- VI. SUMMARY OF SCREENING ANALYSIS RESULTS 65 --- ------------------------------------- VII. VERTICAL MARKET POWER ISSUES 72 ---- ---------------------------- VIII. CONCLUSION 75 ----- ---------- 187 APPLICANTS EXHIBIT NO. APP-300 PAGE ii of 75 EXHIBITS Exhibit APP-301: Resume of Rodney Frame Exhibit APP-302: List of Abbreviations Exhibit APP-303: Schematic Depiction of Destination Markets Exhibit APP-304: Applicants' Energy Sales to other Utilities Exhibit APP-305: System Lambdas Exhibit APP-306: Base Case Economic Capacity Exhibit APP-307: Base Case Available Economic Capacity Exhibit APP-308: Off Peak Flows between ECAR and PJM Exhibit APP-309: Sensitivity for Firm ATC Exhibit APP-310: Sensitivity for Gas Price Basis Differential Exhibit APP-311: Sensitivity for Alliance Transmission Prices Exhibit APP-312: Sensitivity for Zero Transmission Price Exhibit APP-313: Sensitivity for Off Peak 650 MW Sale to GPU Exhibit APP-314: Sensitivity for GPU divesting Yards Creek to PSEG Exhibit APP-315: Sensitivity for Henry Hub gas price decrease by $1 Exhibit APP-316: Sensitivity for Henry Hub gas price decrease by $2 Exhibit APP-317: Sensitivity to Move Pepco Sale Outside PJM 188 APPLICANTS EXHIBIT NO. APP-300 Page 1 of 75 UNITED STATES OF AMERICA BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION OHIO EDISON COMPANY, THE CLEVELAND ELECTRIC ) ILLUMINATING COMPANY, ) THE TOLEDO EDISON COMPANY, ) PENNSYLVANIA POWER COMPANY, ) AMERICAN TRANSMISSION SYSTEMS, INC. AND THEIR PUBLIC ) UTILITY AFFILIATES ) AND ) DOCKET NO. EC01-__-000 ) JERSEY CENTRAL POWER & LIGHT COMPANY, ) METROPOLITAN EDISON COMPANY, ) PENNSYLVANIA ELECTRIC COMPANY ) AND THEIR PUBLIC UTILITY AFFILIATES ) PREPARED DIRECT TESTIMONY AND EXHIBITS OF RODNEY FRAME ON BEHALF OF APPLICANTS I. INTRODUCTION Q. PLEASE STATE YOUR NAME AND POSITION. A. My name is Rodney Frame. I am a Principal with Analysis Group/Economics. Q. WHAT IS YOUR BUSINESS ADDRESS? A. My business address is 1747 Pennsylvania Avenue, N.W., Suite 250, Washington, DC 20006. Q. WHAT IS ANALYSIS GROUP/ECONOMICS? A. Analysis Group/Economics is a consulting firm that provides microeconomic and financial analyses for complex litigation, regulatory proceedings and corporate strategic planning. We have offices in 189 APPLICANTS EXHIBIT NO. APP-300 Page 2 of 75 Cambridge, MA, Washington, DC, New York City, Montreal and Los Angeles, Menlo Park and San Francisco, CA. We have approximately 140 employees. Q. WHAT IS YOUR FORMAL EDUCATIONAL BACKGROUND? A. I received a bachelor's degree in business from George Washington University in Washington, DC. Also at George Washington, I completed all requirements for my Ph.D. in Economics with the exception of my thesis. My graduate studies at George Washington were funded under the National Science Foundation Graduate Traineeship program. Q. PLEASE DESCRIBE YOUR PROFESSIONAL EXPERIENCE. A. I have been employed by Analysis Group/Economics since January 1998. Prior to my affiliation with Analysis Group/Economics, I was a Vice President at National Economic Research Associates, Inc. (NERA), where I was employed from 1984 to January 1998. Most of my work in the last several years, both at Analysis Group/Economics and at NERA, has involved consulting with electric utility clients on a variety of competition related matters including retail competition and restructuring issues, wholesale bulk power markets and competition, transmission access and pricing, mergers and acquisitions and contracting for generation supplies from nonutility suppliers. I frequently address market power concerns in my work. I have testified on numerous occasions on these and related topics, before the Federal Energy Regulatory Commission (FERC), state regulatory commissions, federal and local courts and the Commerce Commission of New Zealand. I frequently speak before industry groups on competition related topics. From 1976 to 1984 I was a Senior Economist with Transcomm, Inc. in Falls Church, VA. There I directed a number of projects concerning market structure and ratemaking in the telecommunications industry, competition among electric utilities, and postal ratemaking. Prior to my affiliation with Transcomm, I worked as 190 APPLICANTS EXHIBIT NO. APP-300 Page 3 of 75 an independent economic consultant advising clients mostly on telecommunications issues. A copy of my resume is included as Exhibit No. APP-301. Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY? A. FirstEnergy Corp. (FirstEnergy) and GPU, Inc. (GPU) have proposed to merge.(1) I have been asked by FirstEnergy and GPU (collectively, Applicants) to provide a competitive assessment of this proposed merger, and in particular to perform the Competitive Analysis Screen that is described in Appendix A of Order 592, the FERC's Merger Policy Statement.(2) An Appendix A analysis addresses potential horizontal market power concerns that might arise from a contemplated merger. In performing this horizontal market power assessment, I also consider, as appropriate, the comments contained in FERC's April 16, 1998 NOPR,(3) which I understand to be pending FERC action in the near future. As well, I examine whether the combination of FirstEnergy and GPU might create vertical market power concerns. Q. HOW IS THE REMAINDER OF YOUR TESTIMONY ORGANIZED? A. Section II summarizes my analysis and conclusions. Section III provides a brief overview of features of Applicants' business activities that are most relevant for an assessment of potential market power concerns. Section IV describes the Appendix A screening analysis and the relevant product and geographic markets included in my study. Section V discusses the data sources and methods used for my screening analysis while Section VI ---------- (1) A variety of abbreviations are used in this testimony. They are identified in Exhibit No. APP-302. (2) Inquiry Concerning the Commission's Merger Policy Under the Federal Power Act: Policy Statement, Order No. 592, 77 FERC (Paragraph) 61,263, issued December 18, 1996. (3) Revised Filing Requirements Under Part 33 of the Commission's Regulations, Notice of Proposed Rulemaking, 83 FERC (Paragraph) 61,027, April 16, 1998. 191 APPLICANTS EXHIBIT NO. APP-300 Page 4 of 75 discusses and summarizes the results. These results, which are shown in a series of tables attached to this testimony as exhibits, include those for both what I refer to as the base case analysis as well as those for a number of scenarios (sensitivity analyses) where potentially important input variables or assumptions are varied. Section VII addresses potential vertical market concerns. Section VIII provides my conclusion. The data and computer models used in my analysis are included in "workpapers" which are provided on compact disks (CD). II. SUMMARY AND CONCLUSIONS Q. WOULD YOU PLEASE SUMMARIZE YOUR ANALYSIS? A. My testimony principally provides an application of the Competitive Analysis Screen of Appendix A of FERC's Merger Policy Statement to the proposed merger of FirstEnergy and GPU. In this analysis, I focus largely upon markets for short-term or non-firm energy. I do not include an analysis of the proposed merger's effect on short-term capacity markets. Analyses of short-term capacity markets generally focus upon quantities of uncommitted capacity held by applicants and their competitors. However, in this case such an examination would be superfluous because neither of the Applicants holds any uncommitted capacity, as that term generally is defined, and therefore cannot realistically be considered as potential sellers of short term capacity. The merger therefore will not remove an independent seller of short term capacity from the market. In addition to assessing the merger's effects on short term energy markets, I also consider whether the merger will have an adverse effect on competition to supply long-term capacity and competition to supply ancillary services. As concerns the former, examinations of market power in long term capacity generally focus upon perceived entry barriers. Because neither of the Applicants has the ability to erect barriers to those 192 APPLICANTS EXHIBIT NO. APP-300 Page 5 of 75 that might compete with them in the construction of new generation capacity, I conclude that the merger will not have an adverse effect on competition to supply long term capacity. I also conclude that the merger will not have an adverse competitive effect on the supply of ancillary services. There is only a single geographic market where each of the Applicants owns generation that is capable of supplying ancillary services, but in that single case Applicants' shares are far too small to suggest potential market power concerns from the combination. Moreover, there appears to be such a surplus of ancillary service capability in that single geographic market that ancillary service prices in all likelihood would be unchanged even if Applicants withdrew their capacity from the market entirely. To perform the Appendix A Competitive Analysis Screen that is used for examining non-firm or short-term energy markets, I assembled available data concerning generator costs and other characteristics, load levels by time period, long term purchases and sales contracts, market prices, transmission prices and losses (both for existing single system and regional tariffs and proposed regional tariffs), and transmission capacities between various market participants including Applicants and their first, second and third tier utilities. Each direct interconnection of Applicants represents a separate destination market for my analysis including as destination markets, as appropriate, groups of entities operating under a single open access transmission tariff. I also assembled data on historical wholesale transactions of Applicants to determine whether this initial list of destination markets should be expanded. Based upon this review, as well as the results that I report below for the individual destination markets that are included in my analysis, I concluded that there was no need to expand the initial list of destination markets. Then, to develop computations for Economic Capacity and Available Economic Capacity, 193 APPLICANTS EXHIBIT NO. APP-300 Page 6 of 75 the two key capacity measures employed in an Appendix A analysis, I first determined the "competitive" price for each destination market. I developed a range of prices for this purpose by looking both at historical system lambda data in the several control areas relevant for my study and publicly available forward price information. For the Economic Capacity measure, I determined what generation could be delivered into each destination market at a delivered price no greater than 1.05 times the competitive price. The generation which can be delivered into each destination market includes both that which already is located within the destination market itself as well as generation which could be imported from the outside. In determining which generators could meet this test, I used the generation cost and transmission price and loss data which had been assembled. Transmission flows into each destination market were capped by transmission limits, both single path nonfirm (ATC in the base case and firm ATCs and TTCs in sensitivity analyses) limits and, where applicable, simultaneous limits as well. As is appropriate for an Appendix A analysis, premerger and postmerger shares and Herfindahl-Hirshmann Indexes (HHIs)(4) were computed using both the generation within each destination market as well as that which could be delivered to the destination market from the outside up to appropriate (path by path and simultaneous) transmission limits. My computations for the Available Economic Capacity measure were performed in the same fashion except that each supplier's native load was deducted from its Economic Capacity in order to determine the Available Economic Capacity which it might have available to sell in the destination market. Determining Available Economic Capacity is becoming ---------- (4) The HHI for a market is equal to the sum of the squared market shares of the individual firms in the market. Thus, a market with four equally sized competitors has an HHI of 2,500 (i.e., 25(2) x 4 = 625 x 4 = 2,500) and a market with 10 equally sized competitors has an HHI of 1,000 (i.e., 10(2) x 10 = 100 x 10 = 1,000). 194 APPLICANTS EXHIBIT NO. APP-300 Page 7 of 75 increasingly difficult as retail customer choice evolves. The process I used was to assume that, for the most part, each traditional supplier that historically had a native load sales obligation continued to serve that same native load. I determined each traditional supplier's native load obligation using publicly filed data which, as appropriate, were escalated to 2001, the study year for my analysis. The only exception that I made to this general procedure for determining Available Economic Capacity concerns GPU, where I employed load forecasts that reflect expected sales losses to competitors. This is conservative in the sense that it will cause GPU's Available Economic Capacity to be higher than if the same procedure used for the other suppliers also was employed for Available Economic Capacity. When I say that it is conservative to do so here and elsewhere, I mean that I have selected a technique or assumption that, in comparison to available alternatives, produces higher HHIs and higher HHI changes. If the merger safely falls short of screening threshold levels when these conservative assumptions are employed, one can be assured that it also will fall short of those screening threshold levels in cases where less conservative assumptions are employed. For my base case analysis, I compute pre and post merger HHIs, and therefore changes in HHIs, for a number of different destination market, season and time period combinations. I examine 12 different destination markets, three seasons (summer, winter and spring/fall) and five different time periods in the summer season and three different time periods in the winter and spring/fall seasons. These different time periods and seasons collectively bound a range of demand and price levels, reflect different generator capabilities and availabilities and incorporate different base case uses of the transmission system. I do the analyses both for Economic Capacity and Available Economic Capacity. 195 APPLICANTS EXHIBIT NO. APP-300 Page 8 of 75 Q. ARE THERE A PRIORI EXPECTATIONS ABOUT WHAT AN APPENDIX A ANALYSIS OF THE FIRSTENERGY-GPU MERGER WILL SHOW? A. Yes. In responding, I will address Available Economic Capacity and Economic Capacity separately. First, as concerns Available Economic Capacity, GPU has sold almost all of the generating assets that it formerly owned and so, given the native load obligations that it retains under the retail customer choice programs now in effect in Pennsylvania and New Jersey where its retail electric service territories are located, is not likely to have any Available Economic Capacity at all. If this is true, then the proposed merger will have no effect at all on concentrations of Available Economic Capacity. As concerns Economic Capacity, the fact that GPU has sold most of the generating assets that it formerly owned also suggests that the concentration effects of the proposed merger will not be great (although not nonexistent as they are for Available Economic Capacity), but there are other important factors as well that support this a priori view. FirstEnergy is located to the west of PJM where GPU is located. Energy principally flows into PJM from the west (where FirstEnergy is located) and south so the principal geographic markets of potential concern with the proposed merger should be those in PJM. If there are no market power concerns from the merger in geographic markets within PJM (i.e., in the PJM destination market itself and in destination markets within PJM defined by important internal PJM interfaces), there are not likely to be market power concerns in any other destination market. Within PJM there are nearly 60,000 MW of generation resources and only about 5,600 MW of simultaneous import capability at most. GPU has sold most of the generation resources that it previously owned within PJM and relies upon purchases in the market to meet a large portion of its commitments to provide energy to its wholesale and remaining retail 196 APPLICANTS EXHIBIT NO. APP-300 Page 9 of 75 customers. Today GPU owns only 285 MW of generation within PJM and has under long term contract only 2,543 MW more.(5) This is a relatively small portion of the total generation available to supply load in PJM - less than 4 percent - and much less than GPU's expected peak demand. FirstEnergy owns an even smaller portion of generation in PJM (less than 3/4 of one percent), just the 435 MW Seneca pumped storage hydroelectric generating facility. The bulk of FirstEnergy's generation is outside of PJM and, to be delivered into PJM, must compete against that of numerous other suppliers in ECAR, the Southeastern Electric Reliability Council (SERC) coordination region and the Mid-American Interconnected Network (MAIN) coordination region. FirstEnergy today has no preferential rights to use the import capability into PJM nor, as Mr. Alexander testifies, will it be seeking to assert any native load priority rights to use the interconnection between it and GPU affiliate Penelec post merger. Both pre and post merger it will be required to obtain tariffed transmission service to be able to make sales into PJM, just as would any other party. Given that the import capability into PJM is limited in comparison to total market size, that FirstEnergy would be allocated only a limited proportion of that import capability using any reasonable allocation procedure, and that each Applicant's pre-merger presence in PJM is relatively small, it is intuitive that the proposed merger will not present realistic horizontal market power concerns in geographic markets within PJM using the Economic Capacity measure. Moreover, since PJM is the geographic region that, given the location of Applicants and the ---------- (5) In arriving at this figure I include (i) GPU's purchases from Qualifying Facilities (1,600 MW), (ii) certain bilateral capacity with energy purchases that it has made from other utility suppliers (100 MW) that extend past year 2001, (iii) its short term buy back from the Oyster Creek nuclear unit (619 MW) that it formerly owned but which now has been sold to AmerGen and (iv) resources owned by its wholesale customer Allegheny Electric Cooperative (AEC) where those resources are used to serve the combined (GPU plus AEC) load (224 MW). I do not include the buy backs from other facilities that GPU formerly owned but now has sold, either because those buy backs do not involve the purchase of energy (as opposed to installed capacity credits) which is the principal focus of my analysis, or because they will expire during 2001 and therefore should not be included in a forward looking merger analysis. I also exclude the purchase of capacity credits from other utilities when 197 APPLICANTS EXHIBIT NO. APP-300 Page 10 of 75 predominant west-to-east direction of power flows, is most likely to be affected by a merger of FirstEnergy and GPU, a "clean bill of health" there strongly suggests that there is likely to be a clean bill of health in other geographic markets as well. On an a priori basis, market power concerns are even less likely in destination markets other than PJM. For example, one destination market included in my analysis is the New York Power Pool (NYPP), but neither merging partner owns generating assets in NYPP (except for nonutility generation (NUG) projects that GPU's GPU International affiliate is in the process of selling to Aquilla Energy, a subsidiary of UtiliCorp United). FirstEnergy's presence in NYPP is even more muted than its limited presence in PJM. NYPP lies to the north of PJM and FirstEnergy's generation generally must pass through PJM to reach NYP (Paragraph) If FirstEnergy's presence in PJM, to which it has a direct interconnection, is relatively small, it follows naturally that its presence in NYPP, with which it is not directly interconnected, will be even less. FirstEnergy is located in ECAR, which lies to the west of PJM. For destination markets to the west (and south) of PJM, GPU is not likely to be an important competitor pre merger because the predominant direction of power flow is west to east and not east to west (or south). This by itself suggests, on an a priori basis, that the proposed merger will not present horizontal market power concerns in those markets because the merger will not be removing a significant competitor from the market. At times when transmission constraints into PJM are binding, which in essence is something that is assumed to be the case in an Appendix A examination of individual destination markets, prices will be higher in PJM than in areas to the west such as ECAR. GPU's incentive naturally will be to sell its ---------- there is no accompanying energy as well as capacity and energy purchases from other utilities that expire before the end of 2001. 198 APPLICANTS EXHIBIT NO. APP-300 Page 11 of 75 output into the market where it can get the higher price, i.e., PJM, and not in markets to the west where lower prices prevail. If GPU's output is sold in PJM, then it is not a competitor in markets to the west and so the merger does not remove a competitor from those markets. The Appendix A screening analysis that I have conducted and report on herein reinforces the a priori perceptions discussed above. Q. PLEASE SUMMARIZE THE RESULTS OF YOUR APPENDIX A SCREENING ANALYSIS. A. Consistent with my a priori expectations, for Available Economic Capacity there are no changes in HHIs resulting from the merger because one of the Applicants, GPU, has sold most of the generating resources that it previously owned and therefore has no Available Economic Capacity at any price level. Its combination with FirstEnergy, therefore, cannot possibly increase concentration of Available Economic Capacity in any destination market. For Economic Capacity, in virtually all cases the merger induced HHI increases that I compute fall below the threshold levels included in Appendix A, which in turn are derived from the April 1992 Horizontal Merger Guidelines of the US Department of Justice and Federal Trade Commission (Merger Guidelines). The only exceptions involve the FirstEnergy destination market where the HHI increases in the summer, spring/fall and winter off peak periods exceed the Merger Guidelines' screening thresholds and the Duquesne Light Company (DQE) destination market, where the HHI increase in the winter and spring/fall off peak periods exceed the Merger Guidelines screening thresholds. However, as I explain further below, I do not believe that these limited screen violations represent a real market power concern arising from the proposed merger. The reasons include the difficulty in exercising market 199 APPLICANTS EXHIBIT NO. APP-300 Page 12 of 75 power during off peak hours through the withholding of capacity when such a high percentage of the capacity operating then consists of units or portions of units (nuclear units and the minimum operating levels for baseload coal units) that cannot be easily or economically withheld. Moreover, the predominant direction of energy flow between ECAR, where FirstEnergy, DQE and numerous other ECAR suppliers are located, and the Mid-Atlantic Area Coordinating region (MAAC), where GPU's generating assets are located, is west to east, that is from FirstEnergy and other ECAR suppliers into PJM. At times when transmission constraints into PJM are binding, which in essence is something that is assumed to be the case in an Appendix A framework when individual destination markets are examined, prices will be higher in PJM than in areas to the west such as ECAR.(6) GPU's incentive is to sell its output into the market where it can get the higher price, i.e., PJM, and not in markets to the west where lower prices prevail. Thus, while the screening analysis and resulting HHI changes might indicate that some of GPU's capacity resources could be competitive in the FirstEnergy and DQE destination markets, or in other ECAR destination markets, during off peak periods, it is relatively rare for energy actually to flow in the east to west direction that would make this a realistic outcome. In addition to these base case analyses, I also analyzed several alternative scenarios where I assume different transmission prices (including those where the proposed Alliance regional transmission tariff is assumed to be in place), transmission capacities, and natural gas prices, as well as further asset sales by GPU. These scenarios collectively bound a range of ---------- (6) If it were not true that prices in PJM were higher than those in ECAR, then there would be no reason for supplies to move from ECAR to PJM in a fashion that creates the constraints that are implicitly presumed to exist in an Appendix A destination market analysis. 200 APPLICANTS EXHIBIT NO. APP-300 Page 13 of 75 expectations about now unknown future market structure and conditions. The results from these sensitivities reinforce the conclusion derived from the base case, which is that the proposed merger of FirstEnergy and GPU does not suggest realistic concerns about the potential exercise of horizontal market power. I also include a sensitivity analysis that assumes, consistent with Mr. Alexander's FERC testimony that is being filed concurrently with the merger application, that post-merger FirstEnergy sends 650 MWH of energy into the PJM ISO's control area during each off peak hour to help GPU meet its energy supply obligations to retail customers in its service territory. As part of this scenario, I assume that FirstEnergy acquires the transmission capacity necessary to implement the energy transfer and that transmission capability available to others therefore concomitantly is reduced. Another sensitivity analysis that I examine assumes, hypothetically, that FirstEnergy's existing sale of 450 MW to Potomac Electric Power Company (Pepco) inside of PJM instead is delivered outside of PJM, which makes more non firm import capability into PJM available to FirstEnergy and other parties. The HHI changes in most of these sensitivity analyses contain the same limited, and inconsequential in my view, off peak screen violations as the base case, but no additional ones. However, in the sensitivity analysis when the 650 MW of energy is shipped from FirstEnergy to PJM post merger in off peak hours, but not pre merger, one effect is to reduce the HHIs in the FirstEnergy destination market and therefore to eliminate the minor base case screen violations referred to above. Q. PLEASE SUMMARIZE YOUR ANALYSIS OF THE PROPOSED MERGER'S POTENTIAL EFFECT ON VERTICAL MARKET POWER CONCERNS. A. I do not believe that the proposed merger presents realistic concerns about vertical market power. Principal vertical market power concerns 201 APPLICANTS EXHIBIT NO. APP-300 Page 14 of 75 involving wholesale electricity supply generally are associated with fears that vertically integrated transmission owners will use their transmission assets to favor sales of their generation over sales of generation by their competitors. GPU already has turned over operational control of its transmission assets to the PJM ISO, so there should be no concern that GPU could use its transmission assets in anticompetitive fashion. Moreover, GPU and the other transmission owners within PJM intend that the PJM ISO become a Regional Transmission Organization (RTO) that will meet FERC's Order 2000 RTO requirements, and have made a filing with FERC to begin that process. This should mitigate any residual concern on this score. FirstEnergy also has committed to participate in either the Alliance or another FERC-approved RTO, which should mitigate concerns that it might be able to use its transmission assets in an anticompetitive fashion. Finally, because of the prevailing west to east power flows from ECAR to PJM, it is the PJM area which is most important for an assessment of the competitive impacts of the proposed merger. Because GPU sold virtually all of its generating assets and is a net purchaser of energy to meet its load commitments, GPU and/or its native load customers will suffer, not benefit, if energy prices in PJM rise. This would more than offset the benefits that FirstEnergy might make on any additional or higher priced energy sales within PJM. Thus, even if the merged firm were able artificially to restrict transmission into PJM, and therefore raise energy prices there, it would lose money if this happened. There is no need for policy makers to be concerned that the merged firm might be motivated to undertake actions that are unprofitable to it. Q. DID YOU ALSO EXAMINE WHETHER APPLICANTS CONTROL ENTRY BARRIERS THAT MIGHT BE USED TO THWART THEIR GENERATION COMPETITORS? A. Yes. I determined that they do not control any such entry barriers (such as sites at which new generation might be constructed, fuel supplies and fuel 202 APPLICANTS EXHIBIT NO. APP-300 Page 15 of 75 transport facilities). Accordingly, the proposed merger should not create or enhance market power concerns on this score. Moreover, while one of FirstEnergy's affiliates does own natural gas pipeline facilities, there are no electric generators served off of those pipelines. This eliminates any concern that the merger might create vertical market power problems for existing electric generators. III. OVERVIEW OF APPLICANTS' RELEVANT BUSINESS ACTIVITIES Q. WHAT TOPIC IS DISCUSSED IN THIS SECTION OF YOUR TESTIMONY? A. In this section I provide a brief overview of Applicants' business activities that are most relevant for a competitive assessment of the proposed merger. Q. PLEASE DESCRIBE FIRSTENERGY. A. FirstEnergy's business operations are described more completely by Mr. Alexander. FirstEnergy is a public utility holding company that was formed from the 1997 merger of Ohio Edison Company and Centerior Energy Corporation. FirstEnergy has four operating company affiliates, Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company and Pennsylvania Power Company (Penn Power). These operating company affiliates have retail electric service territories that cover much of northern Ohio and northwestern Pennsylvania and collectively own or control under long term contract generating facilities with a total capacity of approximately 12,500 MW. The coincident peak demand of the four operating companies (excluding long term wholesale transactions) is forecast to be 11,643 MW for the summer of 2001. Another FirstEnergy subsidiary, American Transmission Systems, Inc. (ATSI), now owns and operates the transmission assets that formerly were owned by FirstEnergy's four operating company affiliates. While these transmission assets now are controlled by ATSI, FirstEnergy 203 APPLICANTS EXHIBIT NO. APP-300 Page 16 of 75 is a participant in the Alliance organization that is seeking Regional Transmission Organization (RTO) status from FERC and has committed to participate in another RTO if the Alliance ultimately is not approved as an RTO by FERC. ATSI's transmission assets interconnect with the following other transmissions systems: Allegheny Energy (Allegheny), American Electric Power Company (AEP), Dayton Power & Light Company (DPL), Duquesne Light Company (DQE), Detroit Edison Company (DetEd) and, through GPU's Pennsylvania Electric Company (Penelec) subsidiary, PJM. There are several smaller electric utility systems in the FirstEnergy control area that are connected to ATSI's transmission system and which receive transmission service from FirstEnergy and in some cases wholesale electric service as well. These smaller systems include Cleveland Public Power, the City of Painesville, 35 municipal systems that are members of and receive their wholesale bulk power from American Municipal Power-Ohio and five municipal electric systems in Pennsylvania (Pennsylvania boroughs). FirstEnergy also provides transmission service to eleven rural electric cooperatives who are members of Buckeye Rural Electric Cooperative, Inc. Retail customer choice already has commenced in Pennsylvania where Penn Power's retail service territory is located and is scheduled to begin in Ohio, where the other of FirstEnergy's operating company subsidiaries are located, beginning January 1, 2001. As part of the restructuring in Pennsylvania, Penn Power's unbundled generation rates are subject to a rate cap through 2005. As part of the retail customer choice program being introduced in Ohio, FirstEnergy's base distribution rates have been frozen through 2007 and FirstEnergy is at risk for a portion of its stranded 204 APPLICANTS EXHIBIT NO. APP-300 Page 17 of 75 cost recovery if customer switching falls short of 20 percent. FirstEnergy has committed to make available up to 1120 MW of generation to competing retail marketers and brokers to enable them to provide retail electric service in Ohio. In addition to its regulated electric business, FirstEnergy also owns FirstEnergy Services, which competes for retail customers in other states plus Marbel Energy Corporation (Marbel), which owns natural gas reserves, production facilities and an intrastate and short interstate pipeline. Q. PLEASE DESCRIBE THE DOMESTIC OPERATIONS OF GPU. A. The domestic business operations of GPU are described more completely in Mr. Levy's testimony. GPU is a public utility holding company with three domestic public utility subsidiaries, Jersey Central Power & Light Company, Metropolitan Edison Company (MetEd) and Pennsylvania Electric Company (Penelec). JCPL, MetEd and Penelec do business as GPU Energy and provide retail electric service principally to customers in New Jersey and Pennsylvania.(7) GPU formerly owned nearly 7000 MW of electric generating facilities but now has sold all but 285 MW as part of the industry restructuring in New Jersey and Pennsylvania.(8) GPU has purchased energy and/or capacity rights from certain of those sold resources but those purchased rights, excluding the ones that expire in the near term, when combined with GPU's remaining owned assets and other (NUG and utility) purchases, sum to levels far below those needed to provide service to GPU's traditional native load customers even after accounting for expected load loss to retail competitors. ---------- (7) Penelec leases the facilities of the Waverly Electric Light & Power Company and through these also provides retail electric service in and around Waverly, New York and vicinity. (8) Not included in these figures are NUG facilities owned by GPU affiliate GPU International that now are in the process of being sold to Aquilla Energy, an affiliate of UtiliCorp United. 205 APPLICANTS EXHIBIT NO. APP-300 Page 18 of 75 As of December 1, 2000 GPU will have only two wholesale customers. GPU sells to Allegheny Electric Cooperative (AEC) its full requirements beyond those met by AEC's purchase of hydroelectric power from the New York Power Authority. As part of the contractual arrangements with AEC GPU receives the output from AEC's 10 percent ownership interest in the Susquehanna nuclear station and its Raystown run-of-river hydroelectric facility. AEC also sells approximately 4 MW of power to Allegheny affiliate West Penn Power. GPU is a participant in the PJM ISO. It has turned over operational control of its transmission service to the PJM ISO and made those facilities available for use under the PJM ISO's open access transmission tariff. The transmission facilities of the PJM ISO interconnect with transmission facilities of FirstEnergy, Allegheny, Virginia Electric and Power Company (VEPCO) and the New York ISO. GPU and the other transmission owners within the PJM ISO have filed with FERC to become an RTO. Retail customer choice has been implemented in both of the principal jurisdictions (Pennsylvania and New Jersey) where the GPU operating companies' retail service territories are located. In both jurisdictions there are currently in effect price caps that govern what GPU's operating company affiliates can charge for unbundled generation service. IV. APPENDIX A SCREENING ANALYSIS AND RELEVANT GEOGRAPHIC AND PRODUCT MARKETS Q. WHAT TOPICS ARE DISCUSSED IN THIS SECTION OF YOUR TESTIMONY? A. In this section of my testimony I describe the Appendix A Competitive Analysis Screen and the determination of relevant geographic and product 206 APPLICANTS EXHIBIT NO. APP-300 Page 19 of 75 markets for a competitive assessment of the proposed FirstEnergy-GPU merger. A. RELEVANT PRODUCT MARKETS 1. ENERGY Q. WHAT RELEVANT PRODUCT MARKETS DO YOU EXAMINE IN YOUR TESTIMONY? A. FERC generally considers three product markets in its market power investigations, short term capacity, long term capacity and short term or non firm energy. In assessing the competitive implications of a merger of FirstEnergy and GPU, only the last of these, short term energy, is relevant or requires any detailed investigation. It is this product market that is the principal focus of my analysis herein, although I briefly discuss long term capacity and ancillary services as well. 2. SHORT TERM CAPACITY Q. PLEASE EXPLAIN WHY SHORT TERM CAPACITY IS NOT A RELEVANT PRODUCT THAT IS INCLUDED IN YOUR ANALYSIS. A. GPU sold most of its generating capacity, and therefore is not realistically a participant in short term capacity markets. Generally, the ability to participate in short term capacity markets is evaluated by looking at a participant's uncommitted capacity, that is its total owned resources plus long term (greater than one year in duration) firm purchases less that required to fulfill its commitment to native load and other firm sales customers (including appropriate planning reserves to support those sales). GPU projects a native load obligation for summer 2001 that is much greater that the long term capacity resources under its control of only 6,316 MW.(9) With this large deficit, GPU clearly cannot participate as a ---------- (9) As indicated, GPU has sold most of the generating capacity that it previously owned. The long term capacity resource total cited in the text includes (i) the relatively small quantity of owned resources 207 APPLICANTS EXHIBIT NO. APP-300 Page 20 of 75 seller in short term capacity markets. While GPU's short capacity position by itself is sufficient to insure that the proposed merger will not have adverse competitive effects in short term capacity markets, FirstEnergy also is short. This further supports the conclusion about the lack of an adverse competitive impact. FirstEnergy forecast a peak demand of 11,871 MW for summer 2000(10) but had committed long term capacity resources of only 12,524 MW.(11) Thus, even using a very low reserve margin of only 6 percent, FirstEnergy, as is GPU, is short of capacity and must rely on short term purchases in the market to meet its summer load obligations. Therefore, it likewise cannot realistically be considered a seller in these markets. 3. LONG TERM CAPACITY Q. PLEASE DISCUSS THE EFFECT OF THE PROPOSED MERGER ON MARKETS FOR LONG TERM CAPACITY. A. FERC has determined as a general matter that market power concerns should not be present in long term capacity markets because of the ability of new firms to enter the market.(12) This general conclusion is reinforced ---------- that GPU has not sold (285 MW consisting of its 50 percent or 200 MW interest in the Yards Creek pump storage facility, its 19.4 MW York Haven hydroelectric facility and its 66 MW Forked River combustion turbine), (ii) certain NUG resources that it has under long term contract (totaling 1,600 MW), (iii) its buyback of energy from the Oyster Creek nuclear unit that it sold to AmerGen (619 MW), (iv) 100 MW of capacity with energy purchases from other utility suppliers, (v) 224 MW of resources owned by AEC but used by GPU to meet the combined GPU plus AEC load and (vi) 3,488 MW in the repurchase of capacity that it sold to Sithe. (Note that the repurchase from Sithe involves capacity but not energy. These capacity rights without energy are not appropriately attributed to GPU in the Appendix A energy market analysis reported on herein.) Not included in this 6,213 MW resource total are contract purchases that expire before the end of 2001 or generating units that GPU has sold that have buyback provisions that expire before the end of 2001. By their very nature, merger analyses should be forward looking and so such soon-terminating purchases ought to be excluded from GPU's total. (10) FirstEnergy's load in this case includes its 450 MW long term "system" or reserved capacity sale to Potomac Electric Power Company (Pepco). (11) This figure is equal to 13,224 MW of Available Capacity shown in FirstEnergy's most recent Long-Term Forecast Report to the Public Utilities Commission of Ohio less 700 MW of firm purchases that will expire by the end of the year and therefore which are not properly reflected in a forward-looking merger analysis. (12) See Promoting Wholesale Competition Through Open Access Non-Discriminatory Transmission Services by Public Utilities, Docket RM 95-8-000 and Recovery of Stranded Costs by Public Utilities 208 APPLICANTS EXHIBIT NO. APP-300 Page 21 of 75 by actual evidence of entry in numerous regions throughout the country, including ECAR where FirstEnergy is located and in the Mid-Atlantic Area Coordinating region (MAAC) where GPU is located.(13) However, FERC considers whether applicants (either merging partners or those requesting initial or continuing market based pricing authority) control entry barriers that might be used to block entry by their competitors. In this case, as I describe below, Applicants do not control entry barriers that could be used to block their competitors. Accordingly, the proposed merger, if consummated, does not present concerns about market power in long term capacity markets. The potential entry barriers usually considered in FERC's market power discussions include control of sites at which new generation might be constructed, control of fuel supplies and control of fuel transport facilities. As concerns sites at which new generation might be constructed, there is ample evidence that site unavailability is not thwarting such new supplies. Within PJM, there are more than 5000 MW of generation currently in operation that are owned by non traditional suppliers including capacity under long term contract to traditional utility suppliers and, as well, nearly 13,000 MW of projects in development that have requested interconnection studies from the PJM ISO just since the beginning of this year. GPU, of course, has sold most of the generating assets that it formerly owned and so it does not have the ability now to expand its owned capacity at those sites or prevent any one else from using them to do so. FirstEnergy owns numerous generating sites, some of which undoubtedly have the potential for siting additional units. But other traditional suppliers also have their own existing sites that could be ---------- and Transmitting Utilities, Docket No. RM 94-7-001, Order 888 Final Rule, 75 FERC (Paragraph) 61,080, April 24, 1996. (13) Mr. Alexander indicates there are at least 16 applications now pending before the Ohio Power Siting Board for nearly 10,000 MW in new generation capacity that is proposed to be on line by the end of 2003. 209 APPLICANTS EXHIBIT NO. APP-300 Page 22 of 75 expanded. These entities include Orion Power Holding, Inc., which owns three generating plants (Niles, New Castle and Avon Lake) located in FirstEnergy's control area that formerly were owned by FirstEnergy. Moreover, as Mr. Alexander testifies, there are at least 16 applications now pending before the Ohio Power Siting Board for nearly 10,000 MW in new generation capacity that would come on line between now and summer 2003. None of the entities making these applications are affiliated with FirstEnergy or GPU. Additionally, as Mr. Alexander also testifies, although an application to the Ohio Power Siting Board has not yet been filed, an affiliate of CME Energy announced last month its intention to construct a new 2,200 MW gas fired merchant plant in Lawrence County, Ohio and indicated that it held an option to purchase the 280 acres required for the plant site. FirstEnergy does not own CME Energy's proposed plant site and therefore cannot restrict its development by denying access to a needed site. From this information, it is evident that Applicants do not control all of the sites at which new generation capacity might be constructed and that site unavailability in fact is not blocking new entrants. Accordingly, there should be no merger induced concerns on this score. As concerns fuel supplies and fuel transport facilities, most new generation facilities today are natural gas fired combustion turbines or combined cycles and so the focus for an entry barrier assessment should be on control of natural gas supplies and transport. GPU does not own any natural gas production, storage or transport facilities in the US and so does not have any ability to thwart potential competitors on this score. FirstEnergy does not own any coal mines or coal transportation facilities and procures coal for its generating stations under a mixture of long term and spot purchases from unaffiliated coal producers. However, through its Marbel Energy Corporation subsidiary (Marbel), FirstEnergy indirectly 210 APPLICANTS EXHIBIT NO. APP-300 Page 23 of 75 owns gas reserves and production. Marbel owns (i) a small LDC that serves 4,700 retail customers in Ohio and (ii) Marbel HoldCo, Inc (HoldCo). HoldCo is a 50 percent owner in Great Lakes Energy Partners, L.L.C. (Great Lakes), a joint venture with Range Resources Corporation of Fort Worth, Texas. Great Lakes owns gas reserves and production in the Appalachian Basin, as well as an intrastate and an interstate pipeline. Great Lakes has annual revenues of approximately $115 million. Great Lakes' intrastate pipeline facilities are located in northeast Ohio, while the interstate pipeline is an approximately 100 mile segment running between an interstate Columbia Gas Transmission line in West Virginia and Washington, County, Ohio. There are no electric generators served off of Great Lakes' two pipelines. Moreover, FirstEnergy's interests in these natural gas production and transport facilities do not give it the ability to block those that might compete with FirstEnergy in the development of new electric generation. There are numerous other interstate pipelines (Columbia Gas, Tenneco, Texas Eastern, CNG and National Fuel) in the same general area and, as well, numerous other parties that own gas production facilities. Moreover, the gas transport facilities owned by Great Lakes and Marbel's LDC all are available for use by competitors under open access tariffs. For the reasons discussed above, there should be no concerns about merger-induced market power in short term or long term capacity markets and so it is only the short term or non firm energy market that should be the principal focus of a competitive investigation of the proposed FirstEnergy-GPU merger. It is for analyzing short term or nonfirm energy that I use the Appendix A screening analysis described below. 211 APPLICANTS EXHIBIT NO. APP-300 Page 24 of 75 4. ANCILLARY SERVICES Q. HAVE YOU ALSO CONSIDERED WHETHER THE MERGED FIRM MIGHT BE ABLE TO EXERCISE MARKET POWER IN ANCILLARY SERVICE MARKETS? A. Yes. While I have not done a detailed analysis, I do not believe that the proposed merger will raise market power problems for the provision of ancillary services. Because of concerns about reliability and the differential costs that would be involved, ancillary services generally are not provided from remote (out-of-control area) locations. This means that the only geographic market of interest for assessing potential ancillary service related market power concerns associated with the FirstEnergy-GPU merger is PJM because it is only within PJM that both Applicants own generation.(14) Within PJM, the only ancillary service that is now procured separately by the PJM ISO at market determined prices is regulation and so that is the only ancillary service that needs to be analyzed now. Q. PLEASE DESCRIBE YOUR ANALYSIS OF THE EFFECTS OF THE MERGER ON THE SUPPLY OF REGULATION SERVICE WITHIN PJM. A. Within PJM, both FirstEnergy and GPU own generating resources that could be used to supply regulation service to the PJM ISO. These units ---------- (14) In the discussion below, I indicate that, at some times, for purposes of an energy market analysis, it may be appropriate to examine destination markets that consist only of portions of PJM. These portions of PJM are defined by important internal interfaces within PJM that at times are constrained. However, for purposes of analyzing regulation and other ancillary services, it is not necessary to consider geographic markets that encompass less than all of PJM. One reason is that FirstEnergy's only generating asset within PJM (Seneca) is located in a different portion of PJM than are the two generating facilities that GPU owns that can be used to provide ancillary services, Yards Creek and Forked River. (Seneca is located to the west of the Central Transfer Interface in PJM while Forked River and Yards Creek are located to the east of the Eastern Transfer Interface.) Also, as concerns regulation specifically, it is my understanding that, even during times when the three internal interfaces within PJM are at their limits, the PJM ISO still acquires regulation on a PJM wide basis, and not from subregions within PJM defined by those internal interfaces. See, e.g., the affidavit of 212 APPLICANTS EXHIBIT NO. APP-300 Page 25 of 75 are, for GPU, its Forked River combustion turbine and its 50 percent interest in the Yards Creek pumped storage facility(15 and, for FirstEnergy, its Seneca pumped storage facility. As I understand it, Seneca is not currently equipped to provide regulation to the PJM ISO but could be equipped to do so in the future. The maximum amount of regulation service that a particular generator can supply to the PJM ISO is equal to the amount by which it can ramp up or ramp down its output within a 5 minute time period. For Seneca this is equal to 150 MW while for Yards Creek and Forked River combined it is equal to 140 MW. The PJM ISO's filing to FERC earlier this year requesting market based pricing for regulation contains some information that can be useful in interpreting these maximum regulating capability figures for FirstEnergy and GPU within PJM.(16) That filing indicates that units within the PJM control area have the ability to supply a total of 2392 MW of regulation service during on peak periods, where the 2392 MW reflects a derating to account for the effects of forced outages. The on peak periods are the only time periods relevant for an assessment of the FirstEnergy-GPU merger because that is the only time that pumped storage facilities such as Seneca and Yards Creek are likely to be generating electricity. During other time periods they are likely to be pumping water to support future peak period electricity generation, but not generating electricity themselves. Conservatively assuming that Seneca and Forked River are included in the PJM ISO's 2392 MW figure for total regulating capability within PJM, (17) ---------- Joseph E. Bowring, the Manager of PJM's Marketing Monitoring Unit, in Docket No. ER00-1630-000. (15) Yards Creek currently is used to provide regulation within PJM. Forked River, while equipped to do so as well, is not currently used in this fashion. (16) See the Affidavit of Joseph E. Bowring in Docket No. ER00-1630-000. While Mr. Bowring's affidavit contains some information that is useful in interpreting the above cited figures concerning regulating capability within PJM, other information that might be helpful has been redacted in the public version of Mr. Bowring's affidavit and therefore was not available to me for my analysis. (17) It is not possible to determine whether or not this is the case from the information contained in the publicly available version of the PJM ISO's filing. As indicated, Seneca is not currently equipped to 213 APPLICANTS EXHIBIT NO. APP-300 Page 26 of 75 this translates into a maximum share of the total regulating capacity of 5.3 percent for FirstEnergy and a maximum share of the total regulating capability of 5.6 percent for GPU.(18) Using the standard "2 x a x b" formula to determine merger induced HHI changes (where "a" and "b" are the pre-merger market shares of the merging parties), this means that the merger of FirstEnergy and GPU will increase the market HHI by no more than 59. From the non redacted portion of the PJM ISO's filing, it appears that the peak period HHI measure of relevance for regulating capacity within PJM, using what the PJM ISO refers to as total as opposed to available (i.e., net of native load requirements) regulation capacity, is 1612. As described below, this portrays a "moderately concentrated" market under the Merger Guidelines. A premerger HHI of 1612 plus a merger induced HHI change of 59 produces a post merger HHI of 1671 which still is in the moderately concentrated range under the Merger Guidelines. A merger induced HHI increase of 59 for a moderately concentrated market falls below the screening threshold levels of the Merger Guidelines. While the indicated HHI increase for regulating capacity within PJM falls below the threshold screening levels of the Merger Guidelines, there is additional and much more significant information that indicates that market power for the supply of regulation in PJM will not result from the FirstEnergy-GPU merger. The PJM ISO's filing with FERC seeking market based pricing for regulation indicated that the highest peak period requirement for regulation in PJM during the next few years, equal to 1.1 percent of forecast peak demand, is approximately 575 MW. This is only a small portion of the 2392 MW that the PJM ISO identified as capable of ---------- provide regulation service in PJM and Forked River, while capable of providing regulation, is not currently used for this purpose. (18) In computing these shares I have adjusted the above identified ramping capabilities (150 MW for Seneca and 140 MW combined for Yards Creek and Forked River) downward (to 134 MW and 127 MW respectively) to account for forced outages and therefore make the figures for Seneca, Yards Creek and Forked River consistent with those in the PJM ISO's analysis. 214 APPLICANTS EXHIBIT NO. APP-300 Page 27 of 75 supplying regulation to the PJM ISO. Such a large excess of supply over requirements suggests that the HHIs are not likely to be useful for assessing potential market power concerns in the context of the FirstEnergy-GPU merger. Were the merged firm to withdraw its regulating resources from the market entirely,(19) either by physical withholding or by bidding "too high", and even if the possibility of new entrants was ignored entirely, other existing suppliers still would have sufficient regulating capacity to be able to meet 350 percent of PJM's peak regulation requirements. The Applicants' withdrawal of their limited regulating capacity therefore would have virtually no discernible effect. Accordingly, Applicants would not be able to exercise market power. Q. YOUR DISCUSSION OF ANCILLARY SERVICES ABOVE CONCERNS ONLY REGULATION. HAVE YOU ALSO CONSIDERED WHETHER THE MERGER OF FIRSTENERGY AND GPU MIGHT CREATE MARKET POWER CONCERNS FOR SUPPLY OF OTHER ANCILLARY SERVICES, SUCH AS SPINNING RESERVE AND OPERATING RESERVE, TO THE PJM ISO? A. Yes. Spinning reserve and operating reserve are not procured separately by the PJM ISO now but are procured in combination with energy in a fashion that makes an energy market analysis the proper tool to assess market power concerns. This argument was advanced by the Supporting Companies in their request for market based pricing authority for sale of energy and certain ancillary services through the PJM ISO in Docket No. ER97-3729-000. It appears to have been accepted by FERC when it approved market based pricing authority. (20) Because the energy market analysis for the proposed FirstEnergy-GPU merger provided herein does not indicate any merger induced market power concerns for energy ---------- (19) In this context, remember that Seneca is not currently used to provide regulation in PJM and that it would be a pro-competitive event in PJM were it to provide regulation in the future. 215 APPLICANTS EXHIBIT NO. APP-300 Page 28 of 75 markets within PJM, the same therefore can be said about spinning and operating reserve as well under the current bundled (energy and ancillary services together) joint procurement process employed in PJM. Moreover, because of the relatively small shares that Applicants hold, the proposed merger will not create market power concerns even if and when PJM moves to unbundled pricing of spinning and operating reserve. The regulation analysis above shows that Applicants' shares of potential regulating capability within PJM are too small to suggest merger induced market power concerns. But almost by definition their shares of spinning and operating reserve capability will be even less than their shares of regulating capability. There is much more generating capacity capable of providing spinning and operating reserve than there is generation capacity that can provide regulation. The denominator used in the share analysis of a spinning reserve or operating reserve computation is much larger than for a regulating capacity computation. For Applicants, however, their numerators are not that much larger because the regulation analysis already includes all of their units that are capable of providing spinning and operating reserve.(21) With a larger denominator, and only slightly larger numerators, Applicants' market shares for spinning and operating reserve necessarily would be below those for regulation. ---------- (20) See 86 FERC (Paragraph) 61,248. (21) The numerators would be slightly higher because Applicants' generators are likely to have somewhat more capability to provide spinning and operating reserve than they are regulation, but not that much more. The other units that GPU owns (York Haven, a run of river hydroelectric facility) or has output rights in that extend past year end 2001 (Oyster Creek, various NUG purchases, plus AEC's interest in Susquehanna and Raystown) that were not included in the regulation analysis are not likely to have sufficient dispatch flexibility to be used for providing spinning or operating reserve ancillary services. FirstEnergy's only generating resource within PJM is Seneca and so it already is included in the regulation analysis. 216 APPLICANTS EXHIBIT NO. APP-300 Page 29 of 75 Q. ARE THERE OTHER ANCILLARY SERVICES WITHIN PJM THAT SHOULD BE CONSIDERED IN ASSESSING POTENTIAL MARKET POWER CONCERNS ARISING FROM THE FIRSTENERGY-GPU MERGER? A. No. One other ancillary service is Reactive Supply and Voltage Control from Generation Sources Service. However, this service is provided on a cost basis within PJM and so, by definition, it is not possible that market power might be exercised. Also, FirstEnergy's and GPU's generators within PJM are not located sufficiently close to each other to be competing sources for this service, which must be provided from localized resources Another potentially relevant ancillary service is Energy Imbalance Service. However, except for certain penalty features, the payments for Energy Imbalance Service are largely tied to the PJM hourly spot energy price. This has important implications for an assessment of market power. Because the energy market analysis included herein indicates that the FirstEnergy-GPU merger will not have adverse effects on energy markets within PJM, there is no need to make a separate analysis of the market power implications of the proposed merger for Energy Imbalance Service. The same analysis that suggests that the merger will not create market power concerns in energy markets within PJM can be used to support a similar conclusion for Energy Imbalance Service. 5. TRANSMISSION Q. DO THE TRANSMISSION LINES OWNED BY FIRSTENERGY AND GPU REPRESENT COMPETING ALTERNATIVES BETWEEN ANY POINTS OF RECEIPT AND POINTS OF DELIVERY? A. No, but I do not believe that it should be an important consideration in assessing this merger even if they did because of (i) GPU's current participation in the PJM ISO, (ii) the intention of GPU and other PJM transmission owners that PJM become an RTO, as evidenced by their 217 APPLICANTS EXHIBIT NO. APP-300 Page 30 of 75 recent FERC filing, and (iii) FirstEnergy's stated intention to participate in the Alliance or another FERC-approved RTO. 6. RETAIL ELECTRICITY Q. PLEASE DISCUSS THE EFFECTS OF THE PROPOSED MERGER ON RETAIL COMPETITION. A. The most important factor for ensuring competitive retail markets, in my view, is ensuring that retailing entities are able to procure the wholesale supplies that they need to resell to their customers in markets that are characterized by an absence of market power. The analyses that I present herein provide comfort on this score, that is, that the merger of FirstEnergy and GPU will not present concerns about the exercise of market power in wholesale energy and capacity markets. Of course, both FirstEnergy and GPU are actual and potential providers of "pure" retailing services in each others' traditional service territories, i.e., where the pure retailing function is considered apart from the wholesale supply function. However, the merger should not create any concerns about reduced competition at this level simply because there are so many firms that are capable of providing these pure retailing services that the reduction of one actual or potential supplier from the market is inconsequential. Accordingly, I do not believe that it is necessary to address this topic further. B. APPENDIX A COMPETITIVE ANALYSIS SCREEN Q. PLEASE DESCRIBE GENERALLY FERC'S APPENDIX A SCREENING ANALYSIS. A. The basic approach under an Appendix A screening analysis is to define individual destination markets, determine the competitive price in each of those individual destination markets and then measure concentration and changes in concentration of ownership of generating resources that are in or can be delivered to that destination market at a delivered price that is no 218 APPLICANTS EXHIBIT NO. APP-300 Page 31 of 75 more than 1.05 times the competitive price. The HHIs produced from this analysis then are compared to the screening threshold levels of the Merger Guidelines. If those screening threshold levels are not exceeded, then it generally will be concluded that the proposed merger presents no concerns about horizontal market power. If the screening thresholds are exceeded, further analyses may be required before it can be determined whether the proposed merger would have adverse competitive effects. In determining which supplies can be economically delivered to each destination market, the analysis must incorporate transmission prices and reflect transmission system limits. The analyses are to be conducted for different seasons and time periods, to reflect a variety of demand and supply conditions. The individual destination markets are to include each entity that is interconnected with one or both of the applicants, plus any additional entities to which at least one of the applicants has made significant sales in the past. For determining the competitive price, FERC in the past has stated a preference for using historical system lambda data. As I discuss more fully below, for my analysis I rely upon both historical system lambda data and publicly available forward price data to determine a range of competitive price levels to use in my analysis. Determining which resources actually can compete in each destination market at a price that is no more than 1.05 times the competitive price (for each season and load period) requires taking into account variable costs (fuel, O&M and emissions) on a generator by generator basis, transmission capacities and transmission prices and losses. Moreover, because it generally will be true that there are more resources competing to use a particular transmission path than that transmission path can accommodate, it is necessary in the analysis to allocate the limited transmission capability among competing suppliers. FERC has stated a preference for using OASIS data for Available Transmission Capability to 219 APPLICANTS EXHIBIT NO. APP-300 Page 32 of 75 determine the transmission quantities to use in the analysis but also has indicated that at times it will be appropriate to incorporate simultaneous as opposed to single path limits into the analysis.(22) Finally, FERC has indicated that there are two different generation capacity measures that ought to be examined in an Appendix A screening analysis. The first of these, Economic Capacity, is all capacity that can be delivered to the destination market at a price that is no greater than 1.05 times the competitive price in that market. The second, Available Economic Capacity, is equal to Economic Capacity less that required to meet the supplier's obligation to its native load customers plus its preexisting firm sales commitments. Q. ARE MEASURES OF TOTAL CAPACITY AND UNCOMMITTED CAPACITY USEFUL IN AN APPENDIX A ANALYSIS? A. Total Capacity is equal to all capacity owned or otherwise controlled by a particular supplier whereas Uncommitted Capacity for any one supplier is equal to its Total Capacity less that required to fulfill its obligations to native load and other firm customers. I do not believe that these measures are required by FERC to be used in an Appendix A analysis, nor do I believe that it would be useful to include them. Because they reflect variable costs and transmission costs and limits, the Economic Capacity and Available Economic Capacity measures that are incorporated in an Appendix A analysis are more sophisticated measures of market participants' abilities to compete in particular markets than are the Total Capacity and Uncommitted Capacity measures. There is no obvious reason to supplement an analysis that already includes more sophisticated capacity measures with some less sophisticated capacity measures and so I have not done so. As indicated, however, neither of the Applicants has any Uncommitted Capacity as that term generally is used ---------- (22) See 80 FERC (Paragraph) 61,039 (1997) re: Ohio Edison Company et al. 220 APPLICANTS EXHIBIT NO. APP-300 Page 33 of 75 and so including it in the analysis now would serve no useful purpose. Moreover, as concerns Total Capacity, the analyses reported on below include some time periods when the market prices are so high that virtually all generation capacity is operating. Analyses during such time periods are akin to Total Capacity analyses although, as required by Appendix A, they incorporate transmission prices (which are not very important in a relative sense in an Appendix A analysis during these high priced time periods) and limits. Q. WHAT ARE THE MERGER GUIDELINES SCREENING THRESHOLD LEVELS? A. Under the Appendix A process, the HHI changes that are computed are to be compared to the threshold levels contained in the Merger Guidelines. The Merger Guidelines considers markets with post merger HHIs less than 1,000 to be "unconcentrated." Mergers in unconcentrated markets ordinarily require no further analysis notwithstanding the level of HHI increase that results from the merger. The Merger Guidelines considers markets with post merger HHIs between 1,000 and 1,800 to be "moderately concentrated." If a merger in a moderately concentrated market causes the HHI to increase by more than 100, the merger, according to the Merger Guidelines, "potentially raise[s] significant competitive concerns" depending on other factors such as ability to collude and barriers to entry. The Merger Guidelines considers markets with post merger HHIs greater than 1,800 to be "highly concentrated." If a merger in such a market causes the HHI to increase by more than 50, the merger "potentially raise[s] significant competitive concerns" according to the Merger Guidelines, again depending on other factors. Importantly, having merger-induced HHI increases that exceed the threshold screening levels of the Merger Guidelines does not mean that a merger must fail on competitive grounds. Rather, it means only that Applicants must provide additional information and that additional analyses must be performed. 221 APPLICANTS EXHIBIT NO. APP-300 Page 34 of 75 C. DESTINATION MARKETS Q. WHAT DESTINATION MARKETS ARE EXAMINED IN YOUR APPENDIX A SCREENING ANALYSIS? A. There are 12 destination markets included in my Appendix A screening analysis, centered on (i) Allegheny, (ii) AEP, (iii) DPL, (iv) DQE, (v) FirstEnergy, (vi) the Michigan Electric Coordinating System (MECS), (vii) NYPP, (viii) PJM and portions of it termed (ix) PJM West/Central/East, (x) PJM Central/East and (xi) PJM East and (xii) VEPCO. In one way or another, each of these entities or aggregation of entities is directly interconnected with at least one of the Applicants. These destination markets are depicted schematically in Exhibit No. APP-303. FirstEnergy's transmission facilities are directly interconnected with Allegheny, AEP, DPL, Detroit Edison Company (DetEd), DQE and GPU operating subsidiary Penelec. I define and analyze separate destination markets centered on four of these entities taken individually, Allegheny, AEP, DPL and DQE. DetEd, along with Consumers Energy, is a participant in MECS, which has its own single system open access transmission tariff. Accordingly, I define a separate destination market centered on all of MECS and not just DetEd with which FirstEnergy is directly interconnected. Doing so is consistent with FERC precedent as I understand it. Penelec and GPU's other operating subsidiaries are participants in the PJM ISO's single system open access tariff. Accordingly, also consistent with FERC precedent, I examine a separate destination market centered on the entirety of PJM and not just the particular systems within PJM that are directly interconnected with one or both of the Applicants. 222 APPLICANTS EXHIBIT NO. APP-300 Page 35 of 75 Because GPU is a participant in the single system PJM open access transmission tariff, I consider GPU's interconnections to be entities directly interconnected with any of the transmission facilities operated by the PJM ISO, not just those owned by GPU. For this reason VEPCO is included as a separate destination market in my study. VEPCO's transmission lines connect with those of Pepco which, along with GPU, is one of the entities whose transmission facilities are operated by the PJM ISO. The transmission facilities operated by the PJM ISO also are directly interconnected with those operated by the New York ISO. Because the New York ISO also has a single system open access transmission tariff, I include the entirety of the New York ISO as a separate destination market as well. In addition to the destination markets identified above, I also examine separate destination markets reflecting portions of PJM to account for times when important internal interfaces within PJM are at or close to their limits. Within PJM there are three well recognized internal interfaces (referred to as the Eastern, Central and Western interfaces) that sometimes reach their limits for west to east transfers. I refer to the separate destination markets demarcated by these internal interfaces as PJM/East, PJM Central/East and PJM West/Central/East, where PJM East represents the area within PJM to the east of the Eastern interface, PJM Central/East represents the area within PJM to the east of the Central interface and PJM West/Central/East represents the area within PJM to the east of the Western interface. PJM Central/East includes all of PJM East and PJM West/Central/East includes all of PJM Central/East. I do not examine as separate destination markets areas in PJM that lie to the west of these three important internal interfaces, because the predominant direction of energy flow within PJM is west to east and because of my understanding that 223 APPLICANTS EXHIBIT NO. APP-300 Page 36 of 75 these internal interfaces have not been binding in the past in the opposite direction. As indicated, I include a separate destination market centered on FirstEnergy. The FirstEnergy market can be used for assessing the potential competitive effects of the proposed merger on the smaller electric utilities (such as Cleveland Public Power, the City of Painesville, AMP-Ohio and the Pennsylvania boroughs) that are directly connected to FirstEnergy's transmission system. Similarly, other of the destination markets (including PJM and the disaggregated portions of PJM) can be used to assess the potential competitive effects of the proposed merger on smaller systems located in those destination markets. Thus, because both are located within PJM, the effects of the merger on the Allegheny Electric Cooperative, GPU's principal remaining wholesale customer(23), and the Wellsboro Electric Company, one of FirstEnergy's wholesale customers, can be assessed using the figures reported for the PJM destination market. Q. HAVE YOU INCLUDED AS PART OF YOUR APPENDIX A ANALYSIS ANY INDIVIDUAL DESTINATION MARKETS OTHER THAN THOSE CENTERED ON ENTITIES DIRECTLY INTERCONNECTED WITH ONE OF THE APPLICANTS? A. No. I examined historical information concerning the Applicants' sales to other utilities to see if it was appropriate to include additional destination markets and determined that it was not. Exhibit No. APP-304 is a table that shows MW quantities and revenues from wholesale sales made by each of the Applicants during the last three years (1997-99). The information for GPU comes from the Form 1s filed by its three operating company subsidiaries while that for FirstEnergy was provided to me by FirstEnergy. There is only one utility that both Applicants made sales to ---------- (23) As indicated, however, GPU also sells approximately 4 MW to Allegheny affiliate West Penn Power. 224 APPLICANTS EXHIBIT NO. APP-300 Page 37 of 75 during this time period that is not included as a destination market in my analysis, either on its own or as part of a larger area (e.g., PJM). That one entity is Cinergy, with GPU having sold a total of 15 GWH to Cinergy during the three year period and FirstEnergy having sold a total of 431 GWH. For the three year time period these amounts represent only 1/100 of one percent (GPU) and 2/10 of one percent (FirstEnergy) of Cinergy's system input. However, while both Applicants have historically made some wholesale sales to Cinergy, I do not believe that it is necessary to include a separate Cinergy destination market in my study in order to assess the affects of the proposed merger or that any useful information would be provided were I to do so. Cinergy is simply too remote from Applicants to think that there will be a discernable HHI change from the merger if it were analyzed as a separate destination market. Neither of the Applicants is directly interconnected with Cinergy and therefore, to make wholesale sales to it, would have to go through an intermediate system. FirstEnergy can reach Cinergy using either the AEP or DPL transmission systems while GPU would require transmission service from either (i) FirstEnergy and AEP or DPL or (ii) Allegheny and AEP (plus, of course, the PJM ISO). However, in the results that I report below, the effects of the FirstEnergy-GPU merger in both the AEP and DPL destination markets are very small, never even approaching the Merger Guidline's threshold screen levels. The merger induced HHI changes necessarily would be much smaller in the Cinergy market, which requires the extra wheel through AEP or DPL (for FirstEnergy) and Allegheny plus AEP (for GPU) and where the presence of Applicants as a result would be that much less. Because of the location of the Applicants' resources, if their merger passes competitive muster in the AEP and DPL markets, then it also must pass competitive muster in markets that are even more remote and where wheeling through AEP or DPL would be required in order to make sales. 225 APPLICANTS EXHIBIT NO. APP-300 Page 38 of 75 Exhibit No. APP-304 does not indicate any other potential destination market utilities to whom both Applicants have made sales during the past three years but it does indicate certain utilities that one of the Applicants has made sales to during that time period that are not included as separate destination markets in my analysis. However, for the same reason as discussed above (i.e., no need to examine more remote destination markets when there are only insignificant merger-related effects in less remote destination markets), I have not examined individual destination markets centered on any of these other utilities. The results from the 12 destination markets that I did examine suggests that it would be pointless to include any additional destination markets in my study. The merger-induced HHI changes for the most part are very small in all of the destination markets examined. The merger induced HHI changes would be even smaller if additional markets more remote from Applicants' generating resources were studied simply because Applicants' relative influence in those additional, more remote markets would be that much less. V. DATA SOURCES AND ANALYTICAL PROCEDURES Q. WHAT STUDY YEAR DO YOU USE FOR YOUR ANALYSIS? A. Merger analyses should be forward looking and so my study models conditions as they are expected to exist in calendar year 2001. To use a calendar 2001 study year requires, in many cases, adjusting certain historical data to bring it forward in time. The procedures I use to do so are described below. I use calendar year 2001 as a representative time period to examine the likely competitive effects of the merger in the near term. In some respects, however, the use of such a near term time period for the assessment acts to overstate the effects of the merger as measured in my study. Over time, as GPU sells its remaining owned generation, as 226 APPLICANTS EXHIBIT NO. APP-300 Page 39 of 75 the energy sell back provisions from GPU's Oyster Creek sale expire, as new merchant capacity enters commercial operation and as new regional transmission tariffs are implemented, the impacts of the proposed merger, however limited they are shown to be in my study, will be even less. Q. PLEASE DESCRIBE THE DATA SOURCES USED IN YOUR ANALYSIS. A. Conducting an Appendix A analysis requires assembling data for, among other things, generation ownership, generator capacities and variable costs, purchases and sales transactions between marketplace participants, load responsibility by supplier, transmission capacity both on path by path and simultaneous bases and transmission prices and losses. My principal source for data concerning generator size, type, location, and ownership was the 1999 EIA Form 860A and the 1998 EIA Form 860B. This was supplemented with information provided by RDI. Generators were derated for outages based upon information in NERC's "Generating Unit and Statistical Brochure 1994-1998" with adjustments made for peaking units when the NERC outage factors seemed too high. Forced outages were assumed to occur throughout the year while maintenance was assumed to occur during the spring/fall season only. Information for generator heat rates comes from EIA Form 860 for 1995, the latest year for which such information is publicly available. For units that have been added since 1995, the heat rates were estimated from information available for comparable units. SO2 emissions costs for coal units were developed principally from RDI and FERC Form 423 information for sulfur and heat contents, EIA Form 860 for heat rates and Cantor Fitzgerald for allowance prices. Scrubbed units were identified using the latest version of the EIA Clean Air Act Browser, as supplemented with information from RDI. Emissions rates 227 APPLICANTS EXHIBIT NO. APP-300 Page 40 of 75 for units that are scrubbed were assumed in my analysis to be decreased by 90 percent from those that otherwise would be estimated. Scrubbing was assumed to increase variable O & M costs by $1.30 per MWH. I also included costs for NOx emissions for generating units located in the northeast. I used NOx emissions data from EPA's Emissions Scorecard 1999 and allowance price estimates and variable O&M cost adders provided by FirstEnergy. In some cases I also used emissions information provided by RDI. Q. HOW DID YOU DETERMINE WHAT FUEL PRICES TO USE IN YOUR ANALYSIS? A. For prices for natural gas, I employed two procedures. With the first, I developed month by month and plant by plant prices paid for delivered spot natural gas from FERC Form 423 information for the years 1995 to 1999. I then subtracted month by month historical prices at Henry Hub from the Form 423 plant by plant figures to develop monthly basis differentials for each plant. To reflect different seasonal transportation costs, the basis differentials then were averaged, weighted by the quantity purchased in each reported transaction, for all Januarys, Februarys,..., Novembers and Decembers from the different years. The resulting basis differentials for each month then were added to NYMEX futures prices for Henry Hub for December 2000 through November 2001 to obtain delivered price estimates appropriate for the 2001 study year for each plant. I used December 2000 for this computation rather than December 2001 so that my winter figures would be based on three consecutive calendar months. When Form 423 prices were not available for a particular plant for a particular month, the quantity-weighted average prices paid for deliveries to other plants in the region (or adjacent regions) were used. The resulting monthly forecast prices for each plant then were averaged to produce prices for the summer, winter and spring/fall seasons used in the analysis. 228 APPLICANTS EXHIBIT NO. APP-300 Page 41 of 75 I had some concern that the above described procedure for estimating delivered natural gas prices to each natural gas fired plant might at times overstate the true basis differential. This would be true if the delivered Form 423 prices included some perhaps small but unknowable amount of fixed fuel transport costs. To mitigate concern on this score, I also employed an alternative procedure. With it I determined the basis differential, again plant by plant and month by month, using historical information from Bloomberg both for Henry Hub prices and for deliveries from various pipelines to various locations. Each of the gas fired generators was mapped to one of the locations for which Bloomberg reports this historical information. As with the first procedure, the resulting differential, again on a month by month basis, was added to the adjusted NYMEX futures price to obtain delivered natural gas price estimates for the study period. The monthly figures then were averaged to provide seasonal values. The procedures used to develop prices for the other fuels were much simpler. For fuel types that had widely reported spot purchases, such as coal, No. 2 fuel oil and No. 6 fuel oil, I used as a basis historical FERC Form 423 prices from the 1995 to 1999 time period. I escalated these to August 2000 levels using fuel specific producer price escalators from the Bureau of Labor Statistics, and then raised these now current values to the study year using EIA forecast fuel specific price increases. When Form 423 prices were not available for a particular plant for a particular month, the quantity weighted average prices paid for deliveries to other plants in the region (or adjacent regions) were used. For fuel types where no spot transactions were reported in the Form 423s, prices for other fuels were used as a proxy, e.g., No. 2 fuel oil for jet fuel. 229 APPLICANTS EXHIBIT NO. APP-300 Page 42 of 75 Q. DID YOU DO ANY SENSITIVITY ANALYSES THAT ADJUST FOR THE RECENT UPTURN IN NATURAL GAS PRICES? A. Yes. Natural gas prices at Henry Hub have increased by roughly 150 percent since the beginning of this year. The futures prices that I use in my base case analysis embody this recent dramatic increase, which has produced Henry Hub prices in the neighborhood of $5 per mmbtu. I perform sensitivity analyses that assume lower natural gas prices than this, one where the price is $1 per mmbtu lower and another where the price is $2 per mmbtu lower. Q. HOW DOES YOUR STUDY INCORPORATE NEW GENERATION CAPACITY ADDITIONS THAT ARE NOT INCLUDED IN THE GENERATION DATA BASE THAT YOU HAVE DESCRIBED? A. The publicly available EIA data source that I relied upon for identifying generators to use in my analysis was current as of 1998. I supplemented this data base with units that could be identified from public sources (including RDI) as being added during 1999 and 2000, or were projected to be added during 2000 and 2001 and indicated as being under construction. The complete list of generating units is included in my workpapers. Q. HOW DID YOU DETERMINE THE MARKET PARTICIPANTS' LOADS FOR USE IN DETERMINING THEIR AVAILABLE ECONOMIC CAPACITY? A. I developed peak load information for market participants from a variety of sources including EIA Form 411 reports, individual supplier load and resource reports and other sources such as FERC Form 1s, Electric Utility Week, Electric World Directory 2000, and EIA Form 861. I used peak demands as forecast for calendar year 2001. Where the peak demands were historical, they were inflated to year 2001 using regional escalators. 230 APPLICANTS EXHIBIT NO. APP-300 Page 43 of 75 Q. WHAT SEASONS AND TIME PERIODS DID YOU INCLUDE IN YOUR ANALYSIS? A. My analysis includes three seasons (summer, winter and spring/fall) and "super peak," peak and off peak time periods within each of these. As well, I include two separate and even higher demand summer peak periods to reflect the type of system conditions that can give rise to extraordinary price run ups such as have been seen for short time periods the past few summers. Accordingly, there are a total of 11 different seasonal and time period "slices" included in my analysis. I used EIA Form 714 information on hour by hour loads in conjunction with the peak demand information to determine demand for each season and time period in the study. When utility specific load shapes were not available, I used a load shape from a nearby supplier which peaks in the same season. Looking at different seasons and time periods in the fashion that I have allows the analysis to incorporate a full range of market clearing price levels. It also allows the analysis to reflect different seasonal transmission limits and different seasonal availabilities. I define the summer season as the months of June, July and August, the winter season as the months of December, January and February, and the spring/fall season as all other months. During each season the peak hours are from 6:00 AM to 10:00 PM while the off peak hours are all other hours. Additionally, to reflect the possibility that prices might rise significantly during just a few peak hours per year, I also defined "super" peak periods that, for each season, consisted of just the few hours when demand was the highest. During the winter and spring/fall periods, I looked separately at the 150 hours when demand was the highest, calling this the "super peak" and calling all remaining peak hours the "peak." During the summer, when extreme price increases seem most likely, I defined and analyzed separate periods consisting of the 50 hours with the greatest load ("super peak I"), the 100 hours with the next greatest loads 231 APPLICANTS EXHIBIT NO. APP-300 Page 44 of 75 ("super peak II") and the 400 hours with the next greatest loads ("super peak III").(24) The remaining peak period hours are referred to simply as "peak". Q. DO YOU ADJUST THE VARIOUS MARKET PARTICIPANTS' DEMANDS TO REFLECT ESTIMATES OF LOAD LOST TO COMPETING SUPPLIERS IN JURISDICTIONS WHERE RETAIL CUSTOMER CHOICE HAS BEEN INTRODUCED? A. For the most part, no. There is no sufficient publicly available information to do so nor is there, in my view, a non arbitrary procedure that could be employed. As FERC has recognized in a not unrelated context, involving an application for market based pricing authority, substantial uncertainty is involved in seeking to do so.(25) As an alternative, I made the assumption that each traditional supplier continues to meet the same native load obligations that it always has. This approach has the merit of treating suppliers in symmetric fashion and not producing different results depending on whether optimistic or pessimistic forecasts of customer load retention are employed. Of course, the load estimates are utilized in an Appendix A analysis only in the process to determine Available Economic Capacity. In the current study, I determined that GPU has no Available Economic Capacity even when I ignore potential load loss to competitors. This means that, even using this very conservative assumption, the merger will not have any affect on concentration of Available Economic Capacity and therefore that it is not particularly important if the load values for other market participants are not stated precisely. ---------- (24) I used the highest demand hours on the FirstEnergy system for this categorization, which then was applied to all other suppliers. (25) See EME Homer City Generation, L.P., 86 FERC (Paragraph) 61, 016 (1999). 232 APPLICANTS EXHIBIT NO. APP-300 Page 45 of 75 Q. ARE THERE ANY CURRENTLY EXISTING LONG TERM PURCHASE OR SALE TRANSACTIONS BETWEEN FIRSTENERGY AND GPU? A. No. Q. HOW DID YOU IDENTIFY THE PURCHASE AND SALE TRANSACTIONS TO INCLUDE IN YOUR STUDY? A. The purchase and sales transactions of interest for an Appendix A analysis are those that are long term in nature. Purchase and sale transactions which are short term in nature or which expire in the near term should not be incorporated in a forward looking merger analysis. The study year that I use for implementing the Appendix A Competitive Analysis Screen is calendar year 2001. So, for purposes of my study, I sought to identify and properly attribute only those purchase and sale transactions that extended past year 2001. Thus, purchase or sale transactions that expire during or before 2001 are excluded. The category of excluded purchase transactions, among other things, properly encompasses purchases that, as indicated, the Applicants intend to make during the upcoming months to meet their summer 2001 load responsibilities as well as soon-to-terminate buybacks from some of the units that GPU has sold. Applicants supplied information on their own long term purchases and sales. FirstEnergy has only two long term purchases that extend past the end of year 2001 and therefore which are properly included in an Appendix A screening analysis. One of these is the output that is likely to be made available to it as one of the joint owners of the Ohio Valley Electric Company (OVEC). The bulk of OVEC's output historically has been sold to the United States Enrichment Corporation (USEC) or its predecessor, and the amount available to FirstEnergy and the other joint owners has been only that which is not required by USEC for uranium enrichment. USEC's requirements from OVEC now are on the decline, 233 APPLICANTS EXHIBIT NO. APP-300 Page 46 of 75 however. FirstEnergy has provided an estimate of the amount of energy that is likely to be available to it and the other joint owners of OVEC during 2001 and these amounts have been attributed as resources to FirstEnergy and the other joint owners in my study. FirstEnergy's only other long term purchase that extends past the end of year 2001 is a 300 MW unit purchase from DetEd's interest in the Ludington pumped storage facility in Michigan. Similar to what is done with the other purchase and sale transactions, this amount is added to FirstEnergy's resource total and subtracted from that of DetEd. FirstEnergy makes long term capacity and energy sales to Pepco, Wellsboro Electric Company (Wellsboro), the City of Painesville and AMP-Ohio.(26) The most significant long term sale is a 450 MW "system" sale to Pepco. For my base case, I have subtracted this amount from FirstEnergy's resources (plus an additional amount to account for reserves, appropriate in the case of a sale of this nature) and added it to Pepco's resources.(27) FirstEnergy provided pricing information to allow the resources for this transaction to be deducted from its supply stack appropriately, and added to that of Pepco.(28) I also include a sensitivity analysis that assumes that this 450 MW is not delivered to Pepco in PJM but, instead, is delivered to another supplier (Allegheny) at a delivery point outside of PJM. ---------- (26) FirstEnergy also sells regulation, spinning and operating reserve to DQE under a transaction that runs until May of 2002. Because some of the resources that FirstEnergy needs to support this sale (up to 78 MW) could also be used at least at times to provide nonfirm energy, I have not subtracted them from FirstEnergy's totals in determining its Economic Capacity and Available Economic Capacity for my study. It is conservative to attribute this capacity to FirstEnergy in calculating post merger HHIs. (27) FirstEnergy includes its obligation under this transaction as part of its load. For consistency, in determining FirstEnergy's load for purposes of computing Available Economic Capacity in my study, I subtracted the 450 MW Pepco obligation from FirstEnergy's load. (28) Pepco has sold certain of its generating assets and rights under power purchase agreements to an affiliate of Southern Energy International (SEI). However, for my study, I attribute this capacity to Pepco and not SEI assuming, as is discussed below and as is consistent with trade press accounts, that there are interim period sellback arrangements under which Pepco will buyback energy from the capacity it sells to SEI. 234 APPLICANTS EXHIBIT NO. APP-300 Page 47 of 75 FirstEnergy also sells the equivalent of requirements power to Wellsboro, which is located in the PJM control area, under a five year contract that extends until 2003. In my study, this sale is treated as an addition to FirstEnergy's load rather than a subtraction from its capacity.(29) This is conservative and tends to increase FirstEnergy's shares and the merger induced HHI changes, albeit by a relatively small amount. FirstEnergy also sells up to 50 MW to the City of Painesville, which is located in the FirstEnergy control area, on a year round basis. The sale to Painesville involves stated energy prices except during 250 hours per year when the energy prices are market based. The billing demand is determined by Painesville's actual monthly take from FirstEnergy under the contract without any minimum contract demand or ratchets to account for variations in the actual month to month takes. In fact, there has been substantial month to month variation in the extent to which Painesville has used this contract since its August 1999 inception, with Painesville in some months using the full 50 MW but in other months using none at all. For purposes of the screening study, I have chosen to ignore FirstEnergy's obligation to sell capacity and energy to Painesville under this contract. This is a very conservative approach because it attributes too much capacity to FirstEnergy and therefore artificially overstates the HHIs and merger induced HHI changes. The alternative approach, to attribute the 50 MW to Painesville and deduct it from FirstEnergy's share, seemingly would be misleading, and difficult to implement in nonarbitrary fashion for an energy market analysis, because Painesville pays no demand charge in months when it does not take any energy under the contract. Finally, FirstEnergy also sells 42 MW of capacity and energy to AMP-Ohio under contract arrangements that extend through 2008. Because the --------- (29) The load data used to determine FirstEnergy's Available Economic Capacity includes the Wellsboro obligation. 235 APPLICANTS EXHIBIT NO. APP-300 Page 48 of 75 load that is served by this sale is included in FirstEnergy's load forecast, I have not deducted the resources to serve this load from FirstEnergy's total. This is a conservative way to treat this transaction because it artificially overstates FirstEnergy's shares of Economic Capacity, albeit by a relatively small amount. GPU has no long term sales that have been included in my analysis.(30) Its long term purchases appropriate for inclusion in my energy market analysis include those from (i) several NUGs, (ii) other investor owned utilities, (iii) the buy back of energy from the Oyster Creek nuclear unit that it sold to AmerGen and (iv) AEC's interest in the Susquehanna nuclear station and a run-of-river hydroelectric facility. GPU also has entered into energy buy backs from sale of its interest in the Homer City units that it sold to Edison Mission Energy (EME) and from its sale of the Three Mile Island I nuclear unit to AmerGen, but those buybacks expire during 2001 and therefore are not reflected as a GPU energy resource in my analysis. Rather, the interest in Homer City formerly owned by GPU is attributed to EME and Three Mile Island is attributed to PECO Energy, one of AmerGen's owners. GPU's sale of several of its generators to Sithe (which in turn has sold those generators to Reliant) includes a buy back of installed capacity credits from Sithe, but not energy, and therefore is not reflected as a GPU resource in my analysis. For reasons discussed above, my analysis focuses upon energy markets, not capacity markets. Therefore, in my study, the units originally sold by GPU to Sithe are appropriately attributed to Reliant, which purchased those units from Sithe. ---------- (30) GPU sells requirements power to Allegheny Electric Cooperative (AEC). Under this arrangement, GPU sells to AEC all of its requirements not provided by a hydroelectric allocation from the New York Power Authority and receives the output from AEC's 10 percent ownership in the Susquehanna nuclear station and AEC's Raystown hydroelectric facility. However, I treat AEC as part of GPU's load, not as an independent wholesale market seller, and so do not model this transaction separately in the Appendix A Study. GPU also sells a small amount (4 MW) to Allegheny affiliate West Penn Power. This amount also is included as part of GPU's load and therefore not modeled separately in the Appendix A analysis. 236 APPLICANTS EXHIBIT NO. APP-300 Page 49 of 75 The basic generator data base used for my study includes NUGS but does not identify the utility purchasers for those NUGs that are not merchant plants, which is much of the listing. For my study, I used a combination of reliability council EIA Form 411 reports, individual company load and resource reports and FERC Form 1 filings to attribute most of these NUGs to individual utility purchasers. Those that could not be so attributed were assumed to be merchant plants but ignored if the owner has less than 200 MW of capacity. This is a conservative assumption that artificially tends to increase the concentration changes measured in my analysis. The generator database that I assembled does not identify which NUGs are dispatchable and which are "must take" nor, so far as I am aware, is there any publicly available database that does so. GPU identified for me which of its NUG purchases are from dispatchable units. For other suppliers with significant NUG purchases, where possible, I used their Form 1s to develop historical capacity factors and assumed that fossil fuel fired units with very high capacity factors were not dispatchable but that fossil fuel fired NUG units with lower capacity factors were dispatchable. For other types of NUG units, and where capacity factor information was not readily available, I assumed that the NUG purchases were nondispatchable. Nondispatchable NUGs were assumed in my analysis to have a dispatch price of zero. I used reliability council EIA Form 411 reports, individual company load and resource reports and FERC Form 1 information to develop information on utility-to-utility purchases and sales for transactions not involving Applicants. Developing information on these utility-to-utility transactions undoubtedly is one of the more challenging tasks in undertaking an Appendix A analysis. The available information is incomplete as to its coverage of transactions and many times difficult to 237 APPLICANTS EXHIBIT NO. APP-300 Page 50 of 75 interpret. Pricing information is especially sparse. Where it could be discerned that a transaction was from a specified unit, I assumed that the energy price for the sale was equal to the unit specific cost information that was contained in my database. Certain other transactions were classified as "baseload" or "peaking" depending upon particular circumstances and priced so that they were dispatched appropriately in the algorithms used to produce the HHIs and HHI changes. Prices for certain other transactions were developed using Form 1 information when that seemed appropriate based on the information that was available. I recognize, however, that except for the Applicants' transactions, my information on purchase and sale transactions, while perhaps the best that can be obtained using publicly available sources, is less than perfect. Q. IS IT NECESSARY THAT DATA ON LONG TERM PURCHASE AND SALES TRANSACTIONS BE PERFECT IN ALL RESPECTS IN ORDER TO IMPLEMENT AN APPENDIX A ANALYSIS? A. No. An Appendix A analysis develops market share, HHI and HHI change information. What is most important in such an analysis is to have accurate information on the Applicants' purchases and sales. It is this data that will most directly affect the resulting share and HHI change data. I have been supplied with such accurate information for the Applicants' purchases and sales. While it is desirable also to have accurate information on other suppliers' purchases and sales, errors or omissions with respect to it will have much less effect on the study results than would errors or omissions concerning Applicants' purchases and sales. For purposes of the Economic Capacity computations, errors or omissions in this area should have virtually no effect. For example, if a purchase and sale transaction involving entities other than Applicants is omitted from the analysis, the affected generation still will be included in the analysis but simply incorrectly attributed. The errors from attributing too much generation to one supplier and not enough to another will be largely 238 APPLICANTS EXHIBIT NO. APP-300 Page 51 of 75 offsetting. Depending on the precise circumstances, Applicants' shares of Economic Capacity and the HHI changes for Economic Capacity that are attributable to the merger are unlikely to be affected from errors involving third party purchases and sales, or only marginally affected. Moreover, while the same is not necessarily true for Available Economic Capacity computations, as I discuss further below GPU has no Available Economic Capacity (at any price level, in any destination market) and so the effect of errors and omissions (after correctly accounting for Applicants' transactions) is irrelevant for an assessment of the impact of Applicants' proposed merger. Q. MANY TRADITIONAL SUPPLIERS, INCLUDING GPU, HAVE SOLD SOME OR ALL OF THE GENERATING ASSETS THAT THEY PREVIOUSLY OWNED TO OTHER PARTIES. MANY OF THESE TRANSACTIONS, INCLUDING THOSE ENTERED INTO BY GPU, INVOLVE ARRANGEMENTS WHERE THE SELLERS BUY BACK SOME OF THE ENERGY OR CAPACITY FROM THE UNITS THAT THEY HAVE SOLD. HOW ARE THESE TRANSACTIONS MODELED IN YOUR STUDY? A. I have already discussed my treatment of GPU's asset sales. Except for Oyster Creek, which involves a continuing sell back of energy to GPU (through March 2003), I have attributed the sold assets to the purchasers (or in the case of the assets originally sold by GPU to Sithe, Reliant, which is the subsequent purchaser). Other asset sales in the region of the country most appropriate for an assessment of the FirstEnergy-GPU merger appear generally, at least so far as can be gleaned from trade press accounts, to involve the sell back of energy from the buyer to the seller for an interim time period. Such sell back arrangements are presumed to be in place during calendar 2001 for purposes of my study unless there are trade press reports indicating that they have expired or will soon expire. Of course, as is true with the utility-to-utility purchases and sales discussed above, 239 APPLICANTS EXHIBIT NO. APP-300 Page 52 of 75 failing to model accurately in all cases the buy back provisions associated with asset transfers that do not involve Applicants will have no effect or only a marginal effect on the HHI computations for Economic Capacity. And, because GPU has no Available Economic Capacity, Economic Capacity is the only measure of importance for a competitive assessment of the proposed FirstEnergy-GPU merger. Q. GPU HAS ANNOUNCED THAT IT INTENDS TO SELL ITS 50 PERCENT (200 MW) INTEREST IN THE YARDS CREEK PUMPED STORAGE HYDROELECTRIC FACILITY. HOW IS THIS TREATED IN YOUR ANALYSIS? A. While GPU has announced that it intends to sell its 200 MW interest in Yards Creek, it has not yet consummated an agreement for the sale. Accordingly, I attribute the 200 MW Yards Creek interest to GPU in my base case analysis. To do so is conservative and therefore artificially overstates the HHI change resulting from the merger by a small amount. I perform a sensitivity analysis that assumes that GPU's Yards Creek interest is sold to Public Service Electric & Gas Company, the co-owner of Yards Creek, in both the pre- and post-merger scenarios. Certain of the HHI changes resulting from the merger are very marginally reduced when this disposition of Yards Creek is assumed. Q. PLEASE DISCUSS THE TRANSMISSION CAPACITY DATA USED IN YOUR ANALYSIS. A. The transmission capacity data that I use come principally from various transmission providers' OASIS sites. My base case analysis uses non firm ATC measures but I also perform a separate sensitivity analysis using firm ATC values. Where available, I assembled data from the OASIS sites of both the Point of Receipt (POR) and Point of Delivery (POD) systems. In many cases the transmission capacity data shown on those different 240 APPLICANTS EXHIBIT NO. APP-300 Page 53 of 75 OASIS sites differ from those on the other site and so I generally used the lower values in my analysis. There are three exceptions to this general rule of using the lower of POR and POD values. One involves the path from FirstEnergy to DPL where FirstEnergy at times reports an ATC value of zero when DPL shows positives figures. Using the "lower of" rule in this case essentially would eliminate FirstEnergy as a potential market supplier for the time periods when it reports zero ATC and therefore eliminate the need for any further analysis for those time periods. Accordingly, in order to be conservative, I used the higher ATC values reported by DPL. The second case where I do not use the lower of different POR or POD reported values involves the paths from NYPP into PJM. Because I include in my study destination markets that comprise only a portion of PJM, it is necessary to have separate values for deliveries from NYPP into PJM East and from NYPP into the rest of PJM, and only the PJM OASIS provides such separate values. Accordingly, I employ them in my analysis even though, when summed, they exceed the single NYPP to PJM value reported on the NYPP OASIS site. The third case where I do not use the lower of the POR and POD values involves paths into PJM from ECAR and SERC and paths out of PJM into ECAR and SERC. For these paths I use the values from the PJM OASIS, even in cases where they are higher, on the assumption that they are more likely to reflect in proper fashion the interrelationships among the several paths that are involved than would values derived from separate FirstEnergy, Allegheny and VEPCO OASIS sites. One of the destination markets included in my study is NYPP. NYPP is a destination market because there are direct interconnections between NYPP entities and entities in PJM, where GPU is located. In addition to PJM, entities in NYPP are interconnected with New England Power Pool 241 APPLICANTS EXHIBIT NO. APP-300 Page 54 of 75 (NEPOOL) suppliers, Hydro Quebec and Ontario Hydro. I was unable to get ATC and TTC data from OASIS for these interconnections and so, as proxies, I used transfer capability measures as provided in regional seasonal assessment studies. The OASIS data that I used consisted of monthly values. For the most part, I averaged the individual monthly values to obtain seasonal values for the three seasons included in my study (summer, winter and spring/fall). However, when there was an individual monthly value that was significantly different from the values for the other months comprising the season, I generally ignored that single outlier value in the averaging process to obtain the seasonal values on the assumption that more representative seasonal values would be obtained if I did. When data was not available on a particular OASIS site for a particular period, the lesser of the values for the other two seasons was used. In addition to the path by path transmission capacity values included in my study, I also asked personnel at FirstEnergy to estimate certain simultaneous limits for me. These simultaneous limits reflect the fact that it may not always be reasonable to sum OASIS derived path by path limits to obtain limits across multiple paths or into the same control area because common limiting facilities may be involved. FERC has suggested that it is appropriate to include such simultaneous limits in Appendix A analyses.(31) This order discusses the then-pending merger of Ohio Edison and Centerior, which created FirstEnergy. Two types of simultaneous limits were employed. The first reflects limits on imports into entire control areas while the second reflects limits on imports into some of those control areas from certain directions. These limits were not developed for all control areas or directions but only those where such limits seemed likely to be important for the analysis based upon a priori understanding ---------- (31) See 80 FERC (Paragraph) 61,039 at page 61,107. 242 APPLICANTS EXHIBIT NO. APP-300 Page 55 of 75 of the transmission network and flows on it. As an example of the directional simultaneous limits that were utilized, energy can flow into the FirstEnergy control area from the east from PJM, DQE or Allegheny. A simultaneous limit on flows into FirstEnergy from this direction would cap flows at a level lower than the sum of the separate ATCs on the PJM-FirstEnergy, DQE-FirstEnergy and Allegheny-FirstEnergy paths. I implemented the simultaneous limits in my model by proportionally scaling down the single path transmission values so that, when summed, they did not exceed the appropriate simultaneous limit. I employ both the directional and control area simultaneous limits in my base case analysis. The simultaneous limits that are used in my study are included in my workpapers. Q. WHAT WAS THE SOURCE OF YOUR DATA ON TRANSMISSION PRICES AND LOSSES? A. This information generally comes from the various transmission providers' OASIS sites and in a few cases from the Order 888 transmission tariffs themselves. I used the ceiling rate for non firm service. Even though there were a few cases where transmission providers today post discounts for service on particular paths in the near term, I had no basis to assume that such discounts would prevail into the future. In cases where there were separate peak and off peak rates, I incorporated these in my analysis. Where there were not, I used a single "all hours" rate. Where they were separately stated on a per MWH basis, I added ancillary service charges for Scheduling, System Control and Dispatch and for Reactive Supply and Voltage Control from Generation Sources services. Where there were no such separate ancillary service charges stated, I assumed that they were included in the base non firm "access" charge. Where loss levels were specified, I used those specified loss levels. Where loss levels were not specified, I used a "default" value of 2.5 percent. 243 APPLICANTS EXHIBIT NO. APP-300 Page 56 of 75 I used transmission rates for the existing pool wide open access tariffs for MECS, PJM and NYPP. In a sensitivity analysis, I assumed that the Alliance transmission tariff was in effect. This tariff has separate rates for "drive through" and "drive out" rates on the one hand, and "drive in" and "drive within" rates on the other. There is a single system-wide rate for drive through and drive out service but the drive in and drive within rates are specific depending on the ultimate sink. The transmission rates that I used for this sensitivity are contained in the Alliance participants' recent filing in Docket Nos. ER99-3144-000 and EC99-80-000. Of course, the Alliance transmission rates are just estimates as of this point in time, because the tariff rates themselves have not yet been approved by FERC and also because the precise composition of this group at the time service begins is not now known. I also examined an additional sensitivity scenario where I assume that marginal transmission prices were zero, i.e., that all transmission payments consisted of fixed or demand charges that did not depend on the source of scheduled transactions. While perhaps unrealistic, this scenario provides an extreme example of a trend toward lower variable price payments and broader RTOs.(32) I applied transmission rates in my study for the originating system and each intervening system between the source and sink. I did not apply the transmission price for the destination system (sink), effectively assuming that customers in the sink all are network customers. It is essentially inconsequential to make this assumption because including a separate point-to-point charge for the destination system for non network customers would penalize all remote supplies by the same amount and therefore leave their relative ranking undisturbed. --------- (32) I also examined a separate sensitivity where I assumed that the single system transmission rates of the Midwest ISO were in effect. The merger induced HHI changes when this assumption was employed were indistinguishable from those of my base case. Accordingly, I do not discuss it further herein, or report the specific results. 244 APPLICANTS EXHIBIT NO. APP-300 Page 57 of 75 Q. THE PJM ISO AND ALLEGHENY HAVE ANNOUNCED THAT ALLEGHENY WOULD JOIN THE PJM ISO AND BE INCORPORATED INTO THE PJM ISO'S TRANSMISSION TARIFF AS PART OF WHAT IS REFERRED TO AS PJM WEST. HOW IS THIS REFLECTED IN YOUR ANALYSIS? A. I have not directly reflected in my analysis the possibility that Allegheny would join PJM as a part of PJM West because there is not sufficient publicly available information to allow this to be done. Moreover, the information that is publicly available indicates that transmission prices for PJM West will be designed to keep Allegheny from suffering transmission revenue losses in the near term when it joins PJM.(33) If this is true, then it may be that using the existing Allegheny transmission price to model wheeling across the Allegheny system in fact accurately represents the prices that will be in effect even after PJM West is formed, at least in the near term. In any case, as indicated, I have also included a sensitivity analysis that assumes that all marginal transmission prices, including those for wheeling across the Allegheny system, are zero. Q. DID YOU INCORPORATE A MAXIMUM NUMBER OF WHEELS IN YOUR ANALYSIS? A. Yes. I included suppliers that are one or two wheels away from each destination market but did not include suppliers that are more than two wheels away from the destination market. This was done for computational convenience and does not in any way limit the usefulness of my results. As discussed below, application of the Appendix A screening analysis, under the assumptions that I have employed, indicates that there are no adverse competitive effects that will arise from the proposed FirstEnergy-GPU merger. Including suppliers more than two ---------- (33) See Allegheny Power/PJM Interconnection, L.L.C. Memorandum of Agreement dated October 5, 2000, paragraph 6.K. 245 APPLICANTS EXHIBIT NO. APP-300 Page 58 of 75 wheels away from the destination markets examined could only reinforce this conclusion. Q. HOW HAVE YOU ALLOCATED LIMITED TRANSMISSION PATH CAPABILITY IN SITUATIONS WHERE THE AMOUNT OF POTENTIALLY COMPETING SUPPLY EXCEEDS THE PATH CAPABILITY (ADJUSTED AS APPROPRIATE TO INCORPORATE THE SIMULTANEOUS LIMITS)? A. This situation arises in all cases with the Economic Capacity computations. I have used a "proportional" method, which means that I sum supplies competing to use a particular path and then attribute to each supplier the amount of the path represented by the proportion that its competing supplies are of the total of all competing supplies. Thus, if supplier X has 200 MW of capacity deemed by the analysis to be competing to use a particular 400 MW path, and four other competing suppliers each have 200 MW as well, then supplier X will receive an allocation of 80 MW or its pro rata 20 percent share. I have used the proportional method because it incorporates the presence of all competing suppliers in the analysis. The principal alternative to this proportional allocation method is an "economic" allocation method that assigns the limited transmission capability to the suppliers with lower delivered costs. While perhaps more realistic in terms of which suppliers ultimately will gain access to the limited transmission capability, the economic allocation method overlooks entirely in the HHI determinations all suppliers other than those that gain an allocation of the limited transmission capability that can deliver energy into the destination market at a price lower than the competitive price and therefore ignores the competitive pressure from those supplies. Seemingly, therefore, it will artificially overstate market HHIs. For Economic Capacity, which for reasons discussed earlier is the only capacity measure for which any 246 APPLICANTS EXHIBIT NO. APP-300 Page 59 of 75 detailed assessment is required for the FirstEnergy-GPU merger, the economic allocation method also tends to assign high market shares to entities with substantial quantities of nuclear generation, effectively for purposes of an Appendix A analysis assuming that nuclear capacity can be used simultaneously in multiple destination markets. This occurs because the nuclear capacity has such low variable costs that it still can be economic in remote destination markets even after shouldering multiple transmission charges. The nuclear capacity actually squeezes out capacity that is more likely to be competing on the margin. The economic allocation method also suffers from "knife edge" properties, which means that very small changes in market clearing price (or transmission prices) can significantly, and unrealistically in my view, affect market shares and HHIs. For these reasons, I have selected the proportional allocation method. Q. IN YOUR ANALYSIS, HOW DID YOU DETERMINE WHICH TRANSMISSION PATHS TO USE TO DELIVER THE SUPPLIES FROM INDIVIDUAL SUPPLIERS TO PARTICULAR DESTINATION MARKETS? A. Where there is only a single direct path that might be used, that path obviously is selected. Where there are potentially competing paths, some selection among them is required. Unfortunately, there is no one best and non arbitrary decision rule that can be employed when the proportional (as opposed to economic) method is used for allocating limited transmission capability among competing supplies.(34) However, in most cases it does not matter a great deal how the decision is made. AEP's transmission system is interconnected with numerous market participants and a large number of the routing decisions for the FirstEnergy-GPU merger involve it. Given its robustness, when the AEP transmission system represents a ---------- (34) When the economic allocation procedure is employed, paths may be selected in order to minimize the cost of delivered energy to the destination market. 247 APPLICANTS EXHIBIT NO. APP-300 Page 60 of 75 potential alternative transmission route, as a practical matter most of the flows will be routed over it when there are competing alternatives simply because the capacity on it is so great. The approach that I used was conservative. When there was a choice of competing paths, and one was always preferred both on the basis of lower price and larger amounts of transmission capability, it was selected. When one path was preferred on the basis of lower price, but another path preferred on the basis of greater quantity of available transmission capacity, I examined each choice individually and selected the lower priced choice if the available quantity on it was not significantly lower than on the competing path(s) and the greater quantity choice if its ceiling price was not significantly greater than on the competing paths. My analysis conservatively is limited to supplies within two wheels of a destination market and so this path by path analysis is relatively easy to perform. As it turns out, there is much more variation in transmission quantity levels than there is in price levels and so employing this procedure generally selects the path with the greatest transmission capacity. To test the reasonableness of the procedure that I employed, I performed sensitivity analyses that used alternative path routings and found that the results, in terms of HHIs, HHI changes and Applicants' shares, changed very little. I modified this general approach in certain instances to ensure that my analysis provided a conservative depiction of the effects of a FirstEnergy-GPU merger. For any Appendix A analysis, measured HHI changes in the destination markets centered on Applicants (i.e., in this instance the FirstEnergy and PJM destination markets) are likely to be greatest. Accordingly, for the FirstEnergy market, I allowed supplies from PJM (where GPU's limited generation interests are located) to reach the FirstEnergy market both through the direct PJM-FirstEnergy tie as well as 248 APPLICANTS EXHIBIT NO. APP-300 Page 61 of 75 through the indirect PJM-Allegheny-FirstEnergy tie. This insures that I do not artificially understate the HHI changes in the FirstEnergy market, by limiting too much the GPU supplies that can enter. I employ a similar procedure for supplies that go from FirstEnergy to PJM, letting them use the direct FirstEnergy-PJM path as well as the indirect FirstEnergy-Allegheny-PJM path. A second exception to the general procedure that I have outlined was to route competing suppliers through paths other than FirstEnergy in cases where there was a choice to go through FirstEnergy or another supplier, unless the selection of FirstEnergy was obviously superior. For example, energy from Allegheny could be routed to the DPL market either through FirstEnergy or AEP. My study uses AEP for this routing. This is conservative because it artificially increases Applicants' shares. Q. HOW DID YOU DETERMINE THE COMPETITIVE OR MARKET CLEARING PRICES TO USE IN YOUR ANALYSIS? A. I first looked at historical system lambda prices as filed in EIA 714 reports for calendar 1999, the most recent year for which such data generally is available publicly. Historical system lambdas for each of the seasons and time periods, for each of the destination markets used in my analysis, are provided in Exhibit No. APP-305. Several things are striking from reviewing this exhibit. One is that during the off peak periods there is relatively little variation among the system lambda values reported by the different destination market/control areas. In contrast, there is substantial variation in these system lambda values during higher demand time periods. A second striking feature from reviewing Exhibit No. APP-305 is that while system lambda values do rise when moving from lower demand to higher demand time periods, the pattern of these increases is noticeably different from control area to control area. The top 50 hours summer system lambda value is only 55 percent above the summer off peak system 249 APPLICANTS EXHIBIT NO. APP-300 Page 62 of 75 lambda value in the AEP control area and only 28 percent above it in the DPL control area. Indeed, the summer top 50 hours average system lambda values in these two control areas seem remarkably low, at $17.16 per MWH in the DPL control area and $17.96 per MWH in the AEP control area. In contrast, the summer top 50 hours average system lambda in the FirstEnergy control area was $811.36, nearly 25 times as large as the summer off peak average system lambda. Likewise, in the DQE control area the summer top 50 hours system lambda of $693.59 was also roughly 25 times as large as the average summer off peak system. PJM, MECS and Allegheny also had very high summer top 50 hours average system lambdas in comparison to the other markets and in comparison to their own summer off peak average system lambdas. It is relatively well known that different suppliers use somewhat different techniques in developing the system lambda values that are reported on the EIA Form 714 forms. That this is true seems apparent from even a cursory examination of Exhibit No. APP-305. It would be inappropriate simply to use the individual reported control area by control area figures in the Appendix A analysis to identify the competitive clearing price for each destination market because, at least in the higher demand hours, systems like DPL and AEP simply are not measuring the same phenomenon that the other systems are measuring. The alternative approach that I have employed, which I believe is much more reasonable, is to use the same competitive prices in each market for each season and time period combination and, where appropriate (i.e., for the higher demand time periods), let these reflect a range of possible market clearing prices. I examined current NYMEX futures prices for delivery to the PJM and Cinergy systems during calendar 2001, the study year for my analysis, to help inform me about what ranges should be used. These NYMEX futures prices are also reported in Exhibit No. APP-305. APPLICANTS EXHIBIT NO. APP-300 Page 63 of 75 Based upon Exhibit No. APP-305, for my analysis, for the summer off peak I used a price of $20 per MWH while for the summer peak (including super peak I, II and III) I used a range of prices from $40 up to $100 per MWH. The NYMEX forward prices for 2001 are $101.75 per MWH for peak period deliveries to Cinergy and $89.67 per MWH for peak period deliveries to PJM. The top end of the range of prices that I examine for the peak period in the summer months is $100 per MWH, a price that will bring in to the dispatch virtually all generators in my database. Accordingly, using a higher super peak value would not change the results noticeably. For the winter and spring/fall months I use an off peak price of $15 per MWH and peak and super peak period prices of $30 and $40, respectively, per MWH. Q. HOW ARE SUPPLIES FROM NEPOOL INCORPORATED IN YOUR ANALYSIS? A. NEPOOL is directly interconnected with NYPP. If suppliers that compete in a market are limited to those within two wheels of the market, NEPOOL supplies would be able to compete in the NYPP and PJM markets (including PJM West/Central/East, PJM Central/East and PJM East). However, in my study I have excluded NEPOOL supplies entirely. It is conservative to do so as concerns this merger because including NEPOOL in these markets could only lower the measured HHI changes from the merger. I excluded NEPOOL suppliers simply because of the extra effort that would be involved were they to be included, and the apparent lack of any significant effect upon my results. 250 APPLICANTS EXHIBIT NO. APP-300 Page 64 of 75 Q. HOW IS FIRSTENERGY'S SENECA PUMPED STORAGE UNIT INCLUDED IN YOUR ANALYSIS? A. Seneca is located in PJM but is owned entirely by FirstEnergy and included as one of FirstEnergy's network resources.(35) Accordingly, for all destination markets except PJM I assume that Seneca in effect has been "moved" from PJM to FirstEnergy's control area. The ATCs that I employ in my analysis presumably have been developed in a fashion to reflect this "movement." However, for my analysis of the PJM destination market, and the destination markets that consist of portions of PJM, I leave Seneca in PJM and do not move it to FirstEnergy's control area. I believe that this approach is appropriate. It leaves Seneca in PJM to compete in those destination markets when the prices are higher there, but also allows Seneca to be moved to the FirstEnergy control area using transmission service procured by FirstEnergy from the PJM ISO when prices are higher there. Q. THERE ARE NUMEROUS RELATIVELY SMALL ELECTRIC SYSTEMS INCLUDED IN THE GEOGRAPHIC AREA COVERED BY YOUR ANALYSIS. HOW DID YOU TREAT THEM? A. For the most part, I ignored the generating capacity held by entities with generating resources that totaled less than 200 MW. This results in a very small overstatement of HHIs and merger induced HHI changes. I did, however, include the generation owned by Cleveland Public Power and the City of Painesville that is located inside FirstEnergy's control area. For entities such as American Municipal Power-Ohio (AMP-Ohio) that have loads in multiple control areas, for computational convenience I left those resources where they are located and did not move them as network resources to the control areas where their load is located. This also will tend to overstate HHIs and merger induced HHI changes in the ---------- (35) Until 1999, GPU owned a 20 percent or 87 MW interest in the Seneca station. Its 20 percent interest was sold to FirstEnergy in 1999. 251 APPLICANTS EXHIBIT NO. APP-300 Page 65 of 75 FirstEnergy destination market where some of AMP-Ohio's resources in fact are delivered. VI. SUMMARY OF SCREENING ANALYSIS RESULTS Q. PLEASE DESCRIBE YOUR BASE CASE ANALYSIS. A. There are a number of different variables and assumptions that enter into an Appendix A analysis. In some cases there is a clear cut preference as to which choice to make when alternatives for these variables and assumptions are available but in other cases there may not be. Likewise, it might be desirable to perform sensitivity analyses that span a range of possible future conditions when there is uncertainty concerning which conditions actually will prevail. This will inform FERC about potential competitive consequences over a wide range of future system conditions. My base case employs non firm ATCs, simultaneous transmission limits as appropriate, delivered natural gas price estimates based on the Bloomberg locational price differentials rather than on FERC Form 423 historical prices and existing single system and poolwide transmission tariffs. It also assumes that GPU continues to own its 50 percent interest in the Yards Creek pumped storage facility even though GPU has indicated its intention to sell that facility. In various alternative analyses I change certain of these inputs and assumptions to determine their importance. Q. PLEASE DESCRIBE THE RESULTS OF YOUR BASE CASE ANALYSIS. A. The base case results are summarized in Exhibits No. APP-306 and APP-307. Each is a multi page exhibit that provides, for each destination market, for each season, time period and competitive market price examined, the following information: pre merger and post merger HHIs and the merger induced HHI changes; each of the Applicants' capacity in 252 APPLICANTS EXHIBIT NO. APP-300 Page 66 of 75 MW as well as the post merger total for the merged firm;(36) and each of the Applicants' market shares as well as the market share of the merged firm. Exhibit No. APP-306 pertains to Economic Capacity while Exhibit No. APP-307 pertains to Available Economic Capacity. For Economic Capacity, Exhibit No. APP-306 indicates that the merger induced HHI changes almost universally fall below the Merger Guidelines' screening thresholds. In most cases the markets are "highly concentrated" as defined by the Merger Guidelines but the HHI changes from the merger fall below the Merger Guidelines' screening threshold of 50. The NYPP and the various PJM markets fall into the Merger Guidelines' "unconcentrated" or "moderately concentrated" categories. When the markets are moderately concentrated, the HHI changes fall below the screening threshold of 100 for such moderately concentrated markets. There are only limited exceptions when the merger induced HHI increases exceed the Merger Guidelines' screening thresholds. These involve the summer, spring/fall and winter off peak hours in the FirstEnergy destination market and the winter and spring/fall off peak periods in the DQE destination market. Q. DO THESE OFF PEAK SCREEN VIOLATIONS INDICATE THE PRESENCE OF MERGER INDUCED MARKET POWER CONCERNS? A. No. There are several reasons. First, as a general matter, HHI figures during off peak hours can be seriously misleading as potential indicators of market power because at such times there is likely to be a large quantity of supply chasing relatively little demand. This excess of supply means that suppliers then will have very little opportunity to raise their prices ---------- (36) The capacity identified in these exhibits is that which is deemed to make it into the particular market in question, accounting for, among other things, delivered prices, transmission limits and the amount of capacity from other suppliers competing for limited transmission space. 253 APPLICANTS EXHIBIT NO. APP-300 Page 67 of 75 above competitive levels because other suppliers easily can fill the breach if one supplier seeks economically or physically to withhold supply. Moreover, during off peak periods a high portion of the demand is likely to be served by nuclear units and the minimum operating levels of coal units that must be kept operating during off peak periods so that they will be available to meet demand during the next day's peak. It is not possible to use such units to exercise market power by economically or physically withholding their output. The costs of doing so would be far greater than the benefits even if the strategy were successful in raising price. For FirstEnergy, a significant portion of its off peak demand in fact is met by its nuclear units and the minimum operation levels of coal units kept on line in order to meet the next day's peak demand. For example, the minimum operating levels of FirstEnergy's coal units at Sammis, Bruce Mansfield and Eastlake total 2350 MW. Its four nuclear units have a total capacity of 3707 MW. The total of the nuclear units plus the minimum operating levels of the coal units therefore is 6057 MW. The average daily minimum load for FirstEnergy during 1999 was 6004 MW in the summer, 6049 MW in the winter and 5512 MW in the spring/fall time periods used in my analysis. Even after accounting for some modest off peak growth from 1999 to the 2001 study year used for my analysis, and the effects of planned and forced outages, it is apparent from these figures that all or almost all of FirstEnergy's off peak demands will be met by capacity that cannot be easily withheld from the market and that it will have no or very little dispatchable capacity operating during off peak hours that it could withhold in the hopes of raising price and exercising market power. This will be true whether or not it merges with GPU. Accordingly, concerns that the merger could create an opportunity for the merged entity to profit by withholding capacity during off peak hours can be dismissed a priori. 254 APPLICANTS EXHIBIT NO. APP-300 Page 68 of 75 Second, the overwhelmingly predominant direction of energy flows between ECAR (where FirstEnergy and DQE are located) and PJM is west to east from ECAR into PJM. Energy flows from PJM to ECAR only a small portion of the time. Support for this statement is provided in Exhibit No. APP-308 which indicates that during the September 1997 to September 1999 time period, during off peak hours, energy flowed from PJM to FirstEnergy only 5.8 percent of the time and from PJM to Allegheny only 12.6 percent of the time. The remaining portion of the time energy flowed into PJM from FirstEnergy and Allegheny. FirstEnergy and Allegheny are the only ECAR entities that are directly interconnected with PJM. Assuming that transmission constraints are binding in the west to east direction, which is the implicit assumption that underlies an Appendix A analysis of a single destination market, this implies that, on the margin, even during off peak hours, energy produced in ECAR is cheaper than energy produced in PJM. GPU therefore will have an incentive to market its few remaining resources in PJM, not in ECAR to the west where prices presumably are lower. Thus, while the procedures of an Appendix A screening analysis might show that some of the energy generated by resources that GPU has output rights to in fact could be economically supplied to the FirstEnergy and DQE destination markets during off peak time periods, in reality it is not likely to be supplied there based on the predominant direction of power flows in the other direction. Third, the introduction of retail competition notwithstanding, GPU really does not have any resources available that it might use in markets to the west of PJM during off peak hours (or any other time periods for that matter). The energy generating resources that it owns or has long term energy output rights to (as I have explained that term above) that are likely to be operating during off peak hours include roughly 1175 MW of 255 APPLICANTS EXHIBIT NO. APP-300 Page 69 of 75 nondispatchable NUG purchases, its buy back of energy from the 619 MW Oyster Creek nuclear unit that it sold to AmerGen and 224 MW of nuclear and run-of-river hydroelectric resources owned by AEC, its wholesale customer, and its own 19 MW York Haven run-of-river hydroelectric facility. Together these energy sources total only around 2037 MW, an amount which is not nearly sufficient to cover GPU's continuing off peak commitments to its retail and wholesale customers at least in the near term. They therefore provide neither GPU nor the merged firm any opportunity to exercise market power in markets to the west of PJM during off peak periods. Finally, whatever ability FirstEnergy might have to exercise market power during off peak hours in destination markets to the west of PJM (e.g., the FirstEnergy and DQE destination markets), and for reasons stated above I do not believe that any such market power exists, will not be enhanced by its merger with GPU because none of the off peak resources that would be merged with FirstEnergy's resources can be used to restrict supply to drive up price. The off peak resources that GPU has entitlements to are nondispatchable NUG purchases, the energy buyback from the Oyster Creek nuclear unit, AEC's interest in Susquehanna and a run-of-river hydroelectric facility and its own York Haven run-of-river hydroelectric facility.(37) With the exception of York Haven, GPU now has no ability to control the output of any of its off peak resources. It does not own them, cannot affect their dispatch level and does not have the ability to withhold their energy output from the market. GPU simply receives and pays for whatever output that its ownership interest entitles it to, but has no ability to affect that output level. Thus, those resources cannot be used to exercise market power. The same will be true post merger. ---------- (37) The other resources that GPU either owns or has energy entitlements to that extend past the end of 2001--its owned Yards Creek hydroelectric facility, the Forked River combustion turbine and two dispatchable NUGs--are not likely to be dispatched during off peak periods. 256 APPLICANTS EXHIBIT NO. APP-300 Page 70 of 75 Q. PLEASE DISCUSS THE RESULTS OF YOUR BASE CASE ANALYSIS FOR THE AVAILABLE ECONOMIC CAPACITY MEASURE. A. The results for Available Economic Capacity are shown in Exhibit No. APP-307. They indicate that GPU does not have any Available Economic Capacity, either in PJM where its generators are located or in any of the other destination markets during any season or time period. This automatically means that there will be no HHI changes resulting from the merger. The HHI change from a merger generally is given by 2 x a x b where a and b are the pre merger shares of the merging parties. If either a or b is zero, which it is for GPU for the Available Economic Capacity measure, then the merger induced HHI change is zero. Note that in computing Available Economic Capacity for GPU, unlike for other suppliers, I used an estimate of its load obligation after accounting for estimated load loss to competitors. This is a conservative approach. Q. PLEASE NOW DISCUSS THE SENSITIVITY ANALYSES THAT YOU PERFORMED. A. I performed a variety of sensitivity analyses where, among other things, I change transmission prices, transmission capacities and fuel prices. I perform these sensitivity analyses only for the Economic Capacity computations. There is no reason to perform sensitivity analyses for the Available Economic Capacity measure because, as indicated, GPU has no Available Economic Capacity during any season or at any price level. The HHI change using this measure therefore always will be zero and would not be changed with a sensitivity computation. The particular sensitivity analyses that I perform for the Economic Capacity measure are summarized in a series of exhibits as follows: 257 APPLICANTS EXHIBIT NO. APP-300 Page 71 of 75 Exhibit No. APP-309 substitutes firm ATC measures of transmission capacity for non firm ATC measures. Exhibit No. APP-310 uses the alternative (Form 423 based) procedure described in the text to develop delivered natural gas prices. Exhibit No. APP-311 uses proposed Alliance transmission prices instead of single system transmission prices where applicable. Exhibit No. APP-312 uses a variable transmission price of zero for all transmission paths to provide a proxy for RTO pricing over a broad geographic range. Exhibit No. APP-313 assumes that in the off peak hours the merged firm sells 650 MW into PJM and adjusts the ATC from FirstEnergy to PJM accordingly. Exhibit No. APP-314 assumes that GPU sells its interest in the Yards Creek pumped storage hydroelectric facility to its co-owner PSEG. Exhibit No. APP-315 assumes that Henry Hub natural gas prices are $1 per mmbtu lower than current futures prices at Henry Hub. Exhibit No. APP-316 assumes that Henry Hub natural gas prices are $2 per mmbtu lower than current futures prices at Henry Hub. Exhibit No. APP-317 assumes hypothetically that the existing 450 MW sale to Pepco is delivered outside of PJM to Allegheny rather than to Pepco inside of PJM. 258 APPLICANTS EXHIBIT NO. APP-300 Page 72 of 75 All other assumptions from the base case remain unchanged for each of the sensitivity analyses except those specifically noted. While I could have conducted additional sensitivity analyses that changed combinations of assumptions, the results from the sensitivity analyses that I did conduct indicate that this was not necessary for developing an accurate representation of the effects of the proposed merger. For the most part the results of these sensitivity analyses in terms of merger induced HHI changes are not significantly different from the base case results. This is not particularly surprising given the relatively low HHI changes that result from the base case analysis. One difference from the base case analysis is shown in Exhibit No. APP-314, when the merged firm is assumed to sell 650 MW of energy into PJM during off peak hours. When this occurs the off peak screen violations that were present in the base case in the FirstEnergy market disappears. VII. VERTICAL MARKET POWER ISSUES Q. ARE THERE IMPORTANT VERTICAL MARKET POWER CONCERNS RAISED BY THE PROPOSED FIRSTENERGY-GPU MERGER? A. I do not believe that the proposed merger presents any realistic vertical market power concerns. In principle, vertical market power concerns might arise if an integrated generation and transmission owner were able to use its transmission ownership to facilitate sales of its generation over sales of generation by its competitors, perhaps by limiting access to its transmission facilities or by reducing the quantity of transmission service that is made available. In the case of a merger of FirstEnergy and GPU, no such concerns should be present. As discussed earlier, energy generally flows into PJM from the west (and south) and not out of PJM in those directions. This means that the main 259 APPLICANTS EXHIBIT NO. APP-300 Page 73 of 75 geographic market of potential concern for assessing the competitive effects of this merger is PJM or, as discussed above, portions of PJM defined by important internal transmission interfaces. Within PJM, GPU already has turned over operation of its transmission facilities to the PJM ISO, thereby limiting its ability to grant access to or control transmission in a fashion that might benefit its generation. Moreover, GPU and the other transmission owners within PJM intend that the PJM ISO become an RTO that will meet FERC's requirements in Order 2000 and recently have filed appropriate materials with FERC to begin this process. This should reduce any residual concern about GPU's or the merged firm's ability to use its transmission assets to benefit sales of its generation. Also important in lessening residual concern about the merged firm's potential exercise of vertical market power is GPU's position as a net purchaser in wholesale energy markets. That this is true is evidenced by the fact that it has zero Available Economic Capacity for all seasons and time periods studied. GPU is a net purchaser in wholesale energy markets because, as indicated, it has sold virtually all of its owned generating assets but still has substantial native load obligations. Even if, on a pre-merger basis, GPU somehow were able to manipulate the transmission system inappropriately to increase energy prices, it would suffer, not benefit, as a result of such higher prices because it is a net buyer (not seller) of energy. Accordingly, it should have no incentive to behave in a fashion to seek to increase price. The same is true for the merged firm after the consummation of the merger. If the merged firm somehow were able to manipulate the transmission system to reduce west to east flows into PJM, for example, and thereby increase the market price for energy within PJM, this might under some circumstances produce a small amount of additional revenue for what are now FirstEnergy's generators but that amount almost certainly would be swamped by the extra energy purchase expenses that would be incurred by what is now GPU to meet its load 260 APPLICANTS EXHIBIT NO. APP-300 Page 74 of 75 obligations. There is no need for policy makers to worry about price increases from what would obviously be an unprofitable transmission manipulation exercise. In addition to the above considerations, FirstEnergy has committed to participate in the Alliance or, if the Alliance fails to achieve timely compliance with FERC's final RTO rule, another RTO that satisfies FERC's independence, scope and configuration criterion under the RTO Final Rule. This should further mitigate any residual concern about the merger creating the opportunity for the exercise of vertical market power. Q. HAVE YOU ALSO CONSIDERED WHETHER FIRSTENERGY'S INDIRECT OWNERSHIP OF INTERSTATE AND INTRASTATE NATURAL GAS PIPELINES COULD PRESENT VERTICAL MARKET POWER PROBLEMS WHEN COMBINED UNDER COMMON OWNERSHIP WITH GPU'S REMAINING GENERATION? A. Yes. As described above and in Mr. Alexander's FERC testimony, FirstEnergy's Great Lakes affiliate owns both an intrastate (Ohio Intrastate Gas Transportation Company) and an interstate (Gas Transport Inc.) pipeline. I have already described above why this ownership does not represent an entry barrier for those that might construct new generation. It likewise does not present the potential for any competitive problems involving existing generation resulting from the FirstEnergy-GPU merger because there are no electric generators served off of either of Great Lakes' two pipelines, whether directly by the pipelines themselves or indirectly by Great Lakes customers using gas from the Great Lakes pipelines. Accordingly, no further analysis is required on this score. APPLICANTS EXHIBIT NO. APP-300 Page 75 of 75 VIII. CONCLUSION Q. DO YOU HAVE AN OVERALL CONCLUSION? A. Yes. The proposed merger of FirstEnergy and GPU will not have an adverse competitive effect. Q. DOES THIS CONCLUDE YOUR TESTIMONY. A. Yes. 261 AFFIDAVIT STATE OF CALIFORNIA ) ) COUNTY OF SAN FRANCISCO ) Rodney Frame, being duly sworn, deposes and states: that he prepared the Direct Testimony and Exhibits of Rodney Frame and that the statements contained therein and the Exhibits attached hereto are true and correct to the best of his knowledge and belief. /s/ Rodney Frame ---------------------------------------- Rodney Frame SUBSCRIBED AND SWORN TO BEFORE ME, this the Seventh day of November, 2000. /s/ Donna M. Boone ---------------------------------------- Notary Public, State of California Printed Name: Donna M. Boone --------------------------- My Commission Expires: 8-25-02 ------------------ [NOTARY SEAL] DONNA M. BOONE Commission # 1192992 Notary Public - California San Francisco County My Comm. Expires Aug 25, 2002 262 EXHIBIT NO. APP-301 263 Exhibit APP-301 Page 1 of 14 RODNEY W. FRAME PRINCIPAL Phone: 202-530-3991 1747 Pennsylvania Avenue, NW Fax: 202-530-0436 Suite 250 rframe@analysisgroup.com Washington, DC 20006 Mr. Frame has consulted with electric utility clients on a variety of matters including industry restructuring, retail competition, wholesale bulk power markets and competition, market power and mergers, transmission access and pricing, contractual terms for wholesale service, and contracting for nonutility generation. A substantial portion of the work has been in conjunction with litigated antitrust and federal and state regulatory proceedings. Mr. Frame frequently speaks before electric industry groups on competition-related topics. He has testified in federal and local courts, before federal and state regulatory commissions, and before the Commerce Commission of New Zealand. Prior to joining Analysis Group/Economics, Mr. Frame was a Vice President at National Economic Research Associates. Mr. Frame graduated from George Washington University and pursued graduate work there under a National Science Foundation Traineeship. His areas of specialization were public finance and urban economics. He completed all requirements for his Ph.D. degree in economics with the exception of the thesis. EDUCATION 1970 B.B.A., George Washington University 1970-73 Ph.D. coursework (all requirements for degree in economics completed except thesis), George Washington University PROFESSIONAL EXPERIENCE 1998 - Analysis Group/Economics Principal 1984 - 1998 National Economic Research Associates Vice President and Senior Consultant. Participated in projects dealing with retail competition, wholesale competition, market power assessment and determination of relevant markets for electricity supply, electric utility mergers, transmission access and pricing, partial requirements ratemaking, contractual terms for wholesale service, and 264 Exhibit APP-301 Page 2 of 14 contracting for nonutility generation supplies. Principal clients were investor-owned electric utilities. 1975 - 1984 Transcomm, Inc. Senior Economist. Worked on a variety of projects concerning market structure, pricing and cost development in regulated industries. Clients included the U.S. Departments of Commerce, Defense and Energy, the Nuclear Regulatory Commission, the State of Oregon, bulk mailers and various communications equipment manufacturers and service providers. Participated in numerous federal and state regulatory proceedings and was principal investigator for a multi-year Department of Energy study addressing various aspects of electric utility competition. 1974 - 1975 Independent Economic Consultant Advised telephone equipment manufacturers concerning cost and rate development for competitive telephone offerings, analyzed alternative travel agent compensation arrangements and examined nonbank activity by bank holding company firms. 1973 - 1974 Program of Policy Studies in Science and Technology Research Staff 1973 Urban Institute Research Staff TESTIFYING EXPERIENCE - Affidavit and Declaration on behalf of Alabama Power Company before the Environmental Protection Agency in FOIA RIN 003111-99, concerning appropriateness of protecting certain competively valuable documents from public release, October 5, 2000. - Affidavit on behalf of Northeast Utilities Service Company and Select Energy Inc. before the Federal Energy Regulatory Commission in Docket No. EL00-102-000, concerning the cost of providing ICAP to New England capacity market, September 25, 2000. - Affidavit on behalf of Alabama Power Company before the Federal Communications Commission in P.A. No. 00-003, concerning appropriateness of protecting certain competitively sensitive information from public release, September 6, 2000. - Affidavit on behalf of Gulf Power Company before the Federal Communications Commission in P.A. No. 00-004, concerning appropriateness of protecting certain competitively sensitive information from public release, September 6, 2000. - Affidavit on behalf of Southern Company and Southern Energy, Inc. before the Federal Energy Regulatory Commission in Docket No. EC00-121-000, concerning whether the proposed spin-off of Southern Energy Inc. would create competitive concerns, August 15, 2000. - Affidavit on behalf of Northeast Utilities Service Company before the Federal Energy Regulatory Commission in Docket No. EL00-62-001 and ER00-2052-002 concerning proposed termination of ICAP market and proposed mitigation of ICAP prices, May 30, 2000. 265 Exhibit APP-301 Page 3 of 14 - Prepared Rebuttal Testimony on behalf of Detroit Edison Company before the Michigan Public Service Commission in Case No. U-12134 concerning the design of a code of conduct for implementing retail customer choice, March 21, 2000. - Affidavit on behalf of Split Rock Energy LLC in Docket No. ER00-1857-000 concerning Split Rock LLC's application for market based pricing authority, March 10, 2000. - Affidavit on behalf of Baltimore Gas and Electric Company, Calvert Cliffs, Inc., Constellation Enterprises, Inc. and Constellation Generation, Inc. in Docket No. EC00-___-000 and on behalf of Baltimore Gas and Electric Company, Calvert Cliffs, Inc., Constellation Generation, Inc., and Constellation Power Source, Inc. in Docket No. ER00-___-000 concerning the application of Calvert Cliffs, Inc. and Constellation Generation, Inc. for market based pricing authority, February 11, 2000. - Deposition in the matter of Cleveland Thermal Energy Company v. Cleveland Electric Illuminating Company, Case No. 1: 97 CV 3023, United States District Court, Northern District of Ohio, Eastern Division, October 15, December 7 and December 8, 1999, concerning competitive issues and damages. - Supplemental Expert Report on behalf of Cleveland Electric Illuminating Company in Cleveland Thermal Energy Corp. v. Cleveland Electric Illuminating Company, Case No. 1: 97 CV 3023, United States District Court, Northern District of Ohio, Eastern Division, December 1, 1999, concerning damages issues. - Expert Report on Behalf of Cleveland Electric Illuminating Company in Cleveland Thermal Energy Corp. v. Cleveland Electric Illuminating Company, Case No. 1: 97 CV 3023, United States District Court Northern District of Ohio, Eastern Division, September 27, 1999, concerning allegations that a clause giving Cleveland Electric Illuminating Company the right to purchase electricity at avoided costs from a cogeneration plant that Cleveland Thermal Energy Corp. would have constructed was anticompetitive and an unreasonable restraint of trade, and computing damages. - Deposition in the matter of Florida Municipal Power Agency v. Florida Power & Light Company, Case No. 92-35-CIV-ORL22C, United States District Court, Middle District of Florida, Orlando Division, concerning damages and market issues, August 31, 1999. - Expert Report on Behalf of Florida Power & Light Company in Florida Municipal Agency v. Florida Power & Light Company in Case No. 92-35-CIV-ORL22C, United States District Court, Middle District of Florida, Orlando Division, concerning damages and market issues, August 26, 1999. - Affidavit on behalf of AmerGen Energy Company before the Federal Energy Regulatory Commission in Docket Nos. EC99-104-000 and ER99-754-001 concerning AmerGen's proposed acquisition of the Clinton nuclear unit, August, 1999. - Affidavit on behalf of AmerGen Energy Company before the Federal Energy Regulatory Commission in Docket Nos. EC99-98-000 and ER99-754-002 concerning AmerGen's proposed acquisition of the Nine Mile Point 1 nuclear unit and a portion of the Nine Mile Point 2 nuclear unit, July, 1999. 266 Exhibit APP-301 Page 4 of 14 - Affidavit on behalf of Minnesota Power, Inc. before the Federal Energy Regulatory Commission in Docket No. ER99-3586-000 concerning Minnesota Power's application for market based pricing authority, July, 1999. - Deposition in the matter of Allegheny Energy Inc. v. DQE, Inc., Civ. A. No. 98-16396 (RJC), United States District Court, Western District of Pennsylvania, June 11, 1999, concerning issues relating to the value of plaintiff's generating assets. - Affidavit on behalf of Public Service Electric and Gas Company (PSEG) before the Federal Energy Regulatory Commission concerning PSEG's request to transfer its generating assets to an affiliate in Docket No. EC 99-____-000, June 1999. - Expert Report on behalf of Allegheny Energy in Allegheny Energy Inc. v. DQE, Inc. Civ. A. No. 98-16396 (RJC), United States District Court, Western District of Pennsylvania, May 17, 1999, concerning issues relating to the value of plaintiff's generating assets. - Affidavit on behalf of Baltimore Gas & Electric (BG&E) Company before the Federal Energy Regulatory Commission concerning BG&E's application for market based pricing authority in Docket No. ER 99-2948-000, May 13, 1999. - Affidavit on behalf of Florida Power & Light in Florida Municipal Power Agency v. Florida Power & Light Co., Case No. 92-35-CIV-ORL-22 concerning legitimacy of Florida Power & Light's conduct, March 22, 1999. - Affidavit on behalf of PECO Energy before the Federal Energy Regulatory Commission concerning PECO's application of market based pricing authority in Docket No ER 99-1872-000, February, 1999. - Affidavit on behalf of Northeast Utilities before the Federal Energy Regulatory Commission concerning Northeast Utilities application for market based pricing authority in Docket No. ER 99-1829-000, February, 1999. - Affidavit on behalf of AmerGen Energy Company, LLC (AmerGen) before the Federal Energy Regulatory Commission in Docket Nos. EC99-11-000, EL99-13-000 and ER99-754-000 concerning (i) AmerGen's acquisition of Three Mile Island No. 1 from GPU, Inc. and (ii) AmerGen's application for market based pricing authority, November, 1998. - Affidavit on behalf of Constellation Energy Source, Inc. (CES) before the Federal Energy Regulatory Commission in Docket No. ER99-198-000 concerning CES's application for market based pricing authority, October 14, 1998. - Affidavit on behalf of Select Energy, Inc. (Select) before the Federal Energy Regulatory Commission in Docket No. ER99-14-000 concerning Select's application for market based pricing authority, October 1, 1998. - Rebuttal Testimony on Retail Market Power Issues on behalf of Mississippi Power Company, before the Mississippi Public Service Commission in Docket No. 96-UA-389 concerning whether Mississippi Power Company will be able to exercise market power in deregulated retail markets in Mississippi, September 11, 1998. 267 Exhibit APP-301 Page 5 of 14 - Prepared Testimony and Report on Retail Market Power Issues on behalf of Mississippi Power Company, before the Mississippi Public Service Commission in Docket No. 96-UA-389, concerning whether Mississippi Power Company will be able to exercise market power in deregulated retail markets in Mississippi, August 7, 1998. - Affidavit on behalf of Southern California Edison Company to the Federal Energy Regulatory Commission concerning market power issues associated with the supply of ancillary services to the California ISO, July 13, 1998. - Prepared Rebuttal Testimony on Behalf of Public Service Electric & Gas Company, with Paul Joskow, before the State of New Jersey, Board of Public Utilities, in Docket Nos. EX94120585Y, E097070457, E097070460, E097070463 and E097070466, responding to market power issues raised by intervenor witnesses, including in particular the role of transmission constraints in market power analyses, appropriate mitigation measures for "load pocket" situations, proper standards for granting market based pricing authority, the role of transitional mechanisms in mitigating market power concerns and the use and role of market simulations in addressing market power topics, April 13, 1998. - Prepared Rebuttal Testimony on Behalf of Atlantic City Electric Company, with Paul Joskow, before the State of New Jersey, Board of Public Utilities, in Docket Nos. EX94120585Y, E097070457, E094770460, E09707463 and E097070466, responding to market power issues raised by intervenor witnesses, including in particular the role of transmission constraints in market power analyses, appropriate mitigation measures for "load pocket" situations, proper standards for granting based pricing authority and the use and role of market simulations in addressing market power topics, April 13, 1998. - Prepared Additional Supplemental Direct Testimony on behalf of Ohio Edison and Centerior Energy, before the Federal Energy Regulatory Commission, Docket No. EC97-5-000, concerning the competitive analyses associated with Ohio Edison's merger with Centerior Energy, August 8, 1997. - Prepared Testimony on behalf of Public Service Electric & Gas Company on Market Power Issues, with Paul Joskow, before State of New Jersey, Board of Public Utilities, concerning market power issues associated with PSE&G's proposal to implement retail customer choice in its competitive filings in New Jersey, July 30, 1997. - Affidavit on behalf of Union Electric Development Corporation before the Federal Energy Regulatory Commission in Docket No. ER97-3663-000, concerning Union Electric Development Corporation's request for the right to make wholesale bulk power sales at market-determined prices, July 8, 1997. - Affidavit on behalf of Union Electric Company before the Federal Energy Regulatory Commission in Docket No. ER97-3664-000, concerning Union Electric's request for the right to make wholesale bulk power sales at market-determined prices, July 8, 1997. - Rebuttal Testimony on Reopening on behalf of Union Electric Company and Central Illinois Public Service Company, before the Illinois Commerce Commission in Docket No. 95-0551, addressing competitive issues raised by witnesses for intervenors and the staff of the ICC in response to previous testimony, May 23, 1997. 268 Exhibit APP-301 Page 6 of 14 - Rebuttal Testimony on behalf of Wisconsin Power and Light Company, Interstate Power Company and IES Industries, Inc., before the Public Service Commission of Wisconsin in Docket No. 6680-UM-100, responding to concerns raised by intervenors regarding competitive issues associated with the proposed merger of the three companies, May 20, 1997. - Direct Testimony on Reopening on behalf of Union Electric Company and Central Illinois Public Service Company, before the Illinois Commerce Commission in Docket No. 95-0551, responding to the ICC's request that applicants apply the screening analysis contained in Appendix A of the Federal Energy Regulatory Commission's Order 592 to the effects of the proposed merger on existing and future Illinois retail markets, April 14, 1997. - Prepared Rebuttal Testimony on behalf of IES Utilities Inc., Interstate Power Company, Wisconsin Power & Light Company, South Beloit Water, Gas & Electric Company, Heartland Energy Services and Industrial Energy Applications, Inc., before the Federal Energy Regulatory Commission in Docket No. EC96-13-000, responding to issues raised by intervenors concerning the proposed merger and the application of the screening analysis contained in Appendix A of FERC's Order 592, April 14, 1997. - Affidavit on behalf of Constellation Power Source, Inc. before the Federal Energy Regulatory Commission in Docket No. ER97-2261-000, concerning Constellation's request for the right to make wholesale bulk power sales at market-determined prices, March 25, 1997. - Prepared Supplemental Direct Testimony on behalf of Ohio Edison Company, Pennsylvania Power Company, The Cleveland Electric Illuminating Company and The Toledo Edison Company, before the Federal Energy Regulatory Commission in Docket No. EC97-5-000, concerning the application of the screening analysis contained in Appendix A of FERC Order 592 to the applicants' proposed merger, March 20, 1997. - Prepared Additional Direct Testimony on behalf of IES Utilities Inc., Interstate Power Company, Wisconsin Power & Light Company, South Beloit Water, Gas & Electric Company, Heartland Energy Services and Industrial Energy Applications, Inc., before the Federal Energy Regulatory Commission in Docket No. EC96-13-000, concerning the application of the screening analysis contained in Appendix A of FERC Order 592 to the applicants' proposed merger, February 27, 1997. - Prepared Rebuttal Testimony on behalf of Union Electric Company and Central Illinois Public Service Company before the Federal Energy Regulatory Commission in Docket Nos. EC96-7-000, et al. addressing competitive issues related to the proposed merger of Union Electric Company and Central Illinois Public Service Company, January 13, 1997. - Affidavit on behalf of Union Electric Company and Central Illinois Public Service Company before the Federal Energy Regulatory Commission in Docket Nos. EC96-7-000, et al. concerning the effect of the FERC's Policy Statement on mergers (Order No. 592) on the proposed merger or Union Electric Company and Central Illinois Public Service Company, January 13, 1997. - Prepared Supplemental Direct Testimony on behalf of Union Electric Company and Central Illinois Public Service Company before the Federal Energy Regulatory Commission in Docket Nos. EC96-7-000, et al. concerning the effects of transmission constraints on the potential to exercise market power as a result of the proposed merger of Union Electric and Central Illinois Public Service, November 15, 1996. 269 Exhibit APP-301 Page 7 of 14 - Direct Testimony on behalf of Ohio Edison Company and Centerior before the Federal Energy Regulatory Commission in Docket No. EC97-5-000 concerning the effect of the proposed merger of Ohio Edison and Centerior on market power and competition, November 8, 1996. - Prepared Direct Testimony on behalf of Union Electric Company before the Missouri Public Service Commission in Case No. EM-96-149, concerning the effects on various market power concerns of the proposed merger between Union Electric Company and Central Illinois Public Service Company, November 1, 1996. - Testimony on behalf of Virginia Electric and Power Company in the matter of Gordonsville Energy, L.P. v. Virginia Electric and Power Company before the Circuit Court of the City of Richmond, Case No. LA-2266-4, concerning damages suffered by VEPCO as a result of a NUG outage, and the appropriateness of a liquidated damages provision in the contract between VEPCO and the NUG, October 23, 1996. - Prepared Direct Testimony on behalf of Southern Company Services, Inc. before the Federal Energy Regulatory Commission in Docket No. ER96-780-000, concerning whether constraints on the Florida/Southern interface give Southern the ability to exercise market power, September 23, 1996. - Deposition in the matter of Gordonsville Energy, L.P. v. Virginia Electric and Power Company before the Circuit Court of the City of Richmond, Case No. LA-2266-4, concerning damages suffered by VEPCO as a result of a NUG outage, September 17, 1996. - Prepared Rebuttal Testimony on behalf of Public Service Company of New Mexico before the Federal Energy Regulatory Commission in Docket No. ER95-1800-000, et al., addressing market power issues raised by intervenors in response to previous testimony, August 30, 1996. - Prepared Testimony on behalf of Public Service Company of New Mexico before the Federal Energy Regulatory Commission in Docket No. ER96-1551-000, concerning whether PNM possesses market power in transmission-constrained areas, July 10, 1996. - Affidavit on behalf of Central Louisiana Electric Company before the Federal Energy Regulatory Commission in Docket No. ER96-2677-000, concerning CLECO's request for the right to make wholesale bulk power sales at market-determined prices, July 9, 1996. - Supplemental Direct Testimony on behalf of IES Utilities Inc., Interstate Power Company, Wisconsin Power & Light Company, South Beloit Water, Gas & Electric Company, Heartland Energy Services and Industrial Energy Applications, Inc., before the Federal Energy Regulatory Commission in Docket No. EC96-13-000, examining the effects of the proposed formation of a regional Independent System Operator on the analyses and conclusions contained in previous testimony in support of the companies' proposed merger, June 5, 1996. - Prepared Testimony on behalf of Minnesota Power & Light Company before the Federal Energy Regulatory Commission in Docket No. EC95-16-000, concerning Minnesota Power & Light's request for the right to make wholesale bulk power sales at market-determined prices, May 16, 1996. - Prepared Rebuttal Testimony on behalf of IES Industries Inc., Interstate Power Company and WPL Holdings, Inc. before the Iowa Utilities Board in Docket No. SPU-96-6 addressing market power and competition issues raised by intervenors in response to previous merger testimony, April 22, 1996. 270 Exhibit APP-301 Page 8 of 14 - Prepared Direct Testimony on behalf of IES Utilities Inc., Interstate Power Company, Wisconsin Power & Light Company, South Beloit Water, Gas & Electric Company, Heartland Energy Services and Industrial Energy Applications, Inc., before the Federal Energy Regulatory Commission in Docket No. EC96-13-000, concerning the effects of their proposed merger on market power and competition, February 29, 1996. - Deposition in the matter of Westmoreland-LG&E Partners v. Virginia Electric and Power Company, Case No. LX-2859-1, concerning interpretation of capacity payment provisions in power purchase agreement under which Westmoreland-LG&E sells output of nonutility generator to VEPCO, February 23, 1996 and October 9, 1998. - Prepared Testimony on behalf of Union Electric Company and Central Illinois Public Service Company before the Federal Energy Regulatory Commission in Docket Nos. EC96-7-000 and ER96-679-000, concerning the effects of their proposed merger on market power and competition, December 22, 1995. - Prepared Testimony on behalf of Northeast Utilities before the Federal Energy Regulatory Commission in Northeast Utilities Service Company, Docket No. ER95-1686-000, concerning FERC's generation dominance standard in support of Northeast Utilities' request for market-based pricing authority, November 13, 1995. - Sur-reply affidavit on behalf of Rochester Gas & Electric before the U.S. District Court, Western District of New York, in Kamine/Besicorp Allegheny L.P. v. Rochester Gas & Electric Corporation, Case No. 95-CIV-6045L, in response to motion by Kamine/Besicorp Allegheny L.P. for a preliminary injunction, July 10, 1995. - Prepared Supplemental Rebuttal Testimony on Transmission NOPR Issues on behalf of Florida Power & Light Company before the Federal Energy Regulatory Commission in Florida Power & Light Company, Docket Nos. ER93-465-000, et al., addressing transmission NOPR issues raised by FERC Staff and Intervenors, May 19, 1995. - Prepared Direct Testimony on Transmission NOPR Issues on behalf of Florida Power & Light before the Federal Energy Regulatory Commission in Florida Power & Light Company, Docket Nos. ER93-465-000, et al., concerning the effects of FERC's recent Notice of Proposed Rulemaking on issues in FPL's ongoing case, April 25, 1995. - Affidavit on behalf of Rochester Gas & Electric before the U.S. District Court, Western District of New York, in Kamine/Besicorp Allegheny L.P. v. Rochester Gas & Electric Corporation, Case No. 95-CIV-6045L, in support of its opposition to a request by Kamine/Besicorp Allegheny L.P. for a temporary restraining order, March 9, 1995. - Testimony on behalf of Virginia Power before the Circuit Court of the City of Richmond in Case No. LW-730-4, Doswell Limited Partnership v. Virginia Electric Power Company concerning the level of fixed gas transportation costs associated with the proxy unit which forms the basis for VEPCO's payments to Doswell, March 2, 1995. - Prepared Rebuttal Testimony on behalf of American Electric Power Service Corporation before the Federal Energy Regulatory Commission in Docket No. ER93-540-001 addressing issues concerning FERC's new comparability standard and its implications for AEP's transmission service offerings, January 17, 1995. 271 Exhibit APP-301 Page 9 of 14 - Deposition on behalf of El Paso Electric Company and Central and South West Services, Inc. before the Federal Energy Regulatory Commission in Docket Nos. EC94-7-000 and ER94-898-000 concerning "comparability" and other transmission issues, December 22, 1994. - Prepared Rebuttal Testimony on behalf of Florida Power & Light Company before the Federal Energy Regulatory Commission in Florida Power & Light Company, Docket Nos. ER93-465-000, et al. concerning market power and competitive issues, comparability and other transmission issues, wholesale electric service tariff revisions, and issues concerning interchange contract revisions, December 16, 1994. - Prepared Rebuttal Testimony on behalf of El Paso Electric Company and Central and South West Services, Inc., before the Federal Energy Regulatory Commission, Dockets Nos. EC94-7-000 and ER94-898-000, concerning network transmission service and point-to-point transmission service, December 12, 1994. - Prepared Direct Testimony on behalf of Midwest Power Systems, Inc. and Iowa-Illinois Gas and Electric Company before the Federal Regulatory Commission, Docket No. EC95-4-000, concerning competitive issues raised by their proposed merger to form MidAmerican Energy Company, November 10, 1994. - Deposition on behalf of Florida Power Corporation in Orlando Cogen, Inc., et al., v. Florida Power Corporation, Case No. 94-303-CIV-ORL-18, US District Court in and for the Middle District of Florida, Orlando Division, involving a contract dispute between FPC and one of its NUG suppliers, August 30, 1994. - Prepared Direct Testimony on Comparability Issues on behalf of Florida Power & Light Company in Florida Power & Light Company, Docket Nos. ER93-465-000 and ER93-922-000 concerning a discussion of the differences between types of transmission services, usage of transmission systems by their owners, transmission services that FPL provides, and how those services compare and contrast with FPL's own uses of the transmission system, August 5, 1994. - Prepared Answering Testimony on behalf of Florida Power & Light Company in Florida Power & Light Company, Docket Nos. ER93-465-000 and ER93-922-000 concerning (i) whether municipal systems should receive billing credits for certain transmission facilities which they own which were argued to be part of an "integrated" transmission grid, and (ii) FPL's obligation to sell wholesale power under its Nuclear Regulatory Commission antitrust license conditions, July 7, 1994. - Deposition on behalf of Virginia Electric & Power Co. in re: Doswell Limited Partnership v. Virginia Electric & Power Co., Case No. LW-730-4, Circuit Court for the City of Richmond, involving an alleged fraud and breach of contract relating to payments by VEPCO to one of its NUG suppliers, April 5, 1994. - Prepared Final Rebuttal Testimony on behalf of Central Louisiana Electric Company before the Federal Energy Regulatory Commission in Docket No. ER93-498-000, examining an allegation of predatory pricing, March 16, 1994. - Prepared Rebuttal Testimony on behalf of Central Louisiana Electric Company before the Federal Energy Regulatory Commission in Docket No. ER93-498-000, examining an allegation of a municipal joint action agency that Central Louisiana's contract to provide bulk power service to a new municipal system customer constituted predatory pricing, December 23, 1993. 272 Exhibit APP-301 Page 10 of 14 - "Comments on the Commerce Commission's Draft Determination Concerning Trans Power's Proposal to Recover Fixed/Sunk Transmission Costs," testimony on competitive issues prepared at the request of The Electricity Industry Committee, New Zealand, November 30, 1993. - Prepared Direct Testimony on behalf of Florida Power & Light Company in Florida Power & Light Company, Docket Nos. ER93-465-000 and ER93-922-000 concerning competitive implications of wholesale tariff revisions, interchange contract revisions and a proposed "open access" transmission tariff, November 26, 1993. - Deposition on Behalf of Florida Power & Light in Florida Municipal Power Agency v. Florida Power & Light Co. Case No. 92-35-CIV-ORL-22 concerning damage related issues, July 21 and 22, 1993. - Affidavit on behalf of Florida Power & Light in Florida Municipal Power Agency v. Florida Power & Light Co. Case No. 92-35-CIV-ORL-22 concerning damage related issues, July 14, 1993. - Prepared Direct Testimony on behalf of the Detroit Edison Company In the Matter of the Application of the Association of Businesses Advocating Tariff Equity for Approval of an experimental retail wheeling tariff for Consumers Power Company, Case No. U-10143, and In the Matter on the Commission's own motion, to consider approval of an experimental retail wheeling tariff for The Detroit Edison Company, Case No. U-10176 before the Michigan Public Service Commission, March 1, 1993. - Deposition on behalf of Florida Power & Light in Florida Municipal Power Agency vs. Florida Power & Light Company, Case No. 92-35-CIV-ORL-22, concerning relevant markets, market power and competitive issues, February 25, 1993. - Deposition in Tucson Electric Power Company v. SCE Corporation, et al., Superior Court of the State California, Case No. 628170, June 19, 1992. - Affidavit on behalf of Iowa Power Inc. and Iowa Public Service Company, Federal Energy Regulatory Commission, Concerning the Competitive Effects of a Merger of the Two Companies, 1991. - Testimony on behalf of Defendants Union Electric and Missouri Utilities, in City of Malden, Missouri v. Union Electric Company and Missouri Utilities Company, U.S. District Court, Eastern District of Missouri, Southeastern Division, Civil Action No. 83-2533-C, 1988. - Testimony on behalf of Defendant Union Electric, in City of Kirkwood, Missouri v. Union Electric Company, U.S. District Court, Eastern District of Missouri, Civil Action No. 86-1787-C-6 (deposition testimony), 1987. - Testimony on behalf of Defendant Union Electric Company, in Citizens Electric Corporation v. Union Electric Company, U.S. District Court, Eastern District of Missouri, Eastern Division, Civil Action No. 83-2756C(c), 1986. - Testimony on behalf of Advo-System, Inc., before the Postal Rate Commission, Docket No. R84-1, Concerning Rates for Third Class Mail, 1984. - Testimony on behalf of D/FW Signal, Inc., before the Federal Communications Commission, Docket No. CC83-945, Concerning Cellular Telephone Service in Dallas-Fort Worth, 1983. 273 Exhibit APP-301 Page 11 of 14 - Testimony on behalf of the Department of Defense, before the Montana Public Service Commission, Docket No. 82.2.8, Concerning Telephone Service Rate Structure, 1982. - Testimony on behalf of Multnomah County, before the Public Utility Commissioner of Oregon, Docket UF 3565, Concerning Telephone Service Rate Structure, 1980. - Testimony on behalf of the Louisiana Consumer League, before the Louisiana Public Service Commission, Docket No. U-14078, Concerning Marginal Cost Pricing for Louisiana Power and Light Company, 1979. - Testimony on behalf of the State of Oregon, City of Portland, and County of Multnomah, before the Public Utility Commissioner of Oregon, Dockets UF3342 and UF3343, concerning Rates for Centrex and ESSX Telephone Service, 1978. SELECTED REPORTS - "An Economic Assessment of the Benefits of Repealing PUHCA," with John Landon, Ajay Gupta and Virginia Perry-Failor, prepared for Mid-American Energy Holdings, April 2000. - Updated Market Power Analysis for Detroit Edison Company, concerning Detroit Edison Company's market based pricing authority, submitted to the Federal Energy Regulatory Commission, December 17, 1999. - Report of Ameren to the Public Service Commission of Missouri on Market Power Issues, concerning whether Ameren, created by the merger of Union Electric Company and Central Illinois Public Service Company, is likely to have market power if deregulation and retail competition are introduced in Missouri, February 27, 1998. - "Supporting Companies' Report on Horizontal Market Power Analysis," with Paul Joskow, concerning analysis of market power issues in connection with a proposed reorganization of the PJM Pool, July 14, 1997. - "International Electricity Sector Investment by US Electric Utilities," with Graham Hadley, Paul Hennemeyer and Barbara MacMullen, prepared for The Kansai Electric Power Company, Inc., March 5, 1997. - "Report on Horizontal Market Power Issues," with Paul Joskow, prepared for Southern California Edison Company in FERC Docket No. ER96-1663-000, May 29, 1996. - "Recent Developments in North American Electric Generation Capacity Procurement Systems," with Mahim Chellappa, prepared for Electricite de France (EDF), Paris, France, August 1994. - "Comments on Transmission Reform Proposals," report prepared for the Edison Electric Institute, October 1993. - "Sunk Transmission Cost Recovery Issues," report prepared for The Electricity Industry Committee, New Zealand, September 1, 1993. - "Opportunity Cost Pricing for Electric Transmission: An Economic Assessment," report prepared for Edison Electric Institute, June 1992. 274 Exhibit APP-301 Page 12 of 14 - "Transmission Access and Pricing: What Does A Good `Open Access' System Look Like," NERA Working Paper #14, January 1992. - "Evaluation of Qualifying Facility Proposals," prepared for Florida Power Corporation, March 1991. - "Design of Capacity Procurement Systems," prepared for Electricite de France, January 1991. - "Issues in the Design of Generating Capacity Procurement Systems," prepared for TransAlta Utilities, January 1991. - "Government Regulators and Market Power Issues," prepared for Edison Electric Institute, January 1991. - "A Critique and Evaluation of the Large Public Power Council's Transmission Access and Pricing Proposal," prepared for Edison Electric Institute, December 1990. - "The Effects of a Premature Shutdown of the Trojan Nuclear Power Plant," prepared for Portland General Electric Company, October 1990. - "An Examination of the Proper Role for Utilities in Promoting Conservation Expenditures," prepared for Public Service Electric & Gas Company with T. Scott Newlon, 1990. - "Issues Concerning Selection Criteria Development for Capacity RFPs," prepared for the Bonneville Power Administration, February 15, 1990. - "Nonutility Generators and Bonneville Power Administration Resource Acquisition Policy," prepared for the Bonneville Power Administration, with David L. Weitzel, January 31, 1990. - "An Evaluation of Resource Solicitation Alternatives," prepared for the Bonneville Power Administration, January 31, 1990. - "Approaching the Transmission Access Debate Rationally," Transmission Research Group Working Paper Number 1, with Joe D. Pace, November 1987. - "The Essential Facilities Doctrine," NERA, June 1985. - "The Nuclear Regulatory Commission's Antitrust Review Process: An Analysis of the Impacts," Transcomm, Inc., prepared for the U.S. Department of Energy, 1981. - "Competitive Aspects of Utility Involvement in Cogeneration and Solar Programs," Transcomm, Inc., prepared for the U.S. Department of Energy, June 1981. - "An Appraisal of Antitrust Review Extension in the Context of Small Utility Fuel Use Act Compliance," Transcomm, Inc., prepared for the U.S. Department of Energy, July 28, 1980. - "Analysis of Proposed License Conditions with Respect to Antitrust Deficiencies," Transcomm, Inc., prepared for the U.S. Nuclear Regulatory Commission, 1978. - "Analysis of NRC Staff's Proposed License Conditions for Midland Units," Transcomm, Inc., prepared for the U.S. Nuclear Regulatory Commission, August 7, 1978. 275 Exhibit APP-301 Page 13 of 14 SELECTED SPEECHES - Presentation to the Board of Directors of the Salt River Project on Code of Conduct Issues Associated with Industry Restructuring, November 9, 1998 - "FERC's Approach To Addressing Horizontal Market Power in Electric Mergers," speech presented to Infocast Conference on Utility Mergers & Acquisitions, Washington, D.C., July 17, 1998. - "Problems in Applying the Appendix A Analytical Screen," speech presented to the Edison Electric Institute Workshop on Practical Applications of the FERC Merger Policy Guidelines, Arlington, Virginia, April 1, 1997. - "Evolving Market Power Issues in the Context of Electric Restructuring," speech presented to Eastern Mineral Law Foundation Forum on Natural Resources and Energy Law, Sanibel Island, Florida, February 13, 1997. - "An Overview of Antitrust in the Electric Industry," speech presented to Antitrust Law & Economics for the Electric Industry, sponsored by Energy Business, Inc., Washington, D.C., February 22, 1996. - "Moving From Here to There: Some Implications for Electric Transmission," speech presented to the Infocast Power Industry Forum, Palm Springs, California, February 17, 1995. - "What Does `Comparability' Really Mean?," speech presented to The Federal Energy Bar Association, Washington, D.C., November 17, 1994. - "Current Transmission Topics" and "Trans Alta's Unbundled Rate Proposal," presented to the Canadian Electrical Association, Montreal, PQ, Canada, May 9, 1994. - "Retail Wheeling Issues," speech presented to the Edison Electric Institute National Accounts Workshop, Atlanta, Georgia, February 7, 1994. - "Retail Wheeling: Doing It the Right Way," speech presented to the Retail Wheeling Conference, Denver, Colorado, November 8, 1993. - "Retail Wheeling," speech presented to the Missouri Valley Electric Association Division Conference, Kansas City, Missouri, October 22, 1993. - "An Economic Perspective on Current Transmission Pricing Issues," speech presented to the Edison Electric Institute 1993 Fall Legal Committee Meeting, Minneapolis, Minnesota, October 7, 1993. - "Characteristics of a `Good' Retail Wheeling System," speech presented to the Second Annual Electricity Conference sponsored by Executive Enterprises, Inc., Washington, D.C., April 21-22, 1993. - "Characteristics of a `Good' Retail Wheeling System," speech presented to the Electric Utility Business Environment Conference sponsored by Electric Utility Consultants, Inc., Denver, Colorado, March 16-17, 1993. - "Change in the Industry," seminar presentation on privatization and service unbundling presented to Ontario Hydro management and special strategy task force, Ontario, Canada, February 3, 1993. 276 Exhibit APP-301 Page 14 of 14 - "The U.S. Experience and What Is To Come," speech presented to NERA Seminar on Competition in the Regulated Industries (Electric/Telecommunications), Rye Town Hilton, Rye Town, New York, October 30, 1992. - "Emerging Transmission Pricing Issues," speech presented to Electric Utility Consultants, Inc.'s 3rd Annual Transmission & Wheeling Conference, Chicago, Illinois, September 22-23, 1992. - "Emerging Transmission Pricing Issues," speech presented to Executive Enterprises, Inc., 1992 Electricity Conference: Restructuring the Electricity Industry, Washington, D.C., September 15-16, 1992. - "A Pragmatic Look at Open Access," presented to DOE/NARUC Workshop on Electricity Transmission, Stockbridge, Massachusetts, June 2, 1992. - "Some Thoughts About Open Access," presented to EMA's Issues and Outlook Forum, Atlanta, Georgia, May 5, 1992. - "Transmission Access: How Should We Proceed?" Speech presented to the Second Annual Transmission and Wheeling Conference, Denver, Colorado, November 21, 1991. - "Can We Implement Reasonable Transmission Pricing and Access Procedures?" presented to the Edison Electric Institute System Planning Committee, Dallas, Texas, October 24, 1990. - "Issues in the Design of Competitive Bidding Systems," presented at the Pennsylvania Electric Association System Planning Meeting," 1990. - "Should We Use Opportunity Cost Pricing for Transmission?" presented to the Edison Electric Institute Interconnection Arrangements Committee, 1990. - "Recent Changes in the Electric Power Industry and Pressures on the Transmission System," presented at seminar "Competitive Electricity: Why the Debate?" Sponsored by the Electricity Consumers Resource Council, 1988. - "Some Thoughts on New Transmission Access and Pricing Proposals," presented at conference "Transmission Pricing and Access: Reinventing the Wheel," sponsored by Cogeneration and Independent Power Coalition of America and American Cogeneration Association, 1988. 277 EXHIBIT NO. APP-302 278 Exhibit APP-302 1 of 1 LIST OF ABBREVIATIONS AEC Allegheny Electric Cooperative AEP American Electric Power Company Allegheny Allegheny Energy AMP-Ohio American Municipal Power-Ohio ATC Available Transmission Capacity ATSI American Transmission Systems, Inc. CNG Consolidated Natural Gas Columbia Gas Columbia Gas of Virginia CPP Cleveland Public Power DetEd Detroit Edison Company DPL Dayton Power & Light Company DQE Duquesne Light Company ECAR East Central Area Reliability Coordination Agreement EIA Energy Information Administration EME Edison Mission Energy FERC Federal Energy Regulatory Commission FirstEnergy FirstEnergy Corporation GPU GPU, Inc. Great Lakes Great Lakes Energy Partners, L.L.C. HHI Herfindahl-Hirshmann Index HoldCo Marble HoldCo, Inc. ISO Independent System Operator JCPL Jersey Central Power & Light Company LDC local distribution company MAAC Mid-Atlantic Area Council MAIN Mid-America Interconnected Network, Inc. MAPP Mid-Continent Area Power Pool Marbel Marbel Energy Corporation MECS Michigan Electric Coordinating System MetEd Metropolitan Edison Company National Fuel National Fuel Gas Company NEPOOL New England Power Pool NERC North American Electric Reliability Council NUG non-utility generator NYMEX New York Mercantile Exchange NYPP New York Power Pool O&M Operating & Maintenance OASIS Open-Access Same-Time Information System OVEC Ohio Valley Electric Company Penelec Pennsylvania Electric Company Pepco Potomac Electric Power Company PJM Pennsylvania-New Jersey-Maryland Interconnection POD Point of Delivery POR Point of Receipt PPL Pennsylvania Power & Light Company RDI Resource Data International RTO Regional Transmission Organization SERC Southeastern Electric Reliability Council SPP Southwest Power Pool Tenneco Tenneco Energy Corporation Texas Eastern Texas Eastern Gas Transmission Corporation TTC Total Transmission Capacity USEC United States Enrichment Corporation VEPCO Virginia Electric & Power Company Wellsboro Wellsboro Electric Company 279 EXHIBIT NO. APP-303 280 EXHIBIT NO. APP-303 Map of Destination Markets for FirstEnergy - GPU Merger. Exhibit Intentionally Omitted. 281 EXHIBIT NO. APP-304 282 Exhibit No. APP-304 page 1 of 2 FIRST ENERGY AND GPU OFF - SYSTEM SALES 1997 - 1999
FIRST ENERGY GPU Purchasing Company MWH Revenues ($) MWH Revenues ($) ---------------------------------------------------------------------------------------------------------------------------- IOUS AEP 204,939 7,054,000 APS 154,950 3,795,000 88,288 2,229,058 Atlantic Electric - - 22,021 561,966 Baltimore Gas & Electric 417,994 7,554,000 2,255 520,992 Carolina Power & Light 9,773 320,000 2,342 412,964 Cinergy Services, Inc. 431,170 5,416,000 15,086 696,267 Commonwealth Edison 2,800 79,000 - - Conectiv - - 303,913 8,742,084 Constellation Power 23,739 1,916,000 16,589 401,147 Delmarva Power & Light 5,900 114,000 1,542 70,024 Detroit Edison 1,352,764 6,745,000 10,669 391,998 DPL 249,768 8,851,000 - - DQE 164,665 3,935,000 - - Duke Power Co. 11,573 4,673,000 - - Entergy 3,506 793,000 - - First Energy - - 61,559 472,230 GPU 347,874 8,653,000 Illinois Power 5,250 102,000 - - LGE 11,920 197,000 - - MECS ** 474,753 11,669,000 - - NIPS 4,839 135,000 - - Northeast Utilities - - 14,211 176,397 NYPP 357,232 8,433,000 151,669 2,550,489 Ontario Hydro - - 500 12,005 OVEC 23,490 434,000 - - PECO 196,018 4,565,000 34,516 1,356,348 Penn Power and Light 388,942 17,714,000 60,611 2,046,589 PEPCO 8,849,085 488,580,000 769 13,565 PJM * 396,785 11,990,000 10,425,420 333,838,284 PSEG 596,208 12,520,000 291,862 22,607,686 Southern 950 27,000 - - VEPCO 11,091 612,000 92,545 2,424,075 WPL 9,600 177,000 - - - - MUNICIPAL SYSTEMS - - ----------------- AMP-Ohio 1,752,364 72,332,000 - - Berlin Borough - - 55,631 2,288,380 Borough of Goldsboro - - 14,263 788,486 Borough of Lewisberry - - 5,843 309,413 Borough of Middletown - - 165,920 1,659,200 Borough of Royalton - - 11,201 580,237 Butler Borough - - 290,525 8,439,375 Columbia 5,475 149,000 - - CPP 14,630 3,693,000 - - East Conemaugh Borough - - 17,729 754,107 Ellwood City 58,503 2,157,000 - - Engle - - - - Gerald - - - 41,604 Girard Borough - - 115,971 4,657,263 Grove City 100,449 3,378,000 - -
283 Exhibit No. APP-304 page 2 of 2 FIRST ENERGY AND GPU OFF - SYSTEM SALES 1997 - 1999
FIRST ENERGY GPU Purchasing Company MWH Revenues ($) MWH Revenues ($) ---------------------------------------------------------------------------------------------------------------------------- Grove City West 5,438 152,000 - - Hooversville Borough - - 11,042 475,701 Lavallette Borough - - 32,253 1,009,874 Madison Borough - - 282,910 7,934,562 New Wilmington 48,872 2,225,000 - - Painesville 106,868 2,824,000 - - Pemberton Borough - - 15,312 429,657 Pike County Power & Light - - 848 42,887 Seaside Heights - - 69,605 2,129,345 Smethport Borough - - 43,796 1,823,738 Summerhill Borough - - 9,424 416,291 Wampum 10,672 512,000 - - Wellsboro 228,227 7,458,000 115,590 4,406,620 WVPA 29,480 822,000 - - Zelionopole - 178,000 - - - - OTHER - - ----- Allegheny Electric Coop - - 922,240 47,341,471 Buckeye 1,882,041 66,100,000 - - Marketers 1,935,056 60,652,000 1,660,569 54,673,434 NJ Pilot Program - - 114,715 2,865,478 Old Dominion Elec Coop - - 8,193 158,753 PA Pilot Program - - - 1,308,442 Penntech 2,163 - Penntech Residential - 543,912 Redacted - - 1,517,003 66,854,574 System Sales 55,265 1,181,000 - - ---------------------------------------------------------------------------------------------------------------------------- - - TOTAL SALES 20,940,918 840,866,000 17,079,113 591,456,972
NOTES: Total Sales = Sum of Sales from 1997, 1998, and 1999 * Excluding sales to utilities within PJM which are listed separately ** Excluding sales to Detroit Edison which are listed separately SOURCES: GPU sales taken from FERC Form 1 Filings (1997, 1998, 1999) First Energy sales provided by First Energy. 284 EXHIBIT NO. APP-305 285 Exhibit APP-305 page 1 of 1 PRICES IN DESTINATION MARKETS SYSTEM LAMBDAS FOR 1999 ($ PER MWH)
SUMMER SUMMER SUMMER SUMMER SUMMER WINTER SUPER PEAK I SUPER PEAK II SUPER PEAK III REST OF PEAK OFF PEAK SUPER PEAK --------------- --------------- ----------------- --------------- ------------- -------------- AEP 17.96 15.30 14.65 13.30 11.62 14.10 Allegheny 150.41 124.54 52.23 20.06 20.02 22.10 DPL 17.16 18.20 15.93 14.07 13.37 15.58 DQE 693.59 269.59 68.59 27.54 22.56 30.66 FE 811.36 414.37 175.65 66.89 32.48 30.97 MECS 310.11 195.76 79.75 32.15 26.77 41.03 NYISO 42.92 49.53 57.36 49.64 25.10 29.62 PJMEAST 437.16 265.90 83.20 28.94 17.17 31.67 PJMWEST 436.80 246.82 81.62 27.55 16.97 30.70 VEPCO 31.34 29.47 25.89 21.70 16.20 22.29
WINTER WINTER SPRING/FALL SPRING/FALL SPRING/FALL REST OF PEAK OFF PEAK SUPER PEAK REST OF PEAK OFF PEAK ---------------- ------------- -------------- --------------- ----------------- AEP 12.94 11.73 14.36 13.30 11.78 Allegheny 19.15 17.28 22.84 19.85 17.79 DPL 14.00 13.27 15.00 14.53 13.52 DQE 20.87 16.39 37.22 24.56 19.27 FE 23.48 15.21 30.21 24.04 16.39 MECS 21.36 16.27 31.58 22.30 16.03 NYISO 35.03 24.64 28.48 33.24 21.15 PJMEAST 19.71 14.20 37.15 23.26 14.02 PJMWEST 19.16 13.92 34.95 22.73 13.88 VEPCO 16.76 14.82 24.03 18.56 14.77
NYMEX FUTURES PRICES FOR 2001 ($ PER MWH) SUMMER WINTER SPRING/FALL PEAK PEAK PEAK ------------- --------------- ---------------- PJM 89.67 40.70 33.87 Cinergy 101.75 31.83 30.46 SOURCES NYPP System Lambdas: www.NYISO.com. System Lambdas for other Regions: FERC Form 714 NYMEX Futures Prices: www.NYMEX.com 286 EXHIBIT NO. APP-306 287 Exhibit APP-306 page 1 of 5 BASE CASE ECONOMIC CAPACITY
SUMMER WINTER -------------------------------------------------------- ------------------------------------ Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak ---------------------------------- -------- --------- --------- --------- --------- ----------- ---------- ---------- FE Pre-Merger HHI 5,228 5,225 5,085 4,334 3,215 4,948 4,194 4,113 Post-Merger HHI 5,243 5,240 5,101 4,369 3,269 4,985 4,236 4,274 Change 15 15 16 36 54 37 42 161 FE Capacity (MW) 11,798 11,788 11,090 10,101 9,965 10,789 10,162 8,175 GPU Capacity (MW) 17 18 18 43 90 41 52 166 Merged Capacity (MW) 11,815 11,805 11,108 10,144 10,055 10,830 10,215 8,341 FE Market Share 71.6% 71.6% 70.5% 64.8% 54.5% 69.8% 63.9% 63.1% GPU Market Share 0.1% 0.1% 0.1% 0.3% 0.5% 0.3% 0.3% 1.3% Merged Market Share 71.7% 71.7% 70.6% 65.1% 55.0% 70.0% 64.2% 64.3% PJM Pre-Merger HHI 1,164 1,163 1,181 1,178 1,143 976 1,130 1,551 Post-Merger HHI 1,176 1,175 1,190 1,183 1,155 998 1,141 1,577 Change 12 12 9 5 12 22 11 26 FE Capacity (MW) 761 761 472 206 360 964 390 235 GPU Capacity (MW) 2,415 2,415 2,043 1,926 1,911 2,171 1,991 1,971 Merged Capacity (MW) 3,176 3,176 2,515 2,132 2,271 3,136 2,381 2,206 FE Market Share 1.4% 1.4% 1.0% 0.5% 1.1% 2.2% 1.0% 1.2% GPU Market Share 4.4% 4.4% 4.5% 5.0% 5.7% 5.0% 5.4% 10.4% Merged Market Share 5.8% 5.8% 5.5% 5.5% 6.7% 7.3% 6.4% 11.7% AEP Pre-Merger HHI 2,434 2,433 2,385 2,464 3,817 2,243 2,131 2,586 Post-Merger HHI 2,434 2,434 2,386 2,464 3,817 2,243 2,131 2,593 Change 1 1 1 1 1 0 1 7 FE Capacity (MW) 3,012 3,011 3,019 2,968 1,664 1,613 1,694 1,591 GPU Capacity (MW) 18 18 21 25 28 26 46 354 Merged Capacity (MW) 3,029 3,030 3,040 2,993 1,692 1,639 1,740 1,945 FE Market Share 6.6% 6.6% 6.7% 6.7% 4.8% 3.4% 3.5% 3.9% GPU Market Share 0.0% 0.0% 0.0% 0.1% 0.1% 0.1% 0.1% 0.9% Merged Market Share 6.6% 6.6% 6.7% 6.8% 4.9% 3.5% 3.6% 4.8%
SPRING / FALL ----------------------------------- Destination Market Super Peak Off-Peak ---------------------------------- ----------- --------- ----------- FE Pre-Merger HHI 4,262 3,519 3,028 Post-Merger HHI 4,298 3,562 3,206 Change 35 43 178 FE Capacity (MW) 8,360 7,847 4,973 GPU Capacity (MW) 35 51 158 Merged Capacity (MW) 8,395 7,898 5,131 FE Market Share 64.3% 57.9% 53.0% GPU Market Share 0.3% 0.4% 1.7% Merged Market Share 64.6% 58.3% 54.6% PJM Pre-Merger HHI 940 1,059 1,288 Post-Merger HHI 967 1,077 1,320 Change 27 18 32 FE Capacity (MW) 979 460 262 GPU Capacity (MW) 1,885 1,747 1,717 Merged Capacity (MW) 2,864 2,207 1,979 FE Market Share 2.6% 1.5% 1.6% GPU Market Share 5.1% 5.9% 10.3% Merged Market Share 7.7% 7.4% 11.8% AEP Pre-Merger HHI 1,817 1,693 2,066 Post-Merger HHI 1,817 1,694 2,079 Change 1 1 13 FE Capacity (MW) 2,436 2,558 2,403 GPU Capacity (MW) 26 47 363 Merged Capacity (MW) 2,463 2,605 2,766 FE Market Share 5.7% 5.9% 6.6% GPU Market Share 0.1% 0.1% 1.0% Merged Market Share 5.8% 6.0% 7.6%
288 Exhibit APP-306, page 2 of 5 BASE CASE ECONOMIC CAPACITY
SUMMER WINTER -------------------------------------------------------- ------------------------------------ Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak ---------------------------------- -------- --------- --------- --------- --------- ----------- ---------- ---------- APS Pre-Merger HHI 4,150 4,126 3,886 3,298 3,607 4,550 2,482 2,644 Post-Merger HHI 4,153 4,129 3,889 3,303 3,612 4,554 2,493 2,668 Change 3 3 3 5 5 4 11 24 FE Capacity (MW) 311 311 311 414 362 334 807 640 GPU Capacity (MW) 84 85 89 101 110 89 166 312 Merged Capacity (MW) 394 396 400 516 472 423 973 952 FE Market Share 2.3% 2.3% 2.5% 3.2% 3.0% 2.7% 5.1% 4.9% GPU Market Share 0.6% 0.6% 0.7% 0.8% 0.9% 0.7% 1.0% 2.4% Merged Market Share 3.0% 3.0% 3.2% 4.0% 3.9% 3.4% 6.1% 7.3% DPL Pre-Merger HHI 7,115 7,092 6,817 5,475 3,907 5,308 3,766 2,963 Post-Merger HHI 7,115 7,092 6,817 5,476 3,909 5,308 3,767 2,967 Change 0 0 0 0 1 0 1 4 FE Capacity (MW) 137 137 137 211 351 234 408 475 GPU Capacity (MW) 0 0 0 1 3 1 2 8 Merged Capacity (MW) 137 137 137 212 354 235 410 484 FE Market Share 3.5% 3.6% 3.9% 5.8% 7.8% 6.3% 9.0% 10.0% GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.1% 0.0% 0.0% 0.2% Merged Market Share 3.5% 3.6% 3.9% 5.8% 7.9% 6.3% 9.0% 10.2% DQE Pre-Merger HHI 6,207 6,207 6,030 3,964 5,902 3,369 3,018 2,676 Post-Merger HHI 6,208 6,208 6,030 3,966 5,903 3,371 3,022 2,747 Change 0 0 0 2 1 2 4 70 FE Capacity (MW) 591 591 592 1,774 604 1,348 1,714 2,101 GPU Capacity (MW) 0 0 0 1 1 2 4 41 Merged Capacity (MW) 591 591 593 1,775 605 1,350 1,718 2,142 FE Market Share 17.5% 17.5% 18.7% 37.6% 19.4% 27.5% 30.7% 42.6% GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.1% 0.8% Merged Market Share 17.5% 17.5% 18.7% 37.7% 19.5% 27.5% 30.8% 43.4%
SPRING / FALL --------------------------------- Destination Market Super Peak Off-Peak ----------------------------- -------- -------- --------- APS Pre-Merger HHI 3,958 2,049 2,189 Post-Merger HHI 3,962 2,060 2,215 Change 4 12 26 FE Capacity (MW) 305 732 582 GPU Capacity (MW) 83 165 308 Merged Capacity (MW) 388 897 890 FE Market Share 2.8% 5.1% 5.0% GPU Market Share 0.8% 1.1% 2.6% Merged Market Share 3.6% 6.2% 7.6% DPL Pre-Merger HHI 4,712 3,243 2,618 Post-Merger HHI 4,713 3,245 2,623 Change 0 1 6 FE Capacity (MW) 228 397 457 GPU Capacity (MW) 1 2 11 Merged Capacity (MW) 229 399 468 FE Market Share 7.2% 10.0% 10.8% GPU Market Share 0.0% 0.1% 0.3% Merged Market Share 7.2% 10.0% 11.1% DQE Pre-Merger HHI 3,354 3,169 3,461 Post-Merger HHI 3,357 3,174 3,546 Change 3 6 85 FE Capacity (MW) 1,597 2,031 3,021 GPU Capacity (MW) 2 4 44 Merged Capacity (MW) 1,599 2,034 3,064 FE Market Share 36.2% 40.0% 54.3% GPU Market Share 0.0% 0.1% 0.8% Merged Market Share 36.3% 40.1% 55.1%
289 Exhibit APP-306, page 3 of 5 BASE CASE ECONOMIC CAPACITY
SUMMER WINTER ---------------------------------------------------------- --------------------------------- Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak ----------------------------- --------- ----------- ------- -------- ----------- ---------- ------- --------- Merged Market Share 17.5% 17.5% 18.7% 37.7% 19.5% 27.5% 30.8% 43.4% MECS Pre-Merger HHI 3,448 3,437 3,290 3,854 2,878 2,643 2,636 3,267 Post-Merger HHI 3,448 3,437 3,290 3,855 2,879 2,643 2,636 3,270 Change 0 0 0 0 1 0 0 2 FE Capacity (MW) 964 963 964 541 1,143 1,184 1,114 1,006 GPU Capacity (MW) 1 1 1 2 11 5 5 18 Merged Capacity (MW) 965 965 965 543 1,154 1,188 1,119 1,024 FE Market Share 4.5% 4.5% 5.5% 3.6% 7.2% 6.3% 6.5% 7.8% GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.1% 0.0% 0.0% 0.1% Merged Market Share 4.5% 4.5% 5.5% 3.6% 7.3% 6.3% 6.5% 7.9% NYPP Pre-Merger HHI 1,166 1,157 1,173 1,064 939 1,161 1,083 1,017 Post-Merger HHI 1,166 1,158 1,173 1,064 940 1,161 1,083 1,017 Change 0 0 0 0 0 0 0 0 FE Capacity (MW) 10 11 13 8 18 13 8 13 GPU Capacity (MW) 62 63 65 70 83 47 48 106 Merged Capacity (MW) 72 74 78 78 101 59 57 119 FE Market Share 0.0% 0.0% 0.0% 0.0% 0.1% 0.1% 0.0% 0.1% GPU Market Share 0.2% 0.2% 0.2% 0.3% 0.6% 0.2% 0.2% 1.0% Merged Market Share 0.2% 0.2% 0.2% 0.3% 0.8% 0.3% 0.3% 1.1% VEPCO Pre-Merger HHI 4,005 3,954 3,425 3,054 2,711 3,098 2,768 1,979 Post-Merger HHI 4,005 3,954 3,426 3,055 2,712 3,099 2,769 1,986 Change 1 1 1 1 1 1 1 7 FE Capacity (MW) 176 176 181 180 128 104 107 207 GPU Capacity (MW) 99 101 105 111 136 138 140 308 Merged Capacity (MW) 275 277 286 292 264 242 247 515 FE Market Share 0.8% 0.8% 0.9% 1.0% 0.8% 0.6% 0.6% 1.6%
SPRING / FALL ----------------------------------- Destination Market Super Peak Off-Peak ---------------------------------- ----------- --------- ----------- MECS Pre-Merger HHI 2,363 2,351 2,816 Post-Merger HHI 2,364 2,352 2,824 Change 1 1 7 FE Capacity (MW) 1,633 1,531 1,368 GPU Capacity (MW) 7 9 33 Merged Capacity (MW) 1,640 1,540 1,401 FE Market Share 9.9% 10.3% 12.2% GPU Market Share 0.0% 0.1% 0.3% Merged Market Share 10.0% 10.4% 12.5% NYPP Pre-Merger HHI 1,001 956 807 Post-Merger HHI 1,001 956 810 Change 0 0 3 FE Capacity (MW) 48 34 54 GPU Capacity (MW) 131 148 320 Merged Capacity (MW) 179 182 374 FE Market Share 0.2% 0.2% 0.5% GPU Market Share 0.5% 0.7% 2.9% Merged Market Share 0.7% 0.9% 3.4% VEPCO Pre-Merger HHI 3,067 2,626 1,734 Post-Merger HHI 3,069 2,628 1,746 Change 1 2 12 FE Capacity (MW) 148 153 254 GPU Capacity (MW) 132 145 316 Merged Capacity (MW) 280 298 570 FE Market Share 0.9% 1.0% 2.2%
290 Exhibit APP-306, page 4 of 5
BASE CASE ECONOMIC CAPACITY SUMMER WINTER -------------------------------------------------------- ------------------------------------ Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak ---------------------------------- -------- --------- --------- ------ --------- ----------- ---------- ---------- GPU Market Share 0.4% 0.5% 0.5% 0.6% 0.8% 0.8% 0.8% 2.3% Merged Market Share 1.2% 1.2% 1.4% 1.6% 1.6% 1.3% 1.5% 3.9% PJM-WESTINT Pre-Merger HHI 1,164 1,163 1,181 1,178 1,143 976 1,130 1,551 Post-Merger HHI 1,176 1,175 1,190 1,183 1,155 998 1,141 1,577 Change 12 12 9 5 12 22 11 26 FE Capacity (MW) 761 761 472 206 360 964 390 235 GPU Capacity (MW) 2,415 2,415 2,043 1,926 1,911 2,171 1,991 1,971 Merged Capacity (MW) 3,176 3,176 2,515 2,132 2,271 3,136 2,381 2,206 FE Market Share 1.4% 1.4% 1.0% 0.5% 1.1% 2.2% 1.0% 1.2% GPU Market Share 4.4% 4.4% 4.5% 5.0% 5.7% 5.0% 5.4% 10.4% Merged Market Share 5.8% 5.8% 5.5% 5.5% 6.7% 7.3% 6.4% 11.7% PJM-CENTINT Pre-Merger HHI 1,508 1,507 1,550 1,462 1,479 1,312 1,455 1,564 Post-Merger HHI 1,513 1,513 1,555 1,465 1,487 1,325 1,462 1,589 Change 6 6 5 3 8 13 7 26 FE Capacity (MW) 216 216 149 71 139 320 151 229 GPU Capacity (MW) 2,177 2,177 1,815 1,714 1,713 1,926 1,769 1,962 Merged Capacity (MW) 2,392 2,392 1,964 1,785 1,852 2,246 1,920 2,191 FE Market Share 0.5% 0.5% 0.4% 0.3% 0.6% 1.0% 0.6% 1.2% GPU Market Share 5.3% 5.4% 5.5% 6.1% 6.9% 6.3% 6.5% 10.5% Merged Market Share 5.9% 5.9% 5.9% 6.4% 7.5% 7.3% 7.0% 11.7% PJM-EASTINT Pre-Merger HHI 1,485 1,477 1,417 1,378 1,350 1,171 1,306 1,667 Post-Merger HHI 1,493 1,484 1,424 1,382 1,360 1,189 1,315 1,691 Change 7 7 7 4 10 18 9 24 FE Capacity (MW) 216 217 150 71 133 292 138 172 GPU Capacity (MW) 1,863 1,864 1,517 1,429 1,441 1,604 1,468 1,757 Merged Capacity (MW) 2,079 2,081 1,667 1,500 1,574 1,896 1,606 1,929
SPRING / FALL ----------------------------------- Destination Market Super Peak Off-Peak ---------------------------------- ----------- --------- ----------- GPU Market Share 0.8% 1.0% 2.7% Merged Market Share 1.7% 2.0% 5.0% PJM-WESTINT Pre-Merger HHI 945 1,059 1,288 Post-Merger HHI 971 1,077 1,320 Change 26 18 32 FE Capacity (MW) 955 460 262 GPU Capacity (MW) 1,885 1,747 1,717 Merged Capacity (MW) 2,841 2,207 1,979 FE Market Share 2.6% 1.5% 1.6% GPU Market Share 5.1% 5.9% 10.3% Merged Market Share 7.7% 7.4% 11.8% PJM-CENTINT Pre-Merger HHI 1,295 1,365 1,417 Post-Merger HHI 1,311 1,378 1,446 Change 16 13 29 FE Capacity (MW) 317 192 199 GPU Capacity (MW) 1,633 1,533 1,631 Merged Capacity (MW) 1,950 1,725 1,830 FE Market Share 1.3% 0.9% 1.3% GPU Market Share 6.5% 7.1% 10.9% Merged Market Share 7.7% 8.0% 12.2% PJM-EASTINT Pre-Merger HHI 1,205 1,228 1,432 Post-Merger HHI 1,226 1,243 1,463 Change 21 15 30 FE Capacity (MW) 296 174 173 GPU Capacity (MW) 1,355 1,279 1,467 Merged Capacity (MW) 1,651 1,454 1,640
291 Exhibit APP-306, page 5 of 5 BASE CASE ECONOMIC CAPACITY
SUMMER WINTER -------------------------------------------------------- ------------------------------------ Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak ---------------------------------- -------- --------- --------- --------- --------- ----------- ---------- ---------- FE Market Share 0.7% 0.7% 0.6% 0.3% 0.7% 1.3% 0.7% 1.1% GPU Market Share 5.7% 5.7% 5.7% 6.4% 7.4% 7.0% 7.0% 11.1% Merged Market Share 6.3% 6.3% 6.3% 6.8% 8.1% 8.3% 7.6% 12.2%
SPRING / FALL ----------------------------------- Destination Market Super Peak Off-Peak ---------------------------------- ----------- --------- ----------- FE Market Share 1.5% 1.0% 1.3% GPU Market Share 7.0% 7.5% 11.3% Merged Market Share 8.5% 8.6% 12.7%
292 EXHIBIT NO. APP-307 293 Exhibit APP-307, page 1 of 5 BASE CASE AVAILABLE ECONOMIC CAPACITY
SUMMER WINTER ---------------------------------------------------------- ---------------------------------- Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak ------------------------------- -------- ---------- -------- ---------- --------- ---------- -------- --------- FE Pre-Merger HHI 1,117 1,213 1,875 1,488 1,524 1,380 1,426 3,029 Post-Merger HHI 1,117 1,213 1,875 1,488 1,524 1,380 1,426 3,029 Change - - - - - - - - FE Capacity (MW) 686 1,344 1,739 2,477 3,518 1,894 2,537 1,693 GPU Capacity (MW) - - - - - - - - Merged Capacity (MW) 686 1,344 1,739 2,477 3,518 1,894 2,537 1,693 FE Market Share 13.4% 23.2% 29.8% 31.8% 30.2% 29.9% 31.3% 50.6% GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% Merged Market Share 13.4% 23.2% 29.8% 31.8% 30.2% 29.9% 31.3% 50.6% PJM Pre-Merger HHI 1,072 1,049 1,095 1,154 1,085 930 1,064 4,382 Post-Merger HHI 1,072 1,049 1,095 1,154 1,085 930 1,064 4,382 Change - - - - - - - - FE Capacity (MW) 210 227 357 152 335 449 268 - GPU Capacity (MW) - - - - - - - - Merged Capacity (MW) 210 227 357 152 335 449 268 - FE Market Share 0.9% 1.0% 2.1% 1.0% 2.4% 2.9% 2.0% 0.0% GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% Merged Market Share 0.9% 1.0% 2.1% 1.0% 2.4% 2.9% 2.0% 0.0% AEP Pre-Merger HHI 791 810 1,127 1,411 2,389 975 1,025 4,637 Post-Merger HHI 791 810 1,127 1,411 2,389 975 1,025 4,637 Change - - - - - - - - FE Capacity (MW) 670 1,255 1,610 2,404 1,686 1,631 1,714 - GPU Capacity (MW) - - - - - - - - Merged Capacity (MW) 670 1,255 1,610 2,404 1,686 1,631 1,714 - FE Market Share 3.9% 6.6% 8.8% 10.8% 8.2% 8.3% 6.6% 0.0% GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% Merged Market Share 3.9% 6.6% 8.8% 10.8% 8.2% 8.3% 6.6% 0.0%
SPRING / FALL ---------------------------------- Destination Market Super Peak Off-Peak ------------------------------- --------- --------- ---------- FE Pre-Merger HHI 1,176 1,070 1,756 Post-Merger HHI 1,176 1,070 1,756 Change - - - FE Capacity (MW) - 711 - GPU Capacity (MW) - - - Merged Capacity (MW) - 711 - FE Market Share 0.0% 11.5% 0.0% GPU Market Share 0.0% 0.0% 0.0% Merged Market Share 0.0% 11.5% 0.0% PJM Pre-Merger HHI 1,117 1,072 2,561 Post-Merger HHI 1,117 1,072 2,561 Change - - - FE Capacity (MW) - 237 - GPU Capacity (MW) - - - Merged Capacity (MW) - 237 - FE Market Share 0.0% 2.3% 0.0% GPU Market Share 0.0% 0.0% 0.0% Merged Market Share 0.0% 2.3% 0.0% AEP Pre-Merger HHI 1,230 1,079 5,559 Post-Merger HHI 1,230 1,079 5,559 Change - - - FE Capacity (MW) - 694 - GPU Capacity (MW) - - - Merged Capacity (MW) - 694 - FE Market Share 0.0% 4.7% 0.0% GPU Market Share 0.0% 0.0% 0.0% Merged Market Share 0.0% 4.7% 0.0%
294 Exhibit APP-307,page 2 of 5 BASE CASE AVAILABLE ECONOMIC CAPACITY
SUMMER WINTER ---------------------------------------------------------- ---------------------------------- Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak ------------------------------- -------- ---------- -------- ---------- --------- ---------- -------- --------- APS Pre-Merger HHI 1,145 1,269 1,405 1,337 1,861 2,521 1,328 3,426 Post-Merger HHI 1,145 1,269 1,405 1,337 1,861 2,521 1,328 3,426 Change - - - - - - - - FE Capacity (MW) 314 315 315 419 367 338 816 - GPU Capacity (MW) - - - - - - - - Merged Capacity (MW) 314 315 315 419 367 338 816 - FE Market Share 5.2% 5.3% 5.8% 6.3% 5.3% 4.5% 7.0% 0.0% GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% Merged Market Share 5.2% 5.3% 5.8% 6.3% 5.3% 4.5% 7.0% 0.0% DPL Pre-Merger HHI 3,016 3,269 2,996 2,737 2,335 1,297 1,483 2,673 Post-Merger HHI 3,016 3,269 2,996 2,737 2,335 1,297 1,483 2,673 Change - - - - - - - - FE Capacity (MW) 95 113 118 177 297 185 341 - GPU Capacity (MW) - - - - - - - - Merged Capacity (MW) 95 113 118 177 297 185 341 - FE Market Share 7.6% 8.4% 9.5% 9.5% 9.9% 13.8% 13.2% 0.0% GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% Merged Market Share 7.6% 8.4% 9.5% 9.5% 9.9% 13.8% 13.2% 0.0% DQE Pre-Merger HHI 4,632 4,465 4,360 3,800 4,474 2,539 2,541 3,920 Post-Merger HHI 4,632 4,465 4,360 3,800 4,474 2,539 2,541 3,920 Change - - - - - - - - FE Capacity (MW) 598 599 599 1,795 612 1,362 1,734 - GPU Capacity (MW) - - - - - - - - Merged Capacity (MW) 598 599 599 1,795 612 1,362 1,734 - FE Market Share 29.8% 31.6% 33.0% 52.8% 31.4% 41.8% 40.4% 0.0% GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0%
SPRING / FALL ---------------------------------- Destination Market Super Peak Off-Peak ------------------------------- --------- --------- ---------- APS Pre-Merger HHI 1,752 1,046 2,963 Post-Merger HHI 1,752 1,046 2,963 Change - - - FE Capacity (MW) - 694 - GPU Capacity (MW) - - - Merged Capacity (MW) - 694 - FE Market Share 0.0% 8.4% 0.0% GPU Market Share 0.0% 0.0% 0.0% Merged Market Share 0.0% 8.4% 0.0% DPL Pre-Merger HHI 875 1,203 2,905 Post-Merger HHI 875 1,203 2,905 Change - - - FE Capacity (MW) - 223 - GPU Capacity (MW) - - - Merged Capacity (MW) - 223 - FE Market Share 0.0% 10.0% 0.0% GPU Market Share 0.0% 0.0% 0.0% Merged Market Share 0.0% 10.0% 0.0% DQE Pre-Merger HHI 2,104 2,196 5,553 Post-Merger HHI 2,104 2,196 5,553 Change - - - FE Capacity (MW) - 694 - GPU Capacity (MW) - - - Merged Capacity (MW) - 694 - FE Market Share 0.0% 26.0% 0.0% GPU Market Share 0.0% 0.0% 0.0%
295 Exhibit APP-307, page 3 of 5 BASE CASE AVAILABLE ECONOMIC CAPACITY
SUMMER WINTER ---------------------------------------------------------- ---------------------------------- Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak ------------------------------- -------- ---------- -------- ---------- --------- ---------- -------- --------- Merged Market Share 29.8% 31.6% 33.0% 52.8% 31.4% 41.8% 40.4% 0.0% MECS Pre-Merger HHI 1,285 1,481 1,819 1,659 1,411 881 1,023 2,212 Post-Merger HHI 1,285 1,481 1,819 1,659 1,411 881 1,023 2,212 Change - - - - - - - - FE Capacity (MW) 670 794 831 453 968 935 931 - GPU Capacity (MW) - - - - - - - - Merged Capacity (MW) 670 794 831 453 968 935 931 - FE Market Share 17.9% 19.1% 25.0% 15.8% 18.8% 16.5% 17.1% 0.0% GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% Merged Market Share 17.9% 19.1% 25.0% 15.8% 18.8% 16.5% 17.1% 0.0% NYPP Pre-Merger HHI 1,135 1,181 1,150 1,011 1,404 1,392 1,383 3,800 Post-Merger HHI 1,135 1,181 1,150 1,011 1,404 1,392 1,383 3,800 Change - - - - - - - - FE Capacity (MW) 26 27 37 22 48 43 26 - GPU Capacity (MW) - - - - - - - - Merged Capacity (MW) 26 27 37 22 48 43 26 - FE Market Share 0.2% 0.2% 0.3% 0.2% 1.0% 0.6% 0.5% 0.0% GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% Merged Market Share 0.2% 0.2% 0.3% 0.2% 1.0% 0.6% 0.5% 0.0% VEPCO Pre-Merger HHI 725 714 1,132 887 1,021 680 769 3,268 Post-Merger HHI 725 714 1,132 887 1,021 680 769 3,268 Change - - - - - - - - FE Capacity (MW) 127 206 226 318 236 302 230 - GPU Capacity (MW) - - - - - - - - Merged Capacity (MW) 127 206 226 318 236 302 230 - FE Market Share 2.0% 3.4% 4.0% 5.5% 3.2% 4.0% 3.0% 0.0%
SPRING / FALL ---------------------------------- Destination Market Super Peak Off-Peak ------------------------------- --------- --------- ---------- Merged Market Share 0.0% 26.0% 0.0% MECS Pre-Merger HHI 863 848 2,853 Post-Merger HHI 863 848 2,853 Change - - - FE Capacity (MW) - 694 - GPU Capacity (MW) - - - Merged Capacity (MW) - 694 - FE Market Share 0.0% 14.0% 0.0% GPU Market Share 0.0% 0.0% 0.0% Merged Market Share 0.0% 14.0% 0.0% NYPP Pre-Merger HHI 1,481 1,004 3,467 Post-Merger HHI 1,481 1,004 3,467 Change - - - FE Capacity (MW) - 119 - GPU Capacity (MW) - - - Merged Capacity (MW) - 119 - FE Market Share 0.0% 1.6% 0.0% GPU Market Share 0.0% 0.0% 0.0% Merged Market Share 0.0% 1.6% 0.0% VEPCO Pre-Merger HHI 929 914 2,269 Post-Merger HHI 929 914 2,269 Change - - - FE Capacity (MW) - 139 - GPU Capacity (MW) - - - Merged Capacity (MW) - 139 - FE Market Share 0.0% 2.5% 0.0%
296 Exhibit APP-307, page 4 of 5 BASE CASE AVAILABLE ECONOMIC CAPACITY
SUMMER WINTER ---------------------------------------------------------- ---------------------------------- Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak ------------------------------- -------- ---------- -------- ---------- --------- ---------- -------- --------- GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% Merged Market Share 2.0% 3.4% 4.0% 5.5% 3.2% 4.0% 3.0% 0.0% PJM-WESTINT Pre-Merger HHI 1,072 1,049 1,095 1,154 1,085 930 1,064 4,382 Post-Merger HHI 1,072 1,049 1,095 1,154 1,085 930 1,064 4,382 Change - - - - - - - - FE Capacity (MW) 210 227 357 152 335 449 268 - GPU Capacity (MW) - - - - - - - - Merged Capacity (MW) 210 227 357 152 335 449 268 - FE Market Share 0.9% 1.0% 2.1% 1.0% 2.4% 2.9% 2.0% 0.0% GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% Merged Market Share 0.9% 1.0% 2.1% 1.0% 2.4% 2.9% 2.0% 0.0% PJM-CENTINT Pre-Merger HHI 1,180 1,149 1,220 1,198 1,149 926 1,076 4,382 Post-Merger HHI 1,180 1,149 1,220 1,198 1,149 926 1,076 4,382 Change - - - - - - - - FE Capacity (MW) 115 124 225 101 240 283 201 - GPU Capacity (MW) - - - - - - - - Merged Capacity (MW) 115 124 225 101 240 283 201 - FE Market Share 0.6% 0.7% 1.7% 0.8% 2.1% 2.4% 1.8% 0.0% GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% Merged Market Share 0.6% 0.7% 1.7% 0.8% 2.1% 2.4% 1.8% 0.0% PJM-EASTINT Pre-Merger HHI 1,128 1,100 1,136 1,176 1,089 918 1,060 4,382 Post-Merger HHI 1,128 1,100 1,136 1,176 1,089 918 1,060 4,382 Change - - - - - - - - FE Capacity (MW) 147 160 291 123 269 345 240 - GPU Capacity (MW) - - - - - - - - Merged Capacity (MW) 147 160 291 123 269 345 240 -
SPRING / FALL ---------------------------------- Destination Market Super Peak Off-Peak ------------------------------- --------- --------- ---------- GPU Market Share 0.0% 0.0% 0.0% Merged Market Share 0.0% 2.5% 0.0% PJM-WESTINT Pre-Merger HHI 1,117 1,072 2,561 Post-Merger HHI 1,117 1,072 2,561 Change - - - FE Capacity (MW) - 237 - GPU Capacity (MW) - - - Merged Capacity (MW) - 237 - FE Market Share 0.0% 2.3% 0.0% GPU Market Share 0.0% 0.0% 0.0% Merged Market Share 0.0% 2.3% 0.0% PJM-CENTINT Pre-Merger HHI 1,078 1,053 2,561 Post-Merger HHI 1,078 1,053 2,561 Change - - - FE Capacity (MW) - 180 - GPU Capacity (MW) - - - Merged Capacity (MW) - 180 - FE Market Share 0.0% 2.2% 0.0% GPU Market Share 0.0% 0.0% 0.0% Merged Market Share 0.0% 2.2% 0.0% PJM-EASTINT Pre-Merger HHI 1,107 1,071 2,561 Post-Merger HHI 1,107 1,071 2,561 Change - - - FE Capacity (MW) - 231 - GPU Capacity (MW) - - - Merged Capacity (MW) - 231 -
297 Exhibit APP-307, page 5 of 5 BASE CASE AVAILABLE ECONOMIC CAPACITY
SUMMER WINTER ---------------------------------------------------------- ---------------------------------- Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak ------------------------------- -------- ---------- -------- ---------- --------- ---------- -------- --------- FE Market Share 0.8% 0.8% 2.0% 1.0% 2.3% 2.7% 1.9% 0.0% GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% Merged Market Share 0.8% 0.8% 2.0% 1.0% 2.3% 2.7% 1.9% 0.0%
SPRING / FALL ---------------------------------- Destination Market Super Peak Off-Peak ------------------------------- --------- --------- ---------- FE Market Share 0.0% 2.3% 0.0% GPU Market Share 0.0% 0.0% 0.0% Merged Market Share 0.0% 2.3% 0.0%
298 EXHIBIT NO. APP-308 299 Exhibit APP-308, page 1 of 1 OFF PEAK FLOWS BETWEEN ECAR AND PJM
Hours with Hours with Tie West To East Flow Percentage East to West Flow Percentage FirstEnergy-PJM 5734 94.2 354 5.8 Allegheny-PJM 5322 87.4 266 12.6 Source: http://www.pjm.com/market_system_data/system/downloads/1999netsched.xls (October 31, 2000). http://www.pjm.com/market_system_data/system/downloads/1998netsched.xls (October 31, 2000). http://www.pjm.com/market_system_data/system/downloads/spjm97s_a.xls (October 31, 2000).
300 EXHIBIT NO. APP-309 301 Exhibit APP-309, page 1 of 5 SENSITIVITY FOR FIRM ATC
SUMMER WINTER ---------------------------------------------------------- -------------------------------- Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak ------------------------------ --------- -------- ------- -------- ---------- ------- --------- ---------- FE Pre-Merger HHI 5,222 5,219 5,079 4,330 3,489 4,951 4,197 4,183 Post-Merger HHI 5,238 5,235 5,097 4,364 3,536 4,983 4,233 4,309 Change 16 16 17 34 47 32 36 126 FE Capacity (MW) 11,798 11,788 11,090 10,101 9,965 10,789 10,162 8,175 GPU Capacity (MW) 18 18 19 41 71 35 44 127 Merged Capacity (MW) 11,816 11,806 11,109 10,142 10,036 10,824 10,207 8,302 FE Market Share 71.6% 71.6% 70.5% 64.8% 57.2% 69.8% 63.9% 63.8% GPU Market Share 0.1% 0.1% 0.1% 0.3% 0.4% 0.2% 0.3% 1.0% Merged Market Share 71.7% 71.7% 70.6% 65.1% 57.6% 70.0% 64.2% 64.7% PJM Pre-Merger HHI 1,165 1,164 1,183 1,178 1,146 1,038 1,136 1,559 Post-Merger HHI 1,175 1,174 1,190 1,182 1,155 1,057 1,144 1,579 Change 11 11 7 4 9 19 8 19 FE Capacity (MW) 665 665 378 150 269 757 294 175 GPU Capacity (MW) 2,415 2,415 2,043 1,926 1,911 2,171 1,991 1,971 Merged Capacity (MW) 3,079 3,079 2,421 2,076 2,180 2,929 2,285 2,146 FE Market Share 1.2% 1.2% 0.8% 0.4% 0.8% 1.8% 0.8% 0.9% GPU Market Share 4.4% 4.4% 4.5% 5.0% 5.7% 5.2% 5.4% 10.4% Merged Market Share 5.6% 5.6% 5.3% 5.3% 6.5% 7.0% 6.2% 11.3% AEP Pre-Merger HHI 2,443 2,443 2,396 2,480 3,828 2,260 2,156 2,623 Post-Merger HHI 2,443 2,443 2,396 2,480 3,828 2,260 2,156 2,625 Change 0 0 0 0 0 0 0 2 FE Capacity (MW) 2,309 2,308 2,315 2,275 1,276 2,131 2,237 2,101 GPU Capacity (MW) 4 4 5 6 7 6 7 70 Merged Capacity (MW) 2,313 2,313 2,320 2,281 1,283 2,137 2,244 2,170 FE Market Share 5.0% 5.0% 5.1% 5.2% 3.7% 4.5% 4.6% 5.2% GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.2% Merged Market Share 5.1% 5.1% 5.1% 5.2% 3.7% 4.5% 4.6% 5.3%
SPRING / FALL --------------------------------- Destination Market Super Peak Off-Peak ------------------------------ -------- ------- --------- FE Pre-Merger HHI 4,284 3,554 3,220 Post-Merger HHI 4,312 3,586 3,351 Change 28 32 132 FE Capacity (MW) 8,360 7,847 4,973 GPU Capacity (MW) 28 38 108 Merged Capacity (MW) 8,388 7,885 5,082 FE Market Share 64.3% 57.9% 55.0% GPU Market Share 0.2% 0.3% 1.2% Merged Market Share 64.6% 58.2% 56.2% PJM Pre-Merger HHI 1,025 1,069 1,297 Post-Merger HHI 1,043 1,079 1,314 Change 18 10 17 FE Capacity (MW) 586 255 140 GPU Capacity (MW) 1,885 1,747 1,717 Merged Capacity (MW) 2,471 2,003 1,857 FE Market Share 1.7% 0.9% 0.8% GPU Market Share 5.3% 5.9% 10.3% Merged Market Share 7.0% 6.7% 11.1% AEP Pre-Merger HHI 1,845 1,734 2,100 Post-Merger HHI 1,845 1,734 2,102 Change 0 0 2 FE Capacity (MW) 2,253 2,365 2,223 GPU Capacity (MW) 5 6 65 Merged Capacity (MW) 2,258 2,371 2,288 FE Market Share 5.3% 5.5% 6.2% GPU Market Share 0.0% 0.0% 0.2% Merged Market Share 5.3% 5.5% 6.3%
302 Exhibit APP-309, page 2 of 5 SENSITIVITY FOR FIRM ATC
SUMMER WINTER ---------------------------------------------------------- -------------------------------- Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak ------------------------------ --------- -------- ------- -------- ---------- ------- --------- ---------- APS Pre-Merger HHI 4,932 4,908 4,668 4,486 4,449 4,780 4,512 4,332 Post-Merger HHI 4,937 4,913 4,674 4,493 4,459 4,787 4,521 4,359 Change 5 5 6 7 9 8 9 27 FE Capacity (MW) 843 843 845 844 844 982 981 1,000 GPU Capacity (MW) 46 47 49 52 64 58 59 130 Merged Capacity (MW) 889 890 894 896 907 1,040 1,039 1,130 FE Market Share 6.9% 7.0% 7.4% 7.7% 7.8% 8.1% 8.6% 10.2% GPU Market Share 0.4% 0.4% 0.4% 0.5% 0.6% 0.5% 0.5% 1.3% Merged Market Share 7.3% 7.3% 7.8% 8.2% 8.4% 8.5% 9.1% 11.5% DPL Pre-Merger HHI 7,114 7,091 6,815 5,474 3,928 5,307 3,768 2,947 Post-Merger HHI 7,114 7,091 6,815 5,474 3,929 5,307 3,769 2,950 Change 0 0 0 0 0 0 1 3 FE Capacity (MW) 88 88 88 136 227 239 416 462 GPU Capacity (MW) 0 0 0 1 2 1 2 8 Merged Capacity (MW) 88 88 88 136 229 240 417 469 FE Market Share 2.3% 2.3% 2.5% 3.7% 5.1% 6.4% 9.1% 9.7% GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.2% Merged Market Share 2.3% 2.3% 2.5% 3.7% 5.1% 6.4% 9.2% 9.9% DQE Pre-Merger HHI 6,206 6,206 6,028 3,964 5,901 3,368 3,015 2,661 Post-Merger HHI 6,206 6,206 6,029 3,965 5,902 3,369 3,017 2,702 Change 0 0 0 1 1 1 2 41 FE Capacity (MW) 592 592 593 1,776 605 1,352 1,719 2,101 GPU Capacity (MW) 0 0 0 1 1 1 2 24 Merged Capacity (MW) 592 592 593 1,776 605 1,353 1,720 2,125 FE Market Share 17.5% 17.5% 18.7% 37.7% 19.5% 27.6% 30.8% 42.7% GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.5%
SPRING / FALL --------------------------------- Destination Market Super Peak Off-Peak ------------------------------ -------- ------- --------- APS Pre-Merger HHI 4,363 4,089 3,908 Post-Merger HHI 4,371 4,099 3,940 Change 9 11 32 FE Capacity (MW) 908 907 925 GPU Capacity (MW) 50 55 120 Merged Capacity (MW) 958 962 1,046 FE Market Share 8.8% 9.3% 11.1% GPU Market Share 0.5% 0.6% 1.4% Merged Market Share 9.3% 9.9% 12.6% DPL Pre-Merger HHI 4,710 3,243 2,615 Post-Merger HHI 4,710 3,244 2,620 Change 0 1 5 FE Capacity (MW) 239 415 460 GPU Capacity (MW) 1 2 10 Merged Capacity (MW) 240 417 469 FE Market Share 7.5% 10.4% 10.9% GPU Market Share 0.0% 0.0% 0.2% Merged Market Share 7.6% 10.5% 11.1% DQE Pre-Merger HHI 3,373 3,190 3,499 Post-Merger HHI 3,374 3,192 3,538 Change 1 2 39 FE Capacity (MW) 1,612 2,049 3,048 GPU Capacity (MW) 1 1 20 Merged Capacity (MW) 1,613 2,051 3,068 FE Market Share 36.6% 40.4% 54.8% GPU Market Share 0.0% 0.0% 0.4%
303 Exhibit APP-309, page 3 of 5 SENSITIVITY FOR FIRM ATC
SUMMER WINTER ---------------------------------------------------------- -------------------------------- Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak ------------------------------ --------- -------- ------- -------- ---------- ------- --------- ---------- Merged Market Share 17.6% 17.6% 18.7% 37.7% 19.5% 27.6% 30.9% 43.2% MECS Pre-Merger HHI 3,882 3,872 3,791 3,856 3,743 2,646 2,639 3,259 Post-Merger HHI 3,882 3,872 3,791 3,856 3,743 2,646 2,639 3,262 Change 0 0 0 0 1 0 1 3 FE Capacity (MW) 874 874 875 842 821 1,440 1,350 1,219 GPU Capacity (MW) 1 1 1 3 7 5 6 21 Merged Capacity (MW) 876 875 876 845 828 1,445 1,356 1,240 FE Market Share 4.3% 4.4% 5.4% 5.6% 6.1% 7.6% 7.8% 9.5% GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.1% 0.0% 0.0% 0.2% Merged Market Share 4.3% 4.4% 5.4% 5.6% 6.1% 7.7% 7.9% 9.6% NYPP Pre-Merger HHI 1,229 1,226 1,248 1,147 1,096 1,197 1,121 1,085 Post-Merger HHI 1,229 1,226 1,248 1,147 1,096 1,197 1,121 1,085 Change 0 0 0 0 0 0 0 0 FE Capacity (MW) 1 2 2 1 3 4 3 5 GPU Capacity (MW) 13 14 14 15 18 26 27 57 Merged Capacity (MW) 15 15 16 16 20 30 30 62 FE Market Share 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.1% GPU Market Share 0.0% 0.0% 0.0% 0.1% 0.2% 0.1% 0.1% 0.6% Merged Market Share 0.0% 0.0% 0.0% 0.1% 0.2% 0.1% 0.1% 0.6% VEPCO Pre-Merger HHI 4,568 4,516 3,963 3,562 3,172 3,565 3,206 2,293 Post-Merger HHI 4,569 4,516 3,964 3,563 3,173 3,566 3,207 2,303 Change 1 1 1 1 1 1 1 9 FE Capacity (MW) 126 126 129 129 92 109 112 208 GPU Capacity (MW) 99 101 106 112 137 140 140 312 Merged Capacity (MW) 225 227 235 241 229 249 253 520 FE Market Share 0.6% 0.6% 0.7% 0.8% 0.6% 0.6% 0.7% 1.8%
SPRING / FALL --------------------------------- Destination Market Super Peak Off-Peak ------------------------------ -------- ------- --------- Merged Market Share 36.6% 40.4% 55.2% MECS Pre-Merger HHI 2,385 2,374 2,848 Post-Merger HHI 2,386 2,376 2,858 Change 1 2 10 FE Capacity (MW) 2,057 1,928 1,736 GPU Capacity (MW) 7 9 36 Merged Capacity (MW) 2,064 1,938 1,772 FE Market Share 12.5% 13.0% 15.5% GPU Market Share 0.0% 0.1% 0.3% Merged Market Share 12.5% 13.1% 15.9% NYPP Pre-Merger HHI 1,086 1,059 935 Post-Merger HHI 1,086 1,059 936 Change 0 0 0 FE Capacity (MW) 9 9 14 GPU Capacity (MW) 70 76 158 Merged Capacity (MW) 79 85 172 FE Market Share 0.0% 0.0% 0.1% GPU Market Share 0.3% 0.4% 1.6% Merged Market Share 0.3% 0.5% 1.8% VEPCO Pre-Merger HHI 3,642 3,154 2,073 Post-Merger HHI 3,643 3,156 2,085 Change 1 2 12 FE Capacity (MW) 102 106 180 GPU Capacity (MW) 136 148 325 Merged Capacity (MW) 239 254 505 FE Market Share 0.7% 0.8% 1.8%
304 Exhibit APP-309, page 4 of 5 SENSITIVITY FOR FIRM ATC
SUMMER WINTER ---------------------------------------------------------- -------------------------------- Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak ------------------------------ --------- -------- ------- -------- ---------- ------- --------- ---------- GPU Market Share 0.5% 0.5% 0.6% 0.7% 0.9% 0.8% 0.9% 2.6% Merged Market Share 1.1% 1.1% 1.3% 1.5% 1.5% 1.5% 1.6% 4.4% PJM-WESTINT Pre-Merger HHI 1,165 1,164 1,183 1,178 1,146 1,038 1,136 1,559 Post-Merger HHI 1,175 1,174 1,190 1,182 1,155 1,057 1,144 1,579 Change 11 11 7 4 9 19 8 19 FE Capacity (MW) 665 665 378 150 269 757 294 175 GPU Capacity (MW) 2,415 2,415 2,043 1,926 1,911 2,171 1,991 1,971 Merged Capacity (MW) 3,079 3,079 2,421 2,076 2,180 2,929 2,285 2,146 FE Market Share 1.2% 1.2% 0.8% 0.4% 0.8% 1.8% 0.8% 0.9% GPU Market Share 4.4% 4.4% 4.5% 5.0% 5.7% 5.2% 5.4% 10.4% Merged Market Share 5.6% 5.6% 5.3% 5.3% 6.5% 7.0% 6.2% 11.3% PJM-CENTINT Pre-Merger HHI 1,523 1,523 1,570 1,473 1,504 1,406 1,508 1,608 Post-Merger HHI 1,528 1,528 1,574 1,475 1,510 1,417 1,514 1,627 Change 5 5 4 2 6 11 5 18 FE Capacity (MW) 186 186 117 51 102 256 110 160 GPU Capacity (MW) 2,175 2,175 1,814 1,713 1,711 1,929 1,764 1,940 Merged Capacity (MW) 2,362 2,362 1,931 1,764 1,813 2,185 1,874 2,101 FE Market Share 0.5% 0.5% 0.4% 0.2% 0.4% 0.9% 0.4% 0.9% GPU Market Share 5.4% 5.4% 5.5% 6.1% 7.0% 6.5% 6.6% 10.6% Merged Market Share 5.8% 5.8% 5.9% 6.3% 7.4% 7.4% 7.0% 11.4% PJM-EASTINT Pre-Merger HHI 1,503 1,495 1,438 1,390 1,375 1,286 1,361 1,713 Post-Merger HHI 1,510 1,502 1,443 1,393 1,383 1,302 1,368 1,731 Change 7 7 5 3 8 16 7 18 FE Capacity (MW) 187 188 119 52 98 232 102 124 GPU Capacity (MW) 1,862 1,862 1,515 1,427 1,438 1,607 1,461 1,737 Merged Capacity (MW) 2,049 2,050 1,633 1,479 1,537 1,839 1,563 1,861
SPRING / FALL --------------------------------- Destination Market Super Peak Off-Peak ------------------------------ -------- ------- --------- GPU Market Share 0.9% 1.1% 3.3% Merged Market Share 1.6% 1.9% 5.1% PJM-WESTINT Pre-Merger HHI 1,025 1,069 1,297 Post-Merger HHI 1,043 1,079 1,314 Change 18 10 17 FE Capacity (MW) 586 255 140 GPU Capacity (MW) 1,885 1,747 1,717 Merged Capacity (MW) 2,471 2,003 1,857 FE Market Share 1.7% 0.9% 0.8% GPU Market Share 5.3% 5.9% 10.3% Merged Market Share 7.0% 6.7% 11.1% PJM-CENTINT Pre-Merger HHI 1,353 1,390 1,440 Post-Merger HHI 1,364 1,397 1,456 Change 11 7 16 FE Capacity (MW) 207 105 104 GPU Capacity (MW) 1,644 1,531 1,625 Merged Capacity (MW) 1,851 1,636 1,730 FE Market Share 0.8% 0.5% 0.7% GPU Market Share 6.6% 7.1% 11.0% Merged Market Share 7.4% 7.6% 11.7% PJM-EASTINT Pre-Merger HHI 1,287 1,254 1,455 Post-Merger HHI 1,301 1,263 1,472 Change 14 9 16 FE Capacity (MW) 188 96 91 GPU Capacity (MW) 1,369 1,276 1,460 Merged Capacity (MW) 1,557 1,372 1,552
305 Exhibit APP-309, page 5 of 5 SENSITIVITY FOR FIRM ATC
SUMMER WINTER ---------------------------------------------------------- -------------------------------- Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak ------------------------------ --------- -------- ------- -------- ---------- ------- --------- ---------- FE Market Share 0.6% 0.6% 0.5% 0.2% 0.5% 1.1% 0.5% 0.8% GPU Market Share 5.7% 5.7% 5.8% 6.5% 7.5% 7.4% 7.1% 11.3% Merged Market Share 6.3% 6.3% 6.2% 6.7% 8.0% 8.4% 7.6% 12.1%
SPRING / FALL --------------------------------- Destination Market Super Peak Off-Peak ------------------------------ -------- ------- --------- FE Market Share 1.0% 0.6% 0.7% GPU Market Share 7.2% 7.6% 11.4% Merged Market Share 8.2% 8.2% 12.1%
306 EXHIBIT NO. APP-310 307 Exhibit APP-310, page 1 of 5 SENSITIVITY FOR GAS PRICE BASIS DIFFERENTIAL
SUMMER WINTER ---------------------------------------------------------- --------------------------------- Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak -------------------------------- --------- ---------- --------- --------- ---------- -------- --------- -------- FE Pre-Merger HHI 5,228 5,225 5,083 4,334 3,215 4,948 4,194 4,113 Post-Merger HHI 5,243 5,240 5,100 4,369 3,269 4,986 4,236 4,274 Change 15 15 16 36 54 38 42 161 FE Capacity (MW) 11,798 11,788 11,090 10,101 9,965 10,789 10,162 8,175 GPU Capacity (MW) 17 18 18 43 90 42 52 166 Merged Capacity (MW) 11,815 11,805 11,109 10,144 10,055 10,831 10,215 8,341 FE Market Share 71.6% 71.6% 70.5% 64.8% 54.5% 69.8% 63.9% 63.1% GPU Market Share 0.1% 0.1% 0.1% 0.3% 0.5% 0.3% 0.3% 1.3% Merged Market Share 71.7% 71.7% 70.6% 65.1% 55.0% 70.1% 64.2% 64.3% PJM Pre-Merger HHI 1,164 1,163 1,178 1,178 1,143 976 1,130 1,551 Post-Merger HHI 1,176 1,175 1,188 1,183 1,155 998 1,141 1,577 Change 12 12 10 5 12 22 11 26 FE Capacity (MW) 761 761 472 206 360 964 390 235 GPU Capacity (MW) 2,415 2,415 2,043 1,926 1,911 2,171 1,991 1,971 Merged Capacity (MW) 3,176 3,176 2,515 2,132 2,271 3,136 2,381 2,206 FE Market Share 1.4% 1.4% 1.1% 0.5% 1.1% 2.2% 1.0% 1.2% GPU Market Share 4.4% 4.4% 4.6% 5.0% 5.7% 5.0% 5.4% 10.4% Merged Market Share 5.8% 5.8% 5.6% 5.5% 6.7% 7.3% 6.4% 11.7% AEP Pre-Merger HHI 2,434 2,433 2,388 2,464 3,817 2,243 2,131 2,586 Post-Merger HHI 2,434 2,434 2,389 2,464 3,817 2,243 2,131 2,593 Change 1 1 1 1 1 0 1 7 FE Capacity (MW) 3,012 3,011 3,019 2,968 1,664 1,613 1,694 1,591 GPU Capacity (MW) 18 18 21 25 28 26 46 354 Merged Capacity (MW) 3,029 3,030 3,040 2,993 1,692 1,639 1,740 1,945 FE Market Share 6.6% 6.6% 6.7% 6.7% 4.8% 3.4% 3.5% 3.9% GPU Market Share 0.0% 0.0% 0.0% 0.1% 0.1% 0.1% 0.1% 0.9% Merged Market Share 6.6% 6.6% 6.7% 6.8% 4.9% 3.5% 3.6% 4.8%
SPRING / FALL --------------------------------- Destination Market Super Peak Off-Peak -------------------------------- --------- ------- -------- FE Pre-Merger HHI 4,262 3,519 3,028 Post-Merger HHI 4,298 3,562 3,206 Change 35 43 178 FE Capacity (MW) 8,360 7,847 4,973 GPU Capacity (MW) 35 51 158 Merged Capacity (MW) 8,395 7,898 5,131 FE Market Share 64.3% 57.9% 53.0% GPU Market Share 0.3% 0.4% 1.7% Merged Market Share 64.6% 58.3% 54.6% PJM Pre-Merger HHI 940 1,059 1,288 Post-Merger HHI 967 1,077 1,320 Change 27 18 32 FE Capacity (MW) 979 460 262 GPU Capacity (MW) 1,885 1,747 1,717 Merged Capacity (MW) 2,864 2,207 1,979 FE Market Share 2.6% 1.5% 1.6% GPU Market Share 5.1% 5.9% 10.3% Merged Market Share 7.7% 7.4% 11.8% AEP Pre-Merger HHI 1,817 1,693 2,066 Post-Merger HHI 1,818 1,694 2,079 Change 1 1 13 FE Capacity (MW) 2,436 2,558 2,403 GPU Capacity (MW) 26 47 363 Merged Capacity (MW) 2,463 2,605 2,766 FE Market Share 5.7% 5.9% 6.6% GPU Market Share 0.1% 0.1% 1.0% Merged Market Share 5.8% 6.0% 7.6%
308 Exhibit APP-310, page 2 of 5 SENSITIVITY FOR GAS PRICE BASIS DIFFERENTIAL
SUMMER WINTER ---------------------------------------------------------- --------------------------------- Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak -------------------------------- --------- ---------- --------- --------- ---------- -------- --------- -------- APS Pre-Merger HHI 4,150 4,126 3,884 3,298 3,607 4,551 2,482 2,644 Post-Merger HHI 4,153 4,129 3,888 3,303 3,612 4,555 2,493 2,668 Change 3 3 3 5 5 4 11 24 FE Capacity (MW) 311 311 311 414 362 334 807 640 GPU Capacity (MW) 84 85 89 101 110 91 166 312 Merged Capacity (MW) 394 396 400 516 472 425 973 952 FE Market Share 2.3% 2.3% 2.5% 3.2% 3.0% 2.7% 5.1% 4.9% GPU Market Share 0.6% 0.6% 0.7% 0.8% 0.9% 0.7% 1.0% 2.4% Merged Market Share 3.0% 3.0% 3.2% 4.0% 3.9% 3.4% 6.1% 7.3% DPL Pre-Merger HHI 7,115 7,101 6,895 5,475 3,907 5,308 3,766 2,963 Post-Merger HHI 7,115 7,101 6,895 5,476 3,909 5,308 3,767 2,967 Change 0 0 0 0 1 0 1 4 FE Capacity (MW) 137 137 137 211 351 234 408 475 GPU Capacity (MW) 0 0 0 1 3 1 2 8 Merged Capacity (MW) 137 137 137 212 354 235 410 484 FE Market Share 3.5% 3.5% 3.9% 5.8% 7.8% 6.3% 9.0% 10.0% GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.1% 0.0% 0.0% 0.2% Merged Market Share 3.5% 3.6% 3.9% 5.8% 7.9% 6.3% 9.0% 10.2% DQE Pre-Merger HHI 6,207 6,207 6,029 3,964 5,902 3,369 3,018 2,676 Post-Merger HHI 6,208 6,207 6,030 3,966 5,903 3,371 3,022 2,747 Change 0 0 0 2 1 2 4 70 FE Capacity (MW) 591 591 592 1,774 604 1,348 1,714 2,101 GPU Capacity (MW) 0 0 0 1 1 2 4 41 Merged Capacity (MW) 591 591 593 1,775 605 1,350 1,718 2,142 FE Market Share 17.5% 17.5% 18.7% 37.6% 19.4% 27.5% 30.7% 42.6% GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.1% 0.8%
SPRING / FALL --------------------------------- Destination Market Super Peak Off-Peak -------------------------------- --------- ------- -------- APS Pre-Merger HHI 3,958 2,049 2,189 Post-Merger HHI 3,962 2,060 2,215 Change 4 12 26 FE Capacity (MW) 305 732 582 GPU Capacity (MW) 83 165 308 Merged Capacity (MW) 388 897 890 FE Market Share 2.8% 5.1% 5.0% GPU Market Share 0.8% 1.1% 2.6% Merged Market Share 3.6% 6.2% 7.6% DPL Pre-Merger HHI 4,712 3,243 2,618 Post-Merger HHI 4,713 3,245 2,623 Change 0 1 6 FE Capacity (MW) 228 397 457 GPU Capacity (MW) 1 2 11 Merged Capacity (MW) 229 399 468 FE Market Share 7.2% 10.0% 10.8% GPU Market Share 0.0% 0.1% 0.3% Merged Market Share 7.2% 10.0% 11.1% DQE Pre-Merger HHI 3,354 3,169 3,461 Post-Merger HHI 3,357 3,174 3,546 Change 3 6 85 FE Capacity (MW) 1,597 2,031 3,021 GPU Capacity (MW) 2 4 44 Merged Capacity (MW) 1,599 2,034 3,064 FE Market Share 36.2% 40.0% 54.3% GPU Market Share 0.0% 0.1% 0.8%
309 Exhibit APP-310, page 3 of 5 SENSITIVITY FOR GAS PRICE BASIS DIFFERENTIAL
SUMMER WINTER ---------------------------------------------------------- --------------------------------- Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak -------------------------------- --------- ---------- --------- --------- ---------- -------- --------- -------- Merged Market Share 17.5% 17.5% 18.7% 37.7% 19.5% 27.5% 30.8% 43.4% MECS Pre-Merger HHI 3,448 3,437 3,290 3,854 2,878 2,643 2,636 3,267 Post-Merger HHI 3,448 3,437 3,290 3,855 2,879 2,643 2,636 3,270 Change 0 0 0 0 1 0 0 2 FE Capacity (MW) 964 963 964 541 1,143 1,184 1,114 1,006 GPU Capacity (MW) 1 1 2 2 11 5 5 18 Merged Capacity (MW) 965 965 965 543 1,154 1,188 1,119 1,024 FE Market Share 4.5% 4.5% 5.5% 3.6% 7.2% 6.3% 6.5% 7.8% GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.1% 0.0% 0.0% 0.1% Merged Market Share 4.5% 4.5% 5.5% 3.6% 7.3% 6.3% 6.5% 7.9% NYPP Pre-Merger HHI 1,166 1,155 1,159 1,064 939 1,161 1,083 1,017 Post-Merger HHI 1,166 1,155 1,159 1,064 940 1,161 1,083 1,017 Change 0 0 0 0 0 0 0 0 FE Capacity (MW) 10 11 13 8 18 13 8 13 GPU Capacity (MW) 62 63 65 70 83 48 48 106 Merged Capacity (MW) 72 74 78 78 101 60 57 119 FE Market Share 0.0% 0.0% 0.0% 0.0% 0.1% 0.1% 0.0% 0.1% GPU Market Share 0.2% 0.2% 0.2% 0.3% 0.6% 0.2% 0.2% 1.0% Merged Market Share 0.2% 0.2% 0.2% 0.3% 0.8% 0.3% 0.3% 1.1% VEPCO Pre-Merger HHI 4,005 3,954 3,411 3,054 2,711 3,099 2,768 1,979 Post-Merger HHI 4,005 3,954 3,412 3,055 2,712 3,100 2,769 1,986 Change 1 1 1 1 1 1 1 7 FE Capacity (MW) 176 176 179 180 128 104 107 207 GPU Capacity (MW) 99 101 105 111 136 141 140 308 Merged Capacity (MW) 275 277 284 292 264 245 247 515 FE Market Share 0.8% 0.8% 0.9% 1.0% 0.8% 0.6% 0.6% 1.6%
SPRING / FALL --------------------------------- Destination Market Super Peak Off-Peak -------------------------------- --------- ------- -------- Merged Market Share 36.3% 40.1% 55.1% MECS Pre-Merger HHI 2,363 2,351 2,816 Post-Merger HHI 2,364 2,352 2,824 Change 1 1 7 FE Capacity (MW) 1,633 1,531 1,368 GPU Capacity (MW) 7 9 33 Merged Capacity (MW) 1,640 1,540 1,401 FE Market Share 9.9% 10.3% 12.2% GPU Market Share 0.0% 0.1% 0.3% Merged Market Share 10.0% 10.4% 12.5% NYPP Pre-Merger HHI 1,001 956 807 Post-Merger HHI 1,001 956 810 Change 0 0 3 FE Capacity (MW) 48 34 54 GPU Capacity (MW) 131 148 320 Merged Capacity (MW) 179 182 374 FE Market Share 0.2% 0.2% 0.5% GPU Market Share 0.5% 0.7% 2.9% Merged Market Share 0.7% 0.9% 3.4% VEPCO Pre-Merger HHI 3,067 2,626 1,734 Post-Merger HHI 3,069 2,628 1,746 Change 1 2 12 FE Capacity (MW) 148 153 254 GPU Capacity (MW) 132 145 316 Merged Capacity (MW) 280 298 570 FE Market Share 0.9% 1.0% 2.2%
310 Exhibit APP-310, page 4 of 5 SENSITIVITY FOR GAS PRICE BASIS DIFFERENTIAL
SUMMER WINTER ---------------------------------------------------------- --------------------------------- Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak -------------------------------- --------- ---------- --------- --------- ---------- -------- --------- -------- GPU Market Share 0.4% 0.5% 0.5% 0.6% 0.8% 0.8% 0.8% 2.3% Merged Market Share 1.2% 1.2% 1.4% 1.6% 1.6% 1.3% 1.5% 3.9% PJM-WESTINT Pre-Merger HHI 1,164 1,163 1,178 1,178 1,143 976 1,130 1,551 Post-Merger HHI 1,176 1,175 1,188 1,183 1,155 998 1,141 1,577 Change 12 12 10 5 12 22 11 26 FE Capacity (MW) 761 761 472 206 360 964 390 235 GPU Capacity (MW) 2,415 2,415 2,043 1,926 1,911 2,171 1,991 1,971 Merged Capacity (MW) 3,176 3,176 2,515 2,132 2,271 3,136 2,381 2,206 FE Market Share 1.4% 1.4% 1.1% 0.5% 1.1% 2.2% 1.0% 1.2% GPU Market Share 4.4% 4.4% 4.6% 5.0% 5.7% 5.0% 5.4% 10.4% Merged Market Share 5.8% 5.8% 5.6% 5.5% 6.7% 7.3% 6.4% 11.7% PJM-CENTINT Pre-Merger HHI 1,508 1,507 1,547 1,462 1,479 1,312 1,455 1,564 Post-Merger HHI 1,513 1,513 1,552 1,465 1,487 1,325 1,462 1,589 Change 6 6 5 3 8 13 7 26 FE Capacity (MW) 216 216 149 71 139 320 151 229 GPU Capacity (MW) 2,177 2,177 1,815 1,714 1,713 1,926 1,769 1,962 Merged Capacity (MW) 2,392 2,392 1,964 1,785 1,852 2,246 1,920 2,191 FE Market Share 0.5% 0.5% 0.5% 0.3% 0.6% 1.0% 0.6% 1.2% GPU Market Share 5.3% 5.4% 5.6% 6.1% 6.9% 6.3% 6.5% 10.5% Merged Market Share 5.9% 5.9% 6.0% 6.4% 7.5% 7.3% 7.0% 11.7% PJM-EASTINT Pre-Merger HHI 1,485 1,477 1,400 1,378 1,350 1,171 1,306 1,667 Post-Merger HHI 1,493 1,484 1,407 1,382 1,360 1,189 1,315 1,691 Change 7 7 7 4 10 18 9 24 FE Capacity (MW) 216 217 150 71 133 292 138 172 GPU Capacity (MW) 1,863 1,864 1,517 1,429 1,441 1,604 1,468 1,757 Merged Capacity (MW) 2,079 2,081 1,667 1,500 1,574 1,896 1,606 1,929
SPRING / FALL --------------------------------- Destination Market Super Peak Off-Peak -------------------------------- --------- ------- -------- GPU Market Share 0.8% 1.0% 2.7% Merged Market Share 1.7% 2.0% 5.0% PJM-WESTINT Pre-Merger HHI 945 1,059 1,288 Post-Merger HHI 971 1,077 1,320 Change 26 18 32 FE Capacity (MW) 955 460 262 GPU Capacity (MW) 1,885 1,747 1,717 Merged Capacity (MW) 2,841 2,207 1,979 FE Market Share 2.6% 1.5% 1.6% GPU Market Share 5.1% 5.9% 10.3% Merged Market Share 7.7% 7.4% 11.8% PJM-CENTINT Pre-Merger HHI 1,295 1,365 1,417 Post-Merger HHI 1,311 1,378 1,446 Change 16 13 29 FE Capacity (MW) 317 192 199 GPU Capacity (MW) 1,633 1,533 1,631 Merged Capacity (MW) 1,950 1,725 1,830 FE Market Share 1.3% 0.9% 1.3% GPU Market Share 6.5% 7.1% 10.9% Merged Market Share 7.7% 8.0% 12.2% PJM-EASTINT Pre-Merger HHI 1,205 1,228 1,432 Post-Merger HHI 1,226 1,243 1,463 Change 21 15 30 FE Capacity (MW) 296 174 173 GPU Capacity (MW) 1,355 1,279 1,467 Merged Capacity (MW) 1,651 1,454 1,640
311 Exhibit APP-310, page 5 of 5 SENSITIVITY FOR GAS PRICE BASIS DIFFERENTIAL
SUMMER WINTER ---------------------------------------------------------- --------------------------------- Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak -------------------------------- --------- ---------- --------- --------- ---------- -------- --------- -------- FE Market Share 0.7% 0.7% 0.6% 0.3% 0.7% 1.3% 0.7% 1.1% GPU Market Share 5.7% 5.7% 5.9% 6.4% 7.4% 7.0% 7.0% 11.1% Merged Market Share 6.3% 6.3% 6.4% 6.8% 8.1% 8.3% 7.6% 12.2%
SPRING / FALL --------------------------------- Destination Market Super Peak Off-Peak -------------------------------- --------- ------- -------- FE Market Share 1.5% 1.0% 1.3% GPU Market Share 7.0% 7.5% 11.3% Merged Market Share 8.5% 8.6% 12.7%
312 EXHIBIT NO. APP-311 313 Exhibit APP-311, page 1 of 5 SENSITIVITY FOR ALLIANCE TRANSMISSION PRICES
SUMMER WINTER SPRING / FALL ---------------------------------------------- ------------------------ ------------------------ Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak ------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- -------- FE Pre-Merger HHI 5,228 5,225 5,083 4,334 3,214 4,948 4,194 4,134 4,262 3,519 3,048 Post-Merger HHI 5,243 5,240 5,100 4,370 3,271 4,986 4,236 4,277 4,298 3,562 3,203 Change 15 15 17 37 57 38 42 143 36 43 156 FE Capacity (MW) 11,798 11,788 11,090 10,101 9,965 10,789 10,162 8,175 8,360 7,847 4,973 GPU Capacity (MW) 17 18 18 44 96 42 52 147 37 51 138 Merged Capacity (MW) 11,815 11,805 11,109 10,145 10,061 10,831 10,215 8,322 8,396 7,898 5,111 FE Market Share 71.6% 71.6% 70.5% 64.8% 54.5% 69.8% 63.9% 63.1% 64.3% 57.9% 53.0% GPU Market Share 0.1% 0.1% 0.1% 0.3% 0.5% 0.3% 0.3% 1.1% 0.3% 0.4% 1.5% Merged Market Share 71.7% 71.7% 70.6% 65.1% 55.0% 70.1% 64.2% 64.2% 64.6% 58.3% 54.4% PJM Pre-Merger HHI 1,164 1,163 1,181 1,178 1,143 976 1,130 1,550 940 1,059 1,288 Post-Merger HHI 1,176 1,175 1,190 1,183 1,155 998 1,141 1,571 966 1,077 1,314 Change 12 12 9 5 12 22 11 21 27 18 26 FE Capacity (MW) 761 761 469 206 351 964 389 188 979 459 212 GPU Capacity (MW) 2,415 2,415 2,043 1,926 1,911 2,171 1,991 1,971 1,885 1,747 1,717 Merged Capacity (MW) 3,176 3,175 2,512 2,132 2,262 3,136 2,381 2,159 2,864 2,207 1,929 FE Market Share 1.4% 1.4% 1.0% 0.5% 1.0% 2.2% 1.0% 1.0% 2.6% 1.5% 1.3% GPU Market Share 4.4% 4.4% 4.5% 5.0% 5.7% 5.0% 5.4% 10.4% 5.1% 5.9% 10.3% Merged Market Share 5.8% 5.8% 5.5% 5.5% 6.7% 7.3% 6.4% 11.4% 7.7% 7.4% 11.5% AEP Pre-Merger HHI 2,434 2,433 2,385 2,464 3,816 2,243 2,131 2,561 1,817 1,693 2,074 Post-Merger HHI 2,434 2,434 2,386 2,464 3,817 2,243 2,131 2,564 1,817 1,694 2,078 Change 1 1 1 1 1 0 1 3 1 1 4 FE Capacity (MW) 3,012 3,011 3,020 2,968 1,664 1,613 1,694 1,563 2,437 2,558 2,346 GPU Capacity (MW) 18 18 21 25 20 26 46 137 26 47 126 Merged Capacity (MW) 3,029 3,030 3,041 2,993 1,684 1,639 1,740 1,700 2,463 2,605 2,472 FE Market Share 6.6% 6.6% 6.7% 6.7% 4.8% 3.4% 3.5% 3.8% 5.7% 5.9% 6.5% GPU Market Share 0.0% 0.0% 0.0% 0.1% 0.1% 0.1% 0.1% 0.3% 0.1% 0.1% 0.3% Merged Market Share 6.6% 6.6% 6.7% 6.8% 4.9% 3.5% 3.6% 4.1% 5.8% 6.0% 6.8%
314 Exhibit APP-311, page 2 of 5 SENSITIVITY FOR ALLIANCE TRANSMISSION PRICES
SUMMER WINTER SPRING / FALL ---------------------------------------------- ------------------------ ------------------------ Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak ------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- -------- APS Pre-Merger HHI 4,150 4,126 3,886 3,298 3,606 4,550 2,482 2,604 3,956 2,049 2,141 Post-Merger HHI 4,153 4,129 3,889 3,303 3,611 4,554 2,493 2,628 3,961 2,060 2,168 Change 3 3 3 5 5 4 11 24 4 12 26 FE Capacity (MW) 311 311 311 414 362 334 807 640 305 732 582 GPU Capacity (MW) 84 85 89 101 110 89 166 312 83 165 308 Merged Capacity (MW) 394 396 400 516 472 423 973 952 388 897 890 FE Market Share 2.3% 2.3% 2.5% 3.2% 3.0% 2.7% 5.1% 4.9% 2.8% 5.1% 5.0% GPU Market Share 0.6% 0.6% 0.7% 0.8% 0.9% 0.7% 1.0% 2.4% 0.8% 1.1% 2.6% Merged Market Share 3.0% 3.0% 3.2% 4.0% 3.9% 3.4% 6.1% 7.3% 3.6% 6.2% 7.6% DPL Pre-Merger HHI 7,115 7,092 6,817 5,475 3,907 5,308 3,766 2,870 4,712 3,243 2,542 Post-Merger HHI 7,115 7,092 6,817 5,476 3,908 5,308 3,767 2,881 4,713 3,245 2,558 Change 0 0 0 0 2 0 1 10 0 1 16 FE Capacity (MW) 137 137 137 211 349 234 408 438 228 397 412 GPU Capacity (MW) 0 0 0 1 5 1 2 26 1 2 35 Merged Capacity (MW) 137 137 137 212 354 235 410 464 229 399 447 FE Market Share 3.5% 3.6% 3.9% 5.8% 7.7% 6.3% 9.0% 9.2% 7.2% 10.0% 9.7% GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.1% 0.0% 0.0% 0.6% 0.0% 0.1% 0.8% Merged Market Share 3.5% 3.6% 3.9% 5.8% 7.9% 6.3% 9.0% 9.8% 7.2% 10.0% 10.5% DQE Pre-Merger HHI 6,207 6,207 6,029 3,964 5,902 3,369 3,018 2,572 3,355 3,169 2,711 Post-Merger HHI 6,208 6,208 6,029 3,967 5,904 3,371 3,022 2,642 3,357 3,174 2,796 Change 0 0 0 2 1 2 4 70 3 6 85 FE Capacity (MW) 591 591 592 1,774 604 1,348 1,714 2,101 1,597 2,031 2,115 GPU Capacity (MW) 0 0 0 1 1 2 4 41 2 4 44 Merged Capacity (MW) 591 591 592 1,775 605 1,350 1,718 2,142 1,599 2,034 2,159 FE Market Share 17.5% 17.5% 18.6% 37.6% 19.4% 27.5% 30.7% 42.6% 36.2% 40.0% 45.4% GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.1% 0.8% 0.0% 0.1% 0.9% Merged Market Share 17.5% 17.5% 18.7% 37.7% 19.5% 27.5% 30.8% 43.4% 36.3% 40.1% 46.4%
315 Exhibit APP-311, page 3 of 5 SENSITIVITY FOR ALLIANCE TRANSMISSION PRICES
SUMMER WINTER SPRING / FALL ---------------------------------------------- ------------------------ ------------------------ Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak ------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- -------- MECS Pre-Merger HHI 3,448 3,437 3,290 3,854 2,878 2,643 2,636 3,249 2,363 2,351 2,789 Post-Merger HHI 3,448 3,437 3,290 3,855 2,879 2,643 2,636 3,251 2,364 2,352 2,796 Change 0 0 0 0 1 0 0 2 1 1 7 FE Capacity (MW) 964 963 964 541 1,144 1,184 1,114 1,023 1,634 1,531 1,350 GPU Capacity (MW) 1 1 1 2 11 5 5 13 7 9 31 Merged Capacity (MW) 965 965 966 543 1,154 1,188 1,119 1,037 1,641 1,540 1,381 FE Market Share 4.5% 4.5% 5.5% 3.6% 7.2% 6.3% 6.5% 7.9% 9.9% 10.3% 12.1% GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.1% 0.0% 0.0% 0.1% 0.0% 0.1% 0.3% Merged Market Share 4.5% 4.5% 5.5% 3.6% 7.3% 6.3% 6.5% 8.0% 10.0% 10.4% 12.4% NYPP Pre-Merger HHI 1,166 1,157 1,173 1,064 939 1,161 1,083 1,017 1,001 956 807 Post-Merger HHI 1,166 1,158 1,173 1,064 940 1,161 1,083 1,017 1,001 956 810 Change 0 0 0 0 0 0 0 0 0 0 3 FE Capacity (MW) 10 11 13 8 18 13 8 13 48 34 54 GPU Capacity (MW) 62 63 65 70 83 47 48 106 131 148 320 Merged Capacity (MW) 72 74 78 78 101 59 57 119 179 182 374 FE Market Share 0.0% 0.0% 0.0% 0.0% 0.1% 0.1% 0.0% 0.1% 0.2% 0.2% 0.5% GPU Market Share 0.2% 0.2% 0.2% 0.3% 0.6% 0.2% 0.2% 1.0% 0.5% 0.7% 2.9% Merged Market Share 0.2% 0.2% 0.2% 0.3% 0.8% 0.3% 0.3% 1.1% 0.7% 0.9% 3.4% VEPCO Pre-Merger HHI 4,005 3,954 3,428 3,053 2,714 3,099 2,768 1,957 3,067 2,626 1,712 Post-Merger HHI 4,005 3,954 3,429 3,055 2,716 3,100 2,769 1,961 3,068 2,628 1,721 Change 1 1 1 1 1 1 1 4 1 2 9 FE Capacity (MW) 176 176 179 180 126 104 107 120 148 153 178 GPU Capacity (MW) 99 101 106 116 153 141 140 308 137 145 335 Merged Capacity (MW) 275 277 285 297 279 245 247 428 285 298 513 FE Market Share 0.8% 0.8% 0.9% 1.0% 0.8% 0.6% 0.6% 0.9% 0.9% 1.0% 1.5% GPU Market Share 0.4% 0.5% 0.5% 0.6% 0.9% 0.8% 0.8% 2.3% 0.8% 1.0% 2.9% Merged Market Share 1.2% 1.3% 1.4% 1.6% 1.7% 1.3% 1.5% 3.2% 1.7% 2.0% 4.5%
316 Exhibit APP-311, page 4 of 5 SENSITIVITY FOR ALLIANCE TRANSMISSION PRICES
SUMMER WINTER SPRING / FALL ---------------------------------------------- ------------------------ ------------------------ Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak ------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- -------- PJM-WESTINT Pre-Merger HHI 1,164 1,163 1,181 1,178 1,143 976 1,130 1,550 944 1,059 1,288 Post-Merger HHI 1,176 1,175 1,190 1,183 1,155 998 1,141 1,571 970 1,077 1,314 Change 12 12 9 5 12 22 11 21 26 18 26 FE Capacity (MW) 761 761 469 206 351 964 389 188 955 459 212 GPU Capacity (MW) 2,415 2,415 2,043 1,926 1,911 2,171 1,991 1,971 1,885 1,747 1,717 Merged Capacity (MW) 3,176 3,175 2,512 2,132 2,262 3,136 2,381 2,159 2,841 2,207 1,929 FE Market Share 1.4% 1.4% 1.0% 0.5% 1.0% 2.2% 1.0% 1.0% 2.6% 1.5% 1.3% GPU Market Share 4.4% 4.4% 4.5% 5.0% 5.7% 5.0% 5.4% 10.4% 5.1% 5.9% 10.3% Merged Market Share 5.8% 5.8% 5.5% 5.5% 6.7% 7.3% 6.4% 11.4% 7.7% 7.4% 11.5% PJM-CENTINT Pre-Merger HHI 1,508 1,507 1,550 1,462 1,479 1,312 1,455 1,564 1,295 1,365 1,417 Post-Merger HHI 1,513 1,513 1,555 1,465 1,487 1,325 1,462 1,584 1,311 1,378 1,440 Change 6 6 5 3 8 13 7 20 16 13 24 FE Capacity (MW) 216 216 148 71 135 320 151 183 317 192 161 GPU Capacity (MW) 2,177 2,177 1,815 1,714 1,713 1,926 1,769 1,962 1,633 1,533 1,631 Merged Capacity (MW) 2,392 2,392 1,963 1,785 1,848 2,246 1,920 2,145 1,950 1,725 1,792 FE Market Share 0.5% 0.5% 0.4% 0.3% 0.5% 1.0% 0.6% 1.0% 1.3% 0.9% 1.1% GPU Market Share 5.3% 5.4% 5.5% 6.1% 6.9% 6.3% 6.5% 10.5% 6.5% 7.1% 10.9% Merged Market Share 5.9% 5.9% 5.9% 6.4% 7.5% 7.3% 7.0% 11.4% 7.7% 8.0% 12.0% PJM-EASTINT Pre-Merger HHI 1,485 1,477 1,417 1,378 1,350 1,171 1,306 1,667 1,205 1,228 1,432 Post-Merger HHI 1,493 1,484 1,424 1,382 1,360 1,189 1,315 1,686 1,226 1,243 1,456 Change 7 7 6 4 10 18 9 19 21 15 25 FE Capacity (MW) 216 217 148 71 130 292 138 137 296 174 140 GPU Capacity (MW) 1,863 1,864 1,517 1,429 1,441 1,604 1,468 1,757 1,355 1,279 1,467 Merged Capacity (MW) 2,079 2,080 1,665 1,500 1,571 1,896 1,606 1,894 1,651 1,454 1,607
317 Exhibit APP-311, page 5 of 5 SENSITIVITY FOR ALLIANCE TRANSMISSION PRICES
SUMMER WINTER SPRING / FALL ---------------------------------------------- ------------------------ ------------------------ Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak ------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- -------- FE Market Share 0.7% 0.7% 0.6% 0.3% 0.7% 1.3% 0.7% 0.9% 1.5% 1.0% 1.1% GPU Market Share 5.7% 5.7% 5.7% 6.4% 7.4% 7.0% 7.0% 11.1% 7.0% 7.5% 11.3% Merged Market Share 6.3% 6.3% 6.3% 6.8% 8.1% 8.3% 7.6% 12.0% 8.5% 8.6% 12.4%
318 EXHIBIT NO. APP-312 319 Exhibit APP-312, page 1 of 5 SENSITIVITY FOR ZERO TRANSMISSION PRICE
SUMMER WINTER SPRING / FALL ---------------------------------------------- ------------------------ ------------------------ Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak ------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- -------- FE Pre-Merger HHI 5,228 5,225 5,083 4,334 3,213 4,948 4,194 3,823 4,262 3,519 2,608 Post-Merger HHI 5,243 5,240 5,099 4,369 3,260 4,985 4,236 3,909 4,297 3,562 2,698 Change 15 15 16 35 47 37 42 86 35 43 90 FE Capacity (MW) 11,798 11,788 11,090 10,101 9,965 10,789 10,162 8,175 8,360 7,847 4,973 GPU Capacity (MW) 17 17 18 42 79 41 52 96 35 51 95 Merged Capacity (MW) 11,815 11,805 11,108 10,143 10,044 10,830 10,215 8,271 8,395 7,898 5,069 FE Market Share 71.6% 71.6% 70.5% 64.8% 54.5% 69.8% 63.9% 60.6% 64.3% 57.9% 48.3% GPU Market Share 0.1% 0.1% 0.1% 0.3% 0.4% 0.3% 0.3% 0.7% 0.3% 0.4% 0.9% Merged Market Share 71.7% 71.7% 70.6% 65.1% 54.9% 70.0% 64.2% 61.3% 64.6% 58.3% 49.3% PJM Pre-Merger HHI 1,164 1,163 1,181 1,178 1,143 976 1,130 1,553 940 1,059 1,292 Post-Merger HHI 1,176 1,175 1,190 1,183 1,155 998 1,141 1,581 967 1,077 1,326 Change 12 12 9 5 12 22 11 28 27 18 33 FE Capacity (MW) 761 761 472 206 354 964 389 251 979 459 273 GPU Capacity (MW) 2,415 2,415 2,043 1,926 1,911 2,171 1,991 1,971 1,885 1,747 1,717 Merged Capacity (MW) 3,176 3,176 2,515 2,132 2,265 3,136 2,381 2,222 2,864 2,207 1,990 FE Market Share 1.4% 1.4% 1.0% 0.5% 1.0% 2.2% 1.0% 1.3% 2.6% 1.5% 1.6% GPU Market Share 4.4% 4.4% 4.5% 5.0% 5.7% 5.0% 5.4% 10.4% 5.1% 5.9% 10.3% Merged Market Share 5.8% 5.8% 5.5% 5.5% 6.7% 7.3% 6.4% 11.7% 7.7% 7.4% 11.9% AEP Pre-Merger HHI 2,434 2,433 2,385 2,464 3,815 2,243 2,131 2,182 1,817 1,693 1,730 Post-Merger HHI 2,434 2,434 2,386 2,464 3,816 2,243 2,131 2,183 1,817 1,694 1,733 Change 1 1 1 1 0 0 1 1 1 1 3 FE Capacity (MW) 3,012 3,011 3,020 2,968 1,664 1,613 1,694 1,563 2,437 2,558 2,346 GPU Capacity (MW) 18 18 20 24 15 25 46 87 25 47 95 Merged Capacity (MW) 3,029 3,029 3,040 2,992 1,679 1,639 1,740 1,650 2,461 2,605 2,441 FE Market Share 6.6% 6.6% 6.7% 6.7% 4.8% 3.4% 3.5% 3.5% 5.7% 5.9% 5.8% GPU Market Share 0.0% 0.0% 0.0% 0.1% 0.0% 0.1% 0.1% 0.2% 0.1% 0.1% 0.2% Merged Market Share 6.6% 6.6% 6.7% 6.8% 4.9% 3.5% 3.6% 3.7% 5.8% 6.0% 6.1%
320 Exhibit APP-312, page 2 of 5 SENSITIVITY FOR ZERO TRANSMISSION PRICE
SUMMER WINTER SPRING / FALL ---------------------------------------------- ------------------------ ------------------------ Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak ------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- -------- APS Pre-Merger HHI 4,150 4,126 3,886 3,299 3,607 4,550 2,482 2,531 3,957 2,052 2,064 Post-Merger HHI 4,153 4,129 3,889 3,304 3,613 4,554 2,493 2,551 3,962 2,064 2,087 Change 3 3 3 5 5 4 11 20 4 12 23 FE Capacity (MW) 311 311 311 414 362 334 807 629 305 732 568 GPU Capacity (MW) 84 84 87 101 106 89 166 283 83 165 293 Merged Capacity (MW) 394 395 399 515 468 423 973 912 387 897 861 FE Market Share 2.3% 2.3% 2.5% 3.2% 3.0% 2.7% 5.1% 4.7% 2.8% 5.1% 4.7% GPU Market Share 0.6% 0.6% 0.7% 0.8% 0.9% 0.7% 1.0% 2.1% 0.8% 1.1% 2.4% Merged Market Share 3.0% 3.0% 3.2% 4.0% 3.9% 3.4% 6.1% 6.9% 3.6% 6.2% 7.2% DPL Pre-Merger HHI 7,115 7,092 6,816 5,475 3,870 5,308 3,766 2,857 4,712 3,243 2,436 Post-Merger HHI 7,115 7,092 6,816 5,476 3,871 5,308 3,767 2,860 4,713 3,245 2,440 Change 0 0 0 0 1 0 1 2 0 1 5 FE Capacity (MW) 137 137 137 211 351 234 408 483 228 397 451 GPU Capacity (MW) 0 0 0 1 3 1 2 6 1 2 9 Merged Capacity (MW) 137 137 137 212 354 235 410 489 229 399 460 FE Market Share 3.5% 3.6% 3.9% 5.8% 7.8% 6.3% 9.0% 10.2% 7.2% 10.0% 10.7% GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.1% 0.0% 0.0% 0.1% 0.0% 0.1% 0.2% Merged Market Share 3.5% 3.6% 4.0% 5.8% 7.9% 6.3% 9.0% 10.3% 7.2% 10.0% 10.9% DQE Pre-Merger HHI 6,207 6,207 6,029 3,964 5,903 3,368 3,018 2,563 3,355 3,169 3,278 Post-Merger HHI 6,208 6,208 6,030 3,966 5,903 3,370 3,022 2,580 3,357 3,174 3,300 Change 0 0 0 2 1 2 4 17 3 6 22 FE Capacity (MW) 591 591 593 1,774 604 1,348 1,714 2,065 1,597 2,031 2,949 GPU Capacity (MW) 0 0 0 1 0 2 4 10 2 4 11 Merged Capacity (MW) 591 591 593 1,775 605 1,350 1,718 2,075 1,599 2,034 2,960 FE Market Share 17.5% 17.5% 18.7% 37.6% 19.4% 27.5% 30.7% 41.9% 36.2% 40.0% 53.0% GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.1% 0.2% 0.0% 0.1% 0.2% Merged Market Share 17.5% 17.5% 18.7% 37.7% 19.5% 27.5% 30.8% 42.1% 36.3% 40.1% 53.2%
321 Exhibit APP-312, page 3 of 5 SENSITIVITY FOR ZERO TRANSMISSION PRICE
SUMMER WINTER SPRING / FALL ---------------------------------------------- ------------------------ ------------------------ Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak ------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- -------- MECS Pre-Merger HHI 3,448 3,437 3,290 3,854 2,878 2,643 2,636 3,241 2,363 2,351 2,784 Post-Merger HHI 3,448 3,437 3,290 3,855 2,879 2,643 2,636 3,242 2,364 2,352 2,790 Change 0 0 0 0 1 0 0 1 1 1 6 FE Capacity (MW) 964 963 964 541 1,144 1,184 1,114 1,023 1,634 1,531 1,350 GPU Capacity (MW) 1 1 1 2 8 4 5 12 7 9 28 Merged Capacity (MW) 965 965 966 543 1,152 1,188 1,119 1,035 1,640 1,540 1,378 FE Market Share 4.5% 4.5% 5.5% 3.6% 7.2% 6.3% 6.5% 7.9% 9.9% 10.3% 12.1% GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.1% 0.0% 0.0% 0.1% 0.0% 0.1% 0.2% Merged Market Share 4.5% 4.5% 5.5% 3.6% 7.3% 6.3% 6.5% 8.0% 10.0% 10.4% 12.3% NYPP Pre-Merger HHI 1,166 1,157 1,173 1,064 883 1,161 1,083 945 1,001 956 761 Post-Merger HHI 1,166 1,157 1,173 1,064 883 1,161 1,083 945 1,001 956 764 Change 0 0 0 0 0 0 0 0 0 0 2 FE Capacity (MW) 10 10 13 8 17 13 8 12 48 34 49 GPU Capacity (MW) 62 63 64 70 80 47 48 95 131 148 296 Merged Capacity (MW) 72 73 77 78 97 59 57 107 178 182 345 FE Market Share 0.0% 0.0% 0.0% 0.0% 0.1% 0.1% 0.0% 0.1% 0.2% 0.2% 0.4% GPU Market Share 0.2% 0.2% 0.2% 0.3% 0.6% 0.2% 0.2% 0.9% 0.5% 0.7% 2.6% Merged Market Share 0.2% 0.2% 0.2% 0.3% 0.7% 0.3% 0.3% 1.0% 0.7% 0.9% 3.1% VEPCO Pre-Merger HHI 4,005 3,954 3,428 3,054 2,704 3,098 2,768 1,907 3,067 2,626 1,659 Post-Merger HHI 4,005 3,954 3,429 3,055 2,705 3,099 2,769 1,911 3,069 2,628 1,666 Change 1 1 1 1 1 1 1 3 1 2 7 FE Capacity (MW) 176 176 179 180 126 104 107 109 148 153 158 GPU Capacity (MW) 99 100 103 111 131 138 140 279 132 145 300 Merged Capacity (MW) 275 276 282 291 257 242 247 389 280 298 458 FE Market Share 0.8% 0.8% 0.9% 1.0% 0.8% 0.6% 0.6% 0.8% 0.9% 1.0% 1.4% GPU Market Share 0.4% 0.5% 0.5% 0.6% 0.8% 0.8% 0.8% 2.1% 0.8% 1.0% 2.6% Merged Market Share 1.2% 1.2% 1.4% 1.6% 1.5% 1.3% 1.5% 2.9% 1.7% 2.0% 4.0%
322 Exhibit APP-312, page 4 of 5 SENSITIVITY FOR ZERO TRANSMISSION PRICE
SUMMER WINTER SPRING / FALL ---------------------------------------------- ------------------------ ------------------------ Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak ------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- -------- PJM-WESTINT Pre-Merger HHI 1,164 1,163 1,181 1,178 1,143 976 1,130 1,553 944 1,059 1,292 Post-Merger HHI 1,176 1,175 1,190 1,183 1,155 998 1,141 1,581 971 1,077 1,326 Change 12 12 9 5 12 22 11 28 26 18 33 FE Capacity (MW) 761 761 472 206 354 964 389 251 956 459 273 GPU Capacity (MW) 2,415 2,415 2,043 1,926 1,911 2,171 1,991 1,971 1,885 1,747 1,717 Merged Capacity (MW) 3,176 3,176 2,515 2,132 2,265 3,136 2,381 2,222 2,841 2,207 1,990 FE Market Share 1.4% 1.4% 1.0% 0.5% 1.0% 2.2% 1.0% 1.3% 2.6% 1.5% 1.6% GPU Market Share 4.4% 4.4% 4.5% 5.0% 5.7% 5.0% 5.4% 10.4% 5.1% 5.9% 10.3% Merged Market Share 5.8% 5.8% 5.5% 5.5% 6.7% 7.3% 6.4% 11.7% 7.7% 7.4% 11.9% PJM-CENTINT Pre-Merger HHI 1,508 1,507 1,550 1,462 1,479 1,312 1,455 1,566 1,295 1,365 1,420 Post-Merger HHI 1,513 1,513 1,555 1,465 1,487 1,325 1,462 1,593 1,311 1,378 1,450 Change 6 6 5 3 8 13 7 27 16 13 30 FE Capacity (MW) 216 216 149 71 137 320 151 245 317 192 208 GPU Capacity (MW) 2,177 2,177 1,815 1,714 1,713 1,926 1,769 1,962 1,633 1,533 1,631 Merged Capacity (MW) 2,392 2,392 1,964 1,785 1,850 2,246 1,920 2,206 1,950 1,725 1,838 FE Market Share 0.5% 0.5% 0.4% 0.3% 0.6% 1.0% 0.6% 1.3% 1.3% 0.9% 1.4% GPU Market Share 5.3% 5.4% 5.5% 6.1% 6.9% 6.3% 6.5% 10.5% 6.5% 7.1% 10.9% Merged Market Share 5.9% 5.9% 5.9% 6.4% 7.5% 7.3% 7.0% 11.8% 7.7% 8.0% 12.3% PJM-EASTINT Pre-Merger HHI 1,485 1,477 1,417 1,378 1,350 1,171 1,306 1,668 1,205 1,228 1,435 Post-Merger HHI 1,493 1,484 1,424 1,382 1,360 1,188 1,315 1,694 1,226 1,243 1,467 Change 7 7 7 4 10 18 9 26 21 15 32 FE Capacity (MW) 216 217 150 71 131 292 138 183 296 174 180 GPU Capacity (MW) 1,863 1,864 1,517 1,429 1,441 1,604 1,468 1,757 1,355 1,279 1,467 Merged Capacity (MW) 2,079 2,081 1,667 1,500 1,572 1,896 1,606 1,941 1,651 1,454 1,647
323 Exhibit APP-312, page 5 of 5 SENSITIVITY FOR ZERO TRANSMISSION PRICE
SUMMER WINTER SPRING / FALL ---------------------------------------------- ------------------------ ------------------------ Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak ------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- -------- FE Market Share 0.7% 0.7% 0.6% 0.3% 0.7% 1.3% 0.7% 1.2% 1.5% 1.0% 1.4% GPU Market Share 5.7% 5.7% 5.7% 6.4% 7.4% 7.0% 7.0% 11.1% 7.0% 7.5% 11.3% Merged Market Share 6.3% 6.3% 6.3% 6.8% 8.1% 8.3% 7.6% 12.3% 8.5% 8.6% 12.7%
324 EXHIBIT NO. APP-313 325 Exhibit APP-313, page 1 of 5 SENSITIVITY FOR OFF-PEAK 650 MW SALE TO GPU
SUMMER WINTER SPRING / FALL ---------------------------------------------- ------------------------ ------------------------ Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak ------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- -------- FE Pre-Merger HHI 5,228 5,225 5,085 4,334 3,215 4,948 4,194 4,113 4,262 3,519 3,028 Post-Merger HHI 5,243 5,240 5,101 4,369 3,120 4,985 4,236 4,095 4,298 3,562 2,922 Change 15 15 16 36 (95) 37 42 (18) 35 43 (106) FE Capacity (MW) 11,798 11,788 11,090 10,101 9,965 10,789 10,162 8,175 8,360 7,847 4,973 GPU Capacity (MW) 17 18 18 43 90 41 52 166 35 51 158 Merged Capacity (MW) 11,815 11,805 11,108 10,144 9,465 10,830 10,215 7,766 8,395 7,898 4,559 FE Market Share 71.6% 71.6% 70.5% 64.8% 54.5% 69.8% 63.9% 63.1% 64.3% 57.9% 53.0% GPU Market Share 0.1% 0.1% 0.1% 0.3% 0.5% 0.3% 0.3% 1.3% 0.3% 0.4% 1.7% Merged Market Share 71.7% 71.7% 70.6% 65.1% 53.6% 70.0% 64.2% 62.9% 64.6% 58.3% 51.8% PJM Pre-Merger HHI 1,164 1,163 1,181 1,178 1,143 976 1,130 1,551 940 1,059 1,288 Post-Merger HHI 1,176 1,175 1,190 1,183 1,136 998 1,141 1,543 967 1,077 1,302 Change 12 12 9 5 (7) 22 11 (8) 27 18 14 FE Capacity (MW) 761 761 472 206 360 964 390 235 979 460 262 GPU Capacity (MW) 2,415 2,415 2,043 1,926 1,911 2,171 1,991 1,971 1,885 1,747 1,717 Merged Capacity (MW) 3,176 3,176 2,515 2,132 2,810 3,136 2,381 2,724 2,864 2,207 2,489 FE Market Share 1.4% 1.4% 1.0% 0.5% 1.1% 2.2% 1.0% 1.2% 2.6% 1.5% 1.6% GPU Market Share 4.4% 4.4% 4.5% 5.0% 5.7% 5.0% 5.4% 10.4% 5.1% 5.9% 10.3% Merged Market Share 5.8% 5.8% 5.5% 5.5% 8.2% 7.3% 6.4% 13.9% 7.7% 7.4% 14.3% AEP Pre-Merger HHI 2,434 2,433 2,385 2,464 3,817 2,243 2,131 2,586 1,817 1,693 2,066 Post-Merger HHI 2,434 2,434 2,386 2,464 3,818 2,243 2,131 2,594 1,817 1,694 2,083 Change 1 1 1 1 1 0 1 8 1 1 17 FE Capacity (MW) 3,012 3,011 3,019 2,968 1,664 1,613 1,694 1,591 2,436 2,558 2,403 GPU Capacity (MW) 18 18 21 25 28 26 46 354 26 47 363 Merged Capacity (MW) 3,029 3,030 3,040 2,993 1,697 1,639 1,740 2,025 2,463 2,605 2,853 FE Market Share 6.6% 6.6% 6.7% 6.7% 4.8% 3.4% 3.5% 3.9% 5.7% 5.9% 6.6% GPU Market Share 0.0% 0.0% 0.0% 0.1% 0.1% 0.1% 0.1% 0.9% 0.1% 0.1% 1.0% Merged Market Share 6.6% 6.6% 6.7% 6.8% 4.9% 3.5% 3.6% 5.0% 5.8% 6.0% 7.9%
326 Exhibit APP-313, page 2 of 5 SENSITIVITY FOR OFF-PEAK 650 MW SALE TO GPU
SUMMER WINTER SPRING / FALL ---------------------------------------------- ------------------------ ------------------------ Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak ------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- -------- APS Pre-Merger HHI 4,150 4,126 3,886 3,298 3,607 4,550 2,482 2,644 3,958 2,049 2,189 Post-Merger HHI 4,153 4,129 3,889 3,303 3,613 4,554 2,493 2,672 3,962 2,060 2,222 Change 3 3 3 5 6 4 11 28 4 12 33 FE Capacity (MW) 311 311 311 414 362 334 807 640 305 732 582 GPU Capacity (MW) 84 85 89 101 110 89 166 312 83 165 308 Merged Capacity (MW) 394 396 400 516 505 423 973 1,037 388 897 984 FE Market Share 2.3% 2.3% 2.5% 3.2% 3.0% 2.7% 5.1% 4.9% 2.8% 5.1% 5.0% GPU Market Share 0.6% 0.6% 0.7% 0.8% 0.9% 0.7% 1.0% 2.4% 0.8% 1.1% 2.6% Merged Market Share 3.0% 3.0% 3.2% 4.0% 4.2% 3.4% 6.1% 8.0% 3.6% 6.2% 8.4% DPL Pre-Merger HHI 7,115 7,092 6,817 5,475 3,907 5,308 3,766 2,963 4,712 3,243 2,618 Post-Merger HHI 7,115 7,092 6,817 5,476 3,904 5,308 3,767 2,958 4,713 3,245 2,611 Change 0 0 0 0 (3) 0 1 (5) 0 1 (7) FE Capacity (MW) 137 137 137 211 351 234 408 475 228 397 457 GPU Capacity (MW) 0 0 0 1 3 1 2 8 1 2 11 Merged Capacity (MW) 137 137 137 212 341 235 410 461 229 399 442 FE Market Share 3.5% 3.6% 3.9% 5.8% 7.8% 6.3% 9.0% 10.0% 7.2% 10.0% 10.8% GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.1% 0.0% 0.0% 0.2% 0.0% 0.1% 0.3% Merged Market Share 3.5% 3.6% 3.9% 5.8% 7.6% 6.3% 9.0% 9.7% 7.2% 10.0% 10.4% DQE Pre-Merger HHI 6,207 6,207 6,030 3,964 5,902 3,369 3,018 2,676 3,354 3,169 3,461 Post-Merger HHI 6,208 6,208 6,030 3,966 5,902 3,371 3,022 2,762 3,357 3,174 3,566 Change 0 0 0 2 0 2 4 86 3 6 105 FE Capacity (MW) 591 591 592 1,774 604 1,348 1,714 2,101 1,597 2,031 3,021 GPU Capacity (MW) 0 0 0 1 1 2 4 41 2 4 44 Merged Capacity (MW) 591 591 593 1,775 604 1,350 1,718 2,151 1,599 2,034 3,075 FE Market Share 17.5% 17.5% 18.7% 37.6% 19.4% 27.5% 30.7% 42.6% 36.2% 40.0% 54.3% GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.1% 0.8% 0.0% 0.1% 0.8% Merged Market Share 17.5% 17.5% 18.7% 37.7% 19.5% 27.5% 30.8% 43.6% 36.3% 40.1% 55.3%
327 Exhibit APP-313, page 3 of 5 SENSITIVITY FOR OFF-PEAK 650 MW SALE TO GPU
SUMMER WINTER SPRING / FALL ---------------------------------------------- ------------------------ ------------------------ Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak ------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- -------- MECS Pre-Merger HHI 3,448 3,437 3,290 3,854 2,878 2,643 2,636 3,267 2,363 2,351 2,816 Post-Merger HHI 3,448 3,437 3,290 3,855 2,875 2,643 2,636 3,264 2,364 2,352 2,807 Change 0 0 0 0 (3) 0 0 (3) 1 1 (9) FE Capacity (MW) 964 963 964 541 1,143 1,184 1,114 1,006 1,633 1,531 1,368 GPU Capacity (MW) 1 1 1 2 11 5 5 18 7 9 33 Merged Capacity (MW) 965 965 965 543 1,110 1,188 1,119 977 1,640 1,540 1,322 FE Market Share 4.5% 4.5% 5.5% 3.6% 7.2% 6.3% 6.5% 7.8% 9.9% 10.3% 12.2% GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.1% 0.0% 0.0% 0.1% 0.0% 0.1% 0.3% Merged Market Share 4.5% 4.5% 5.5% 3.6% 7.0% 6.3% 6.5% 7.6% 10.0% 10.4% 11.8% NYPP Pre-Merger HHI 1,166 1,157 1,173 1,064 939 1,161 1,083 1,017 1,001 956 807 Post-Merger HHI 1,166 1,158 1,173 1,064 939 1,161 1,083 1,017 1,001 956 809 Change 0 0 0 0 (0) 0 0 (0) 0 0 2 FE Capacity (MW) 10 11 13 8 18 13 8 13 48 34 54 GPU Capacity (MW) 62 63 65 70 83 47 48 106 131 148 320 Merged Capacity (MW) 72 74 78 78 121 59 57 142 179 182 448 FE Market Share 0.0% 0.0% 0.0% 0.0% 0.1% 0.1% 0.0% 0.1% 0.2% 0.2% 0.5% GPU Market Share 0.2% 0.2% 0.2% 0.3% 0.6% 0.2% 0.2% 1.0% 0.5% 0.7% 2.9% Merged Market Share 0.2% 0.2% 0.2% 0.3% 0.9% 0.3% 0.3% 1.3% 0.7% 0.9% 4.1% VEPCO Pre-Merger HHI 4,005 3,954 3,425 3,054 2,711 3,098 2,768 1,979 3,067 2,626 1,734 Post-Merger HHI 4,005 3,954 3,426 3,055 2,712 3,099 2,769 1,986 3,069 2,628 1,748 Change 1 1 1 1 1 1 1 8 1 2 15 FE Capacity (MW) 176 176 181 180 128 104 107 207 148 153 254 GPU Capacity (MW) 99 101 105 111 136 138 140 308 132 145 316 Merged Capacity (MW) 275 277 286 292 306 242 247 599 280 298 666 FE Market Share 0.8% 0.8% 0.9% 1.0% 0.8% 0.6% 0.6% 1.6% 0.9% 1.0% 2.2% GPU Market Share 0.4% 0.5% 0.5% 0.6% 0.8% 0.8% 0.8% 2.3% 0.8% 1.0% 2.7% Merged Market Share 1.2% 1.2% 1.4% 1.6% 1.8% 1.3% 1.5% 4.5% 1.7% 2.0% 5.8%
328 Exhibit APP-313, page 4 of 5 SENSITIVITY FOR OFF-PEAK 650 MW SALE TO GPU
SUMMER WINTER SPRING / FALL ---------------------------------------------- ------------------------ ------------------------ Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak ------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- -------- PJM-WESTINT Pre-Merger HHI 1,164 1,163 1,181 1,178 1,143 976 1,130 1,551 945 1,059 1,288 Post-Merger HHI 1,176 1,175 1,190 1,183 1,136 998 1,141 1,543 971 1,077 1,302 Change 12 12 9 5 (7) 22 11 (8) 26 18 14 FE Capacity (MW) 761 761 472 206 360 964 390 235 955 460 262 GPU Capacity (MW) 2,415 2,415 2,043 1,926 1,911 2,171 1,991 1,971 1,885 1,747 1,717 Merged Capacity (MW) 3,176 3,176 2,515 2,132 2,810 3,136 2,381 2,724 2,841 2,207 2,489 FE Market Share 1.4% 1.4% 1.0% 0.5% 1.1% 2.2% 1.0% 1.2% 2.6% 1.5% 1.6% GPU Market Share 4.4% 4.4% 4.5% 5.0% 5.7% 5.0% 5.4% 10.4% 5.1% 5.9% 10.3% Merged Market Share 5.8% 5.8% 5.5% 5.5% 8.2% 7.3% 6.4% 13.9% 7.7% 7.4% 14.3% PJM-CENTINT Pre-Merger HHI 1,508 1,507 1,550 1,462 1,479 1,312 1,455 1,564 1,295 1,365 1,417 Post-Merger HHI 1,513 1,513 1,555 1,465 1,496 1,325 1,462 1,604 1,311 1,378 1,480 Change 6 6 5 3 16 13 7 40 16 13 63 FE Capacity (MW) 216 216 149 71 139 320 151 229 317 192 199 GPU Capacity (MW) 2,177 2,177 1,815 1,714 1,713 1,926 1,769 1,962 1,633 1,533 1,631 Merged Capacity (MW) 2,392 2,392 1,964 1,785 2,434 2,246 1,920 2,666 1,950 1,725 2,332 FE Market Share 0.5% 0.5% 0.4% 0.3% 0.6% 1.0% 0.6% 1.2% 1.3% 0.9% 1.3% GPU Market Share 5.3% 5.4% 5.5% 6.1% 6.9% 6.3% 6.5% 10.5% 6.5% 7.1% 10.9% Merged Market Share 5.9% 5.9% 5.9% 6.4% 9.8% 7.3% 7.0% 14.2% 7.7% 8.0% 15.6% PJM-EASTINT Pre-Merger HHI 1,485 1,477 1,417 1,378 1,350 1,171 1,306 1,667 1,205 1,228 1,432 Post-Merger HHI 1,493 1,484 1,424 1,382 1,356 1,189 1,315 1,680 1,226 1,243 1,480 Change 7 7 7 4 6 18 9 13 21 15 48 FE Capacity (MW) 216 217 150 71 133 292 138 172 296 174 173 GPU Capacity (MW) 1,863 1,864 1,517 1,429 1,441 1,604 1,468 1,757 1,355 1,279 1,467 Merged Capacity (MW) 2,079 2,081 1,667 1,500 2,155 1,896 1,606 2,433 1,651 1,454 2,148
329 Exhibit APP-313, page 5 of 5 SENSITIVITY FOR OFF-PEAK 650 MW SALE TO GPU
SUMMER WINTER SPRING / FALL ---------------------------------------------- ------------------------ ------------------------ Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak ------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- -------- FE Market Share 0.7% 0.7% 0.6% 0.3% 0.7% 1.3% 0.7% 1.1% 1.5% 1.0% 1.3% GPU Market Share 5.7% 5.7% 5.7% 6.4% 7.4% 7.0% 7.0% 11.1% 7.0% 7.5% 11.3% Merged Market Share 6.3% 6.3% 6.3% 6.8% 11.1% 8.3% 7.6% 15.4% 8.5% 8.6% 16.6%
330 EXHIBIT NO. APP-314 331 Exhibit APP-314, page 1 of 5 SENSITIVITY FOR GPU DIVESTING YARDS CREEK TO PSEG
SUMMER WINTER SPRING / FALL ---------------------------------------------- ------------------------ ------------------------ Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak ------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- -------- FE Pre-Merger HHI 5,228 5,225 5,085 4,334 3,215 4,948 4,194 4,113 4,262 3,519 3,028 Post-Merger HHI 5,241 5,239 5,101 4,369 3,269 4,982 4,236 4,274 4,295 3,562 3,206 Change 14 14 16 36 54 34 42 161 32 43 178 FE Capacity (MW) 11,798 11,788 11,090 10,101 9,965 10,789 10,162 8,175 8,360 7,847 4,973 GPU Capacity (MW) 16 16 18 43 90 38 52 166 33 50 158 Merged Capacity (MW) 11,814 11,804 11,108 10,144 10,055 10,827 10,215 8,341 8,393 7,897 5,131 FE Market Share 71.6% 71.6% 70.5% 64.8% 54.5% 69.8% 63.9% 63.1% 64.3% 57.9% 53.0% GPU Market Share 0.1% 0.1% 0.1% 0.3% 0.5% 0.2% 0.3% 1.3% 0.3% 0.4% 1.7% Merged Market Share 71.7% 71.7% 70.6% 65.1% 55.0% 70.0% 64.2% 64.3% 64.6% 58.3% 54.6% PJM Pre-Merger HHI 1,173 1,172 1,183 1,178 1,143 983 1,130 1,551 946 1,060 1,288 Post-Merger HHI 1,184 1,183 1,192 1,183 1,155 1,003 1,141 1,577 971 1,078 1,320 Change 11 11 9 5 12 21 11 26 24 18 32 FE Capacity (MW) 761 761 472 206 360 964 390 235 979 460 262 GPU Capacity (MW) 2,235 2,235 2,005 1,926 1,911 1,992 1,990 1,971 1,739 1,733 1,717 Merged Capacity (MW) 2,997 2,997 2,478 2,132 2,271 2,956 2,380 2,206 2,718 2,193 1,979 FE Market Share 1.4% 1.4% 1.0% 0.5% 1.1% 2.2% 1.0% 1.2% 2.6% 1.5% 1.6% GPU Market Share 4.0% 4.1% 4.4% 5.0% 5.7% 4.6% 5.4% 10.4% 4.7% 5.8% 10.3% Merged Market Share 5.4% 5.5% 5.5% 5.5% 6.7% 6.8% 6.4% 11.7% 7.3% 7.4% 11.8% AEP Pre-Merger HHI 2,434 2,433 2,385 2,464 3,817 2,243 2,131 2,586 1,817 1,693 2,066 Post-Merger HHI 2,434 2,434 2,386 2,464 3,817 2,243 2,131 2,593 1,817 1,694 2,079 Change 0 0 1 1 1 0 1 7 1 1 13 FE Capacity (MW) 3,012 3,011 3,019 2,968 1,664 1,613 1,694 1,591 2,436 2,558 2,403 GPU Capacity (MW) 16 17 21 25 28 24 46 354 24 47 363 Merged Capacity (MW) 3,028 3,028 3,040 2,993 1,692 1,637 1,740 1,945 2,461 2,605 2,766 FE Market Share 6.6% 6.6% 6.7% 6.7% 4.8% 3.4% 3.5% 3.9% 5.7% 5.9% 6.6% GPU Market Share 0.0% 0.0% 0.0% 0.1% 0.1% 0.1% 0.1% 0.9% 0.1% 0.1% 1.0% Merged Market Share 6.6% 6.6% 6.7% 6.8% 4.9% 3.5% 3.6% 4.8% 5.8% 6.0% 7.6%
332 Exhibit APP-314, page 2 of 5 SENSITIVITY FOR GPU DIVESTING YARDS CREEK TO PSEG
SUMMER WINTER SPRING / FALL ---------------------------------------------- ------------------------ ------------------------ Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak ------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- -------- APS Pre-Merger HHI 4,151 4,126 3,886 3,298 3,607 4,551 2,482 2,644 3,958 2,049 2,189 Post-Merger HHI 4,153 4,129 3,889 3,303 3,612 4,554 2,493 2,668 3,962 2,060 2,215 Change 3 3 3 5 5 4 11 24 4 11 26 FE Capacity (MW) 311 311 311 414 362 334 807 640 305 732 582 GPU Capacity (MW) 77 79 87 101 110 82 166 312 77 164 308 Merged Capacity (MW) 388 390 398 516 472 416 973 952 381 895 890 FE Market Share 2.3% 2.3% 2.5% 3.2% 3.0% 2.7% 5.1% 4.9% 2.8% 5.1% 5.0% GPU Market Share 0.6% 0.6% 0.7% 0.8% 0.9% 0.7% 1.0% 2.4% 0.7% 1.1% 2.6% Merged Market Share 2.9% 2.9% 3.2% 4.0% 3.9% 3.3% 6.1% 7.3% 3.5% 6.2% 7.6% DPL Pre-Merger HHI 7,115 7,092 6,817 5,475 3,907 5,308 3,766 2,963 4,712 3,243 2,618 Post-Merger HHI 7,115 7,092 6,817 5,476 3,909 5,308 3,767 2,967 4,712 3,244 2,623 Change 0 0 0 0 1 0 1 4 0 1 6 FE Capacity (MW) 137 137 137 211 351 234 408 475 228 397 457 GPU Capacity (MW) 0 0 0 1 3 1 2 8 1 2 11 Merged Capacity (MW) 137 137 137 212 354 235 410 484 229 399 468 FE Market Share 3.5% 3.6% 3.9% 5.8% 7.8% 6.3% 9.0% 10.0% 7.2% 10.0% 10.8% GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.1% 0.0% 0.0% 0.2% 0.0% 0.1% 0.3% Merged Market Share 3.5% 3.6% 3.9% 5.8% 7.9% 6.3% 9.0% 10.2% 7.2% 10.0% 11.1% DQE Pre-Merger HHI 6,207 6,207 6,030 3,964 5,902 3,369 3,018 2,676 3,354 3,169 3,461 Post-Merger HHI 6,208 6,208 6,030 3,966 5,903 3,370 3,022 2,747 3,357 3,174 3,546 Change 0 0 0 2 1 2 4 70 3 6 85 FE Capacity (MW) 591 591 592 1,774 604 1,348 1,714 2,101 1,597 2,031 3,021 GPU Capacity (MW) 0 0 0 1 1 2 4 41 2 4 44 Merged Capacity (MW) 591 591 593 1,775 605 1,349 1,718 2,142 1,599 2,034 3,064 FE Market Share 17.5% 17.5% 18.7% 37.6% 19.4% 27.5% 30.7% 42.6% 36.2% 40.0% 54.3% GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.1% 0.8% 0.0% 0.1% 0.8% Merged Market Share 17.5% 17.5% 18.7% 37.7% 19.5% 27.5% 30.8% 43.4% 36.3% 40.1% 55.1%
333 Exhibit APP-314, page 3 of 5 SENSITIVITY FOR GPU DIVESTING YARDS CREEK TO PSEG
SUMMER WINTER SPRING / FALL ---------------------------------------------- ------------------------ ------------------------ Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak ------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- -------- MECS Pre-Merger HHI 3,448 3,437 3,290 3,854 2,878 2,643 2,636 3,267 2,363 2,351 2,816 Post-Merger HHI 3,448 3,437 3,290 3,855 2,879 2,643 2,636 3,270 2,363 2,352 2,824 Change 0 0 0 0 1 0 0 2 1 1 7 FE Capacity (MW) 964 963 964 541 1,143 1,184 1,114 1,006 1,633 1,531 1,368 GPU Capacity (MW) 1 1 1 2 11 4 5 18 7 9 33 Merged Capacity (MW) 965 965 965 543 1,154 1,188 1,119 1,024 1,640 1,540 1,401 FE Market Share 4.5% 4.5% 5.5% 3.6% 7.2% 6.3% 6.5% 7.8% 9.9% 10.3% 12.2% GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.1% 0.0% 0.0% 0.1% 0.0% 0.1% 0.3% Merged Market Share 4.5% 4.5% 5.5% 3.6% 7.3% 6.3% 6.5% 7.9% 10.0% 10.4% 12.5% NYPP Pre-Merger HHI 1,166 1,158 1,173 1,064 939 1,161 1,083 1,017 1,001 956 807 Post-Merger HHI 1,166 1,158 1,173 1,064 940 1,161 1,083 1,017 1,001 956 810 Change 0 0 0 0 0 0 0 0 0 0 3 FE Capacity (MW) 10 11 13 8 18 13 8 13 48 34 54 GPU Capacity (MW) 57 59 64 70 83 43 48 106 121 147 320 Merged Capacity (MW) 68 69 77 78 101 55 57 119 169 181 374 FE Market Share 0.0% 0.0% 0.0% 0.0% 0.1% 0.1% 0.0% 0.1% 0.2% 0.2% 0.5% GPU Market Share 0.1% 0.2% 0.2% 0.3% 0.6% 0.2% 0.2% 1.0% 0.5% 0.7% 2.9% Merged Market Share 0.2% 0.2% 0.2% 0.3% 0.8% 0.2% 0.3% 1.1% 0.7% 0.9% 3.4% VEPCO Pre-Merger HHI 4,005 3,954 3,425 3,054 2,711 3,098 2,768 1,979 3,067 2,626 1,734 Post-Merger HHI 4,005 3,954 3,426 3,055 2,712 3,099 2,769 1,986 3,069 2,628 1,746 Change 1 1 1 1 1 1 1 7 1 2 12 FE Capacity (MW) 176 176 181 180 128 104 107 207 148 153 254 GPU Capacity (MW) 92 93 103 111 136 126 140 308 122 144 316 Merged Capacity (MW) 268 269 284 292 264 230 247 515 270 297 570
334 Exhibit APP-314, page 4 of 5 SENSITIVITY FOR GPU DIVESTING YARDS CREEK TO PSEG
SUMMER WINTER SPRING / FALL ---------------------------------------------- ------------------------ ------------------------ Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak ------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- -------- FE Market Share 0.8% 0.8% 0.9% 1.0% 0.8% 0.6% 0.6% 1.6% 0.9% 1.0% 2.2% GPU Market Share 0.4% 0.4% 0.5% 0.6% 0.8% 0.7% 0.8% 2.3% 0.7% 1.0% 2.7% Merged Market Share 1.2% 1.2% 1.4% 1.6% 1.6% 1.3% 1.5% 3.9% 1.6% 2.0% 5.0% PJM-WESTINT Pre-Merger HHI 1,173 1,172 1,183 1,178 1,143 983 1,130 1,551 951 1,060 1,288 Post-Merger HHI 1,184 1,183 1,192 1,183 1,155 1,003 1,141 1,577 975 1,078 1,320 Change 11 11 9 5 12 21 11 26 24 18 32 FE Capacity (MW) 761 761 472 206 360 964 390 235 955 460 262 GPU Capacity (MW) 2,235 2,235 2,005 1,926 1,911 1,992 1,990 1,971 1,739 1,733 1,717 Merged Capacity (MW) 2,997 2,997 2,478 2,132 2,271 2,956 2,380 2,206 2,695 2,193 1,979 FE Market Share 1.4% 1.4% 1.0% 0.5% 1.1% 2.2% 1.0% 1.2% 2.6% 1.5% 1.6% GPU Market Share 4.0% 4.1% 4.4% 5.0% 5.7% 4.6% 5.4% 10.4% 4.7% 5.8% 10.3% Merged Market Share 5.4% 5.5% 5.5% 5.5% 6.7% 6.8% 6.4% 11.7% 7.3% 7.4% 11.8% PJM-CENTINT Pre-Merger HHI 1,524 1,523 1,554 1,462 1,479 1,325 1,455 1,564 1,308 1,366 1,417 Post-Merger HHI 1,529 1,529 1,558 1,465 1,487 1,337 1,462 1,589 1,322 1,379 1,446 Change 5 5 5 3 8 12 7 26 15 12 29 FE Capacity (MW) 216 216 149 71 139 320 151 229 317 192 199 GPU Capacity (MW) 1,998 1,998 1,778 1,714 1,713 1,747 1,767 1,962 1,487 1,519 1,631 Merged Capacity (MW) 2,213 2,213 1,926 1,785 1,852 2,067 1,918 2,191 1,804 1,711 1,830 FE Market Share 0.5% 0.5% 0.4% 0.3% 0.6% 1.0% 0.6% 1.2% 1.3% 0.9% 1.3% GPU Market Share 4.9% 4.9% 5.4% 6.1% 6.9% 5.7% 6.5% 10.5% 5.9% 7.0% 10.9% Merged Market Share 5.4% 5.4% 5.8% 6.4% 7.5% 6.7% 7.0% 11.7% 7.1% 7.9% 12.2% PJM-EASTINT Pre-Merger HHI 1,509 1,500 1,422 1,378 1,350 1,190 1,306 1,667 1,224 1,230 1,432 Post-Merger HHI 1,516 1,507 1,428 1,382 1,360 1,206 1,315 1,691 1,244 1,245 1,463 Change 7 7 6 4 10 16 9 24 19 15 30 FE Capacity (MW) 216 217 150 71 133 292 138 172 296 174 173 GPU Capacity (MW) 1,684 1,685 1,479 1,429 1,441 1,425 1,466 1,757 1,209 1,265 1,467 Merged Capacity (MW) 1,900 1,901 1,629 1,500 1,574 1,717 1,604 1,929 1,505 1,439 1,640
335 Exhibit APP-314, page 5 of 5 SENSITIVITY FOR GPU DIVESTING YARDS CREEK TO PSEG
SUMMER WINTER SPRING / FALL ---------------------------------------------- ------------------------ ------------------------ Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak ------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- -------- FE Market Share 0.7% 0.7% 0.6% 0.3% 0.7% 1.3% 0.7% 1.1% 1.5% 1.0% 1.3% GPU Market Share 5.1% 5.1% 5.6% 6.4% 7.4% 6.2% 7.0% 11.1% 6.3% 7.5% 11.3% Merged Market Share 5.8% 5.8% 6.2% 6.8% 8.1% 7.5% 7.6% 12.2% 7.8% 8.5% 12.7%
336 EXHIBIT NO. APP-315 337 Exhibit APP-315, page 1 of 5 SENSITIVITY FOR HENRY HUB GAS PRICE DECREASE BY $1
SUMMER WINTER SPRING / FALL ---------------------------------------------- ------------------------ ------------------------ Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak ------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- -------- FE Pre-Merger HHI 5,228 5,225 5,055 4,545 3,215 4,948 4,194 4,113 4,492 3,519 3,028 Post-Merger HHI 5,243 5,240 5,070 4,579 3,269 4,985 4,236 4,274 4,525 3,561 3,206 Change 15 15 15 34 54 37 42 161 34 42 178 FE Capacity (MW) 11,798 11,788 11,090 10,897 9,965 10,789 10,162 8,175 9,072 7,847 4,973 GPU Capacity (MW) 17 17 17 42 90 41 52 166 35 49 158 Merged Capacity (MW) 11,815 11,805 11,107 10,939 10,055 10,830 10,215 8,341 9,107 7,897 5,131 FE Market Share 71.6% 71.6% 70.3% 66.5% 54.5% 69.8% 63.9% 63.1% 66.2% 57.9% 53.0% GPU Market Share 0.1% 0.1% 0.1% 0.3% 0.5% 0.3% 0.3% 1.3% 0.3% 0.4% 1.7% Merged Market Share 71.7% 71.7% 70.4% 66.8% 55.0% 70.0% 64.2% 64.3% 66.5% 58.3% 54.6% PJM Pre-Merger HHI 1,164 1,163 1,166 1,217 1,143 976 1,130 1,551 971 1,008 1,288 Post-Merger HHI 1,176 1,175 1,174 1,221 1,155 998 1,141 1,577 995 1,026 1,320 Change 12 12 8 5 12 22 11 26 24 17 32 FE Capacity (MW) 761 761 473 208 360 964 390 235 979 460 262 GPU Capacity (MW) 2,415 2,415 2,043 1,997 1,911 2,171 1,991 1,971 1,957 1,747 1,717 Merged Capacity (MW) 3,176 3,176 2,516 2,205 2,271 3,136 2,381 2,206 2,935 2,207 1,979 FE Market Share 1.4% 1.4% 1.0% 0.5% 1.1% 2.2% 1.0% 1.2% 2.5% 1.5% 1.6% GPU Market Share 4.4% 4.4% 4.2% 4.7% 5.7% 5.0% 5.4% 10.4% 4.9% 5.7% 10.3% Merged Market Share 5.8% 5.8% 5.2% 5.2% 6.7% 7.3% 6.4% 11.7% 7.4% 7.2% 11.8% AEP Pre-Merger HHI 2,434 2,433 2,385 2,403 3,817 2,243 2,131 2,586 1,781 1,692 2,066 Post-Merger HHI 2,434 2,434 2,386 2,403 3,817 2,243 2,131 2,593 1,781 1,693 2,079 Change 1 1 1 1 1 0 1 7 1 1 13 FE Capacity (MW) 3,012 3,011 3,020 2,972 1,664 1,613 1,694 1,591 2,436 2,558 2,403 GPU Capacity (MW) 18 18 19 25 28 25 46 354 26 47 363 Merged Capacity (MW) 3,029 3,030 3,039 2,997 1,692 1,639 1,740 1,945 2,463 2,605 2,766 FE Market Share 6.6% 6.6% 6.7% 6.7% 4.8% 3.4% 3.5% 3.9% 5.6% 5.9% 6.6% GPU Market Share 0.0% 0.0% 0.0% 0.1% 0.1% 0.1% 0.1% 0.9% 0.1% 0.1% 1.0% Merged Market Share 6.6% 6.6% 6.7% 6.7% 4.9% 3.5% 3.6% 4.8% 5.7% 6.0% 7.6%
338 Exhibit APP-315, page 2 of 5 SENSITIVITY FOR HENRY HUB GAS PRICE DECREASE BY $1
SUMMER WINTER SPRING / FALL ---------------------------------------------- ------------------------ ------------------------ Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak ------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- -------- APS Pre-Merger HHI 4,150 4,126 3,886 3,370 3,607 4,550 2,482 2,644 4,029 2,047 2,189 Post-Merger HHI 4,153 4,129 3,890 3,375 3,612 4,554 2,493 2,668 4,033 2,058 2,215 Change 3 3 3 5 5 4 11 24 4 11 26 FE Capacity (MW) 311 311 311 415 362 334 807 640 305 732 582 GPU Capacity (MW) 84 85 81 98 110 89 166 312 81 160 308 Merged Capacity (MW) 394 395 392 513 472 423 973 952 386 892 890 FE Market Share 2.3% 2.3% 2.5% 3.2% 3.0% 2.7% 5.1% 4.9% 2.8% 5.1% 5.0% GPU Market Share 0.6% 0.6% 0.6% 0.7% 0.9% 0.7% 1.0% 2.4% 0.7% 1.1% 2.6% Merged Market Share 3.0% 3.0% 3.1% 3.9% 3.9% 3.4% 6.1% 7.3% 3.5% 6.2% 7.6% DPL Pre-Merger HHI 7,115 7,101 7,020 5,703 3,907 5,308 3,766 2,963 4,898 3,243 2,618 Post-Merger HHI 7,115 7,101 7,020 5,703 3,909 5,308 3,767 2,967 4,898 3,245 2,623 Change 0 0 0 0 1 0 1 4 0 1 6 FE Capacity (MW) 137 137 137 212 351 234 408 475 228 397 457 GPU Capacity (MW) 0 0 0 1 3 1 2 8 1 2 11 Merged Capacity (MW) 137 137 137 213 354 235 410 484 229 399 468 FE Market Share 3.5% 3.5% 3.7% 5.4% 7.8% 6.3% 9.0% 10.0% 6.9% 10.0% 10.8% GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.1% 0.0% 0.0% 0.2% 0.0% 0.1% 0.3% Merged Market Share 3.5% 3.6% 3.7% 5.4% 7.9% 6.3% 9.0% 10.2% 6.9% 10.0% 11.1% DQE Pre-Merger HHI 6,207 6,207 6,029 3,968 5,902 3,368 3,018 2,676 3,354 3,169 3,461 Post-Merger HHI 6,208 6,208 6,029 3,970 5,903 3,370 3,022 2,747 3,357 3,174 3,546 Change 0 0 0 2 1 2 4 70 3 6 85 FE Capacity (MW) 591 591 593 1,776 604 1,348 1,714 2,101 1,597 2,031 3,021 GPU Capacity (MW) 0 0 0 1 1 2 4 41 2 4 44 Merged Capacity (MW) 591 591 593 1,777 605 1,350 1,718 2,142 1,599 2,034 3,064 FE Market Share 17.5% 17.5% 18.7% 37.7% 19.4% 27.5% 30.7% 42.6% 36.2% 40.0% 54.3% GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.1% 0.8% 0.0% 0.1% 0.8% Merged Market Share 17.5% 17.5% 18.7% 37.7% 19.5% 27.5% 30.8% 43.4% 36.3% 40.1% 55.1%
339 Exhibit APP-315, page 3 of 5 SENSITIVITY FOR HENRY HUB GAS PRICE DECREASE BY $1
SUMMER WINTER SPRING / FALL ---------------------------------------------- ------------------------ ------------------------ Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak ------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- -------- MECS Pre-Merger HHI 3,448 3,437 3,365 3,784 2,878 2,641 2,636 3,267 2,371 2,351 2,816 Post-Merger HHI 3,448 3,437 3,366 3,784 2,879 2,642 2,636 3,270 2,372 2,352 2,824 Change 0 0 0 0 1 0 0 2 1 1 7 FE Capacity (MW) 964 963 964 544 1,143 1,184 1,114 1,006 1,633 1,531 1,368 GPU Capacity (MW) 1 1 1 2 11 4 5 18 7 9 33 Merged Capacity (MW) 965 965 966 546 1,154 1,188 1,119 1,024 1,640 1,540 1,401 FE Market Share 4.5% 4.5% 4.8% 3.5% 7.2% 6.3% 6.5% 7.8% 9.7% 10.3% 12.2% GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.1% 0.0% 0.0% 0.1% 0.0% 0.1% 0.3% Merged Market Share 4.5% 4.5% 4.8% 3.5% 7.3% 6.3% 6.5% 7.9% 9.7% 10.4% 12.5% NYPP Pre-Merger HHI 1,166 1,153 1,139 1,152 939 1,153 1,083 1,017 1,029 954 807 Post-Merger HHI 1,166 1,153 1,139 1,152 940 1,153 1,083 1,017 1,029 955 810 Change 0 0 0 0 0 0 0 0 0 0 3 FE Capacity (MW) 10 10 12 7 18 13 8 13 46 33 54 GPU Capacity (MW) 62 63 60 69 83 47 48 106 129 144 320 Merged Capacity (MW) 72 73 72 76 101 59 57 119 175 177 374 FE Market Share 0.0% 0.0% 0.0% 0.0% 0.1% 0.1% 0.0% 0.1% 0.2% 0.2% 0.5% GPU Market Share 0.2% 0.2% 0.2% 0.2% 0.6% 0.2% 0.2% 1.0% 0.5% 0.7% 2.9% Merged Market Share 0.2% 0.2% 0.2% 0.3% 0.8% 0.3% 0.3% 1.1% 0.6% 0.9% 3.4% VEPCO Pre-Merger HHI 4,005 3,954 3,698 3,260 2,711 3,098 2,768 1,979 3,261 2,625 1,734 Post-Merger HHI 4,005 3,954 3,699 3,261 2,712 3,099 2,769 1,986 3,262 2,627 1,746 Change 1 1 1 1 1 1 1 7 1 2 12 FE Capacity (MW) 176 176 179 180 128 104 107 207 148 153 254 GPU Capacity (MW) 99 100 96 108 136 138 140 308 130 141 316 Merged Capacity (MW) 275 276 275 289 264 242 247 515 278 294 570 FE Market Share 0.8% 0.8% 0.9% 0.9% 0.8% 0.6% 0.6% 1.6% 0.9% 1.0% 2.2% GPU Market Share 0.4% 0.5% 0.5% 0.6% 0.8% 0.8% 0.8% 2.3% 0.8% 0.9% 2.7% Merged Market Share 1.2% 1.2% 1.3% 1.5% 1.6% 1.3% 1.5% 3.9% 1.6% 2.0% 5.0%
340 Exhibit APP-315, page 4 of 5 SENSITIVITY FOR HENRY HUB GAS PRICE DECREASE BY $1
SUMMER WINTER SPRING / FALL ---------------------------------------------- ------------------------ ------------------------ Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak ------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- -------- PJM-WESTINT Pre-Merger HHI 1,164 1,163 1,166 1,217 1,143 976 1,130 1,551 976 1,008 1,288 Post-Merger HHI 1,176 1,175 1,174 1,221 1,155 998 1,141 1,577 1,000 1,026 1,320 Change 12 12 8 5 12 22 11 26 24 17 32 FE Capacity (MW) 761 761 473 208 360 964 390 235 955 460 262 GPU Capacity (MW) 2,415 2,415 2,043 1,997 1,911 2,171 1,991 1,971 1,957 1,747 1,717 Merged Capacity (MW) 3,176 3,176 2,516 2,205 2,271 3,136 2,381 2,206 2,912 2,207 1,979 FE Market Share 1.4% 1.4% 1.0% 0.5% 1.1% 2.2% 1.0% 1.2% 2.4% 1.5% 1.6% GPU Market Share 4.4% 4.4% 4.2% 4.7% 5.7% 5.0% 5.4% 10.4% 5.0% 5.7% 10.3% Merged Market Share 5.8% 5.8% 5.2% 5.2% 6.7% 7.3% 6.4% 11.7% 7.4% 7.2% 11.8% PJM-CENTINT Pre-Merger HHI 1,508 1,507 1,513 1,536 1,479 1,312 1,455 1,564 1,355 1,277 1,417 Post-Merger HHI 1,513 1,513 1,518 1,539 1,487 1,325 1,462 1,589 1,369 1,289 1,446 Change 6 6 4 3 8 13 7 26 14 12 29 FE Capacity (MW) 216 216 144 70 139 320 151 229 313 192 199 GPU Capacity (MW) 2,177 2,177 1,812 1,782 1,713 1,926 1,769 1,962 1,702 1,533 1,631 Merged Capacity (MW) 2,392 2,392 1,956 1,851 1,852 2,246 1,920 2,191 2,015 1,725 1,830 FE Market Share 0.5% 0.5% 0.4% 0.2% 0.6% 1.0% 0.6% 1.2% 1.1% 0.9% 1.3% GPU Market Share 5.3% 5.4% 5.1% 5.7% 6.9% 6.3% 6.5% 10.5% 6.2% 6.8% 10.9% Merged Market Share 5.9% 5.9% 5.5% 5.9% 7.5% 7.3% 7.0% 11.7% 7.4% 7.7% 12.2% PJM-EASTINT Pre-Merger HHI 1,485 1,477 1,423 1,404 1,350 1,170 1,306 1,667 1,211 1,180 1,432 Post-Merger HHI 1,493 1,484 1,429 1,407 1,360 1,188 1,315 1,691 1,229 1,195 1,463 Change 7 7 5 3 10 18 9 24 18 15 30 FE Capacity (MW) 216 217 146 71 133 292 138 172 293 169 173 GPU Capacity (MW) 1,863 1,864 1,511 1,495 1,441 1,604 1,468 1,757 1,424 1,271 1,467 Merged Capacity (MW) 2,079 2,081 1,657 1,565 1,574 1,896 1,606 1,929 1,717 1,440 1,640
341 Exhibit APP-315, page 5 of 5 SENSITIVITY FOR HENRY HUB GAS PRICE DECREASE BY $1
SUMMER WINTER SPRING / FALL ---------------------------------------------- ------------------------ ------------------------ Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak ------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- -------- FE Market Share 0.7% 0.7% 0.5% 0.3% 0.7% 1.3% 0.7% 1.1% 1.4% 1.0% 1.3% GPU Market Share 5.7% 5.7% 5.3% 5.9% 7.4% 7.0% 7.0% 11.1% 6.7% 7.4% 11.3% Merged Market Share 6.3% 6.3% 5.8% 6.2% 8.1% 8.3% 7.6% 12.2% 8.0% 8.4% 12.7%
342 EXHIBIT NO. APP-316 343 Exhibit APP-316, page 1 of 5 SENSITIVITY FOR HENRY HUB GAS PRICE DECREASE BY $2
SUMMER WINTER SPRING / FALL ---------------------------------------------- ------------------------ ------------------------ Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak ------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- -------- FE Pre-Merger HHI 5,228 5,225 5,060 4,518 3,215 5,161 4,193 4,113 4,464 3,749 3,028 Post-Merger HHI 5,243 5,240 5,074 4,548 3,269 5,195 4,235 4,274 4,494 3,790 3,206 Change 15 15 14 30 54 35 41 161 30 41 178 FE Capacity (MW) 11,798 11,788 11,111 10,897 9,965 11,637 10,162 8,175 9,072 8,560 4,973 GPU Capacity (MW) 17 17 16 37 90 40 51 166 32 48 158 Merged Capacity (MW) 11,815 11,805 11,127 10,934 10,055 11,676 10,214 8,341 9,104 8,608 5,131 FE Market Share 71.6% 71.6% 70.4% 66.4% 54.5% 71.4% 63.9% 63.1% 66.0% 60.0% 53.0% GPU Market Share 0.1% 0.1% 0.1% 0.2% 0.5% 0.2% 0.3% 1.3% 0.2% 0.3% 1.7% Merged Market Share 71.7% 71.7% 70.5% 66.6% 55.0% 71.6% 64.2% 64.3% 66.2% 60.3% 54.6% PJM Pre-Merger HHI 1,165 1,163 1,186 1,216 1,090 1,022 1,082 1,551 985 1,056 1,288 Post-Merger HHI 1,177 1,175 1,193 1,220 1,102 1,042 1,092 1,577 1,005 1,072 1,320 Change 12 12 8 4 11 20 11 26 20 15 32 FE Capacity (MW) 761 761 471 207 360 968 390 235 986 460 262 GPU Capacity (MW) 2,415 2,415 2,043 1,997 1,911 2,241 1,991 1,971 1,957 1,819 1,717 Merged Capacity (MW) 3,176 3,176 2,514 2,204 2,271 3,209 2,381 2,206 2,943 2,279 1,979 FE Market Share 1.4% 1.4% 0.9% 0.4% 1.0% 2.1% 1.0% 1.2% 2.3% 1.4% 1.6% GPU Market Share 4.4% 4.4% 4.1% 4.3% 5.5% 4.8% 5.2% 10.4% 4.5% 5.5% 10.3% Merged Market Share 5.7% 5.8% 5.0% 4.8% 6.5% 6.8% 6.3% 11.7% 6.7% 6.9% 11.8% AEP Pre-Merger HHI 2,434 2,433 2,385 2,402 3,816 2,191 2,129 2,586 1,776 1,659 2,066 Post-Merger HHI 2,434 2,434 2,386 2,403 3,817 2,191 2,130 2,593 1,777 1,660 2,079 Change 1 1 1 1 1 0 1 7 1 1 13 FE Capacity (MW) 3,012 3,011 3,008 2,960 1,664 1,616 1,694 1,591 2,440 2,558 2,403 GPU Capacity (MW) 17 18 18 22 28 25 46 354 23 46 363 Merged Capacity (MW) 3,029 3,030 3,026 2,982 1,692 1,640 1,740 1,945 2,463 2,604 2,766 FE Market Share 6.6% 6.6% 6.6% 6.6% 4.8% 3.4% 3.5% 3.9% 5.7% 5.8% 6.6% GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.1% 0.1% 0.1% 0.9% 0.1% 0.1% 1.0% Merged Market Share 6.6% 6.6% 6.7% 6.7% 4.9% 3.4% 3.6% 4.8% 5.7% 5.9% 7.6%
344 Exhibit APP-316, page 2 of 5 SENSITIVITY FOR HENRY HUB GAS PRICE DECREASE BY $2
SUMMER WINTER SPRING / FALL ---------------------------------------------- ------------------------ ------------------------ Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak ------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- -------- APS Pre-Merger HHI 4,150 4,126 3,887 3,371 3,607 4,619 2,480 2,644 4,030 2,099 2,189 Post-Merger HHI 4,153 4,129 3,890 3,375 3,612 4,623 2,490 2,668 4,034 2,110 2,215 Change 3 3 3 4 5 4 10 24 4 11 26 FE Capacity (MW) 311 311 310 413 362 334 807 640 305 732 582 GPU Capacity (MW) 83 85 78 88 110 86 162 312 73 157 308 Merged Capacity (MW) 394 395 389 501 472 420 969 952 378 889 890 FE Market Share 2.3% 2.3% 2.5% 3.1% 3.0% 2.6% 5.1% 4.9% 2.8% 5.0% 5.0% GPU Market Share 0.6% 0.6% 0.6% 0.7% 0.9% 0.7% 1.0% 2.4% 0.7% 1.1% 2.6% Merged Market Share 3.0% 3.0% 3.1% 3.8% 3.9% 3.3% 6.1% 7.3% 3.4% 6.1% 7.6% DPL Pre-Merger HHI 7,115 7,101 7,067 5,880 3,907 5,547 3,766 2,963 5,178 3,404 2,618 Post-Merger HHI 7,115 7,101 7,067 5,880 3,909 5,547 3,767 2,967 5,179 3,405 2,623 Change 0 0 0 0 1 0 1 4 0 1 6 FE Capacity (MW) 137 137 136 211 351 235 408 475 230 397 457 GPU Capacity (MW) 0 0 0 1 3 1 2 8 1 2 11 Merged Capacity (MW) 137 137 137 212 354 236 410 484 231 399 468 FE Market Share 3.5% 3.5% 3.6% 5.1% 7.8% 5.9% 9.0% 10.0% 6.4% 9.6% 10.8% GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.1% 0.0% 0.0% 0.2% 0.0% 0.1% 0.3% Merged Market Share 3.5% 3.6% 3.6% 5.1% 7.9% 5.9% 9.0% 10.2% 6.4% 9.6% 11.1% DQE Pre-Merger HHI 6,207 6,207 6,027 3,956 5,902 3,368 3,018 2,676 3,356 3,168 3,461 Post-Merger HHI 6,208 6,208 6,027 3,958 5,903 3,370 3,022 2,747 3,359 3,174 3,546 Change 0 0 0 2 1 2 4 70 2 6 85 FE Capacity (MW) 591 591 590 1,769 604 1,349 1,714 2,101 1,600 2,031 3,021 GPU Capacity (MW) 0 0 0 1 1 2 4 41 1 3 44 Merged Capacity (MW) 591 591 591 1,770 605 1,351 1,718 2,142 1,601 2,034 3,064 FE Market Share 17.5% 17.5% 18.6% 37.6% 19.4% 27.5% 30.7% 42.6% 36.3% 40.0% 54.3% GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.1% 0.8% 0.0% 0.1% 0.8% Merged Market Share 17.5% 17.5% 18.6% 37.6% 19.5% 27.5% 30.8% 43.4% 36.3% 40.1% 55.1%
345 Exhibit APP-316, page 3 of 5 SENSITIVITY FOR HENRY HUB GAS PRICE DECREASE BY $2
SUMMER WINTER SPRING / FALL ---------------------------------------------- ------------------------ ------------------------ Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak ------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- -------- MECS Pre-Merger HHI 3,448 3,437 3,372 3,794 2,878 2,664 2,636 3,267 2,545 2,338 2,816 Post-Merger HHI 3,448 3,437 3,372 3,794 2,879 2,664 2,636 3,270 2,545 2,339 2,824 Change 0 0 0 0 1 0 0 2 1 1 7 FE Capacity (MW) 964 963 961 542 1,143 1,190 1,114 1,006 1,644 1,531 1,368 GPU Capacity (MW) 1 1 1 2 11 4 5 18 6 8 33 Merged Capacity (MW) 965 965 962 544 1,154 1,194 1,119 1,024 1,650 1,539 1,401 FE Market Share 4.5% 4.5% 4.7% 3.0% 7.2% 5.9% 6.5% 7.8% 8.6% 10.0% 12.2% GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.1% 0.0% 0.0% 0.1% 0.0% 0.1% 0.3% Merged Market Share 4.5% 4.5% 4.7% 3.0% 7.3% 5.9% 6.5% 7.9% 8.6% 10.1% 12.5% NYPP Pre-Merger HHI 1,166 1,153 1,147 1,138 939 1,182 1,083 1,017 1,025 968 807 Post-Merger HHI 1,166 1,153 1,147 1,138 940 1,182 1,083 1,017 1,025 968 810 Change 0 0 0 0 0 0 0 0 0 0 3 FE Capacity (MW) 10 10 11 7 18 12 8 13 41 31 54 GPU Capacity (MW) 62 63 58 61 83 45 47 106 117 142 320 Merged Capacity (MW) 72 73 69 68 101 57 55 119 159 173 374 FE Market Share 0.0% 0.0% 0.0% 0.0% 0.1% 0.0% 0.0% 0.1% 0.1% 0.1% 0.5% GPU Market Share 0.2% 0.2% 0.2% 0.2% 0.6% 0.2% 0.2% 1.0% 0.4% 0.6% 2.9% Merged Market Share 0.2% 0.2% 0.2% 0.2% 0.8% 0.2% 0.3% 1.1% 0.5% 0.8% 3.4% VEPCO Pre-Merger HHI 4,005 3,954 3,699 3,545 2,711 3,306 2,766 1,979 3,578 2,837 1,734 Post-Merger HHI 4,005 3,954 3,700 3,546 2,712 3,307 2,767 1,986 3,579 2,839 1,746 Change 1 1 1 1 1 1 1 7 1 2 12 FE Capacity (MW) 176 176 178 178 128 103 107 207 146 153 254 GPU Capacity (MW) 99 100 93 97 136 132 137 308 117 139 316 Merged Capacity (MW) 275 276 271 275 264 235 244 515 263 291 570 FE Market Share 0.8% 0.8% 0.9% 0.9% 0.8% 0.5% 0.6% 1.6% 0.8% 1.0% 2.2% GPU Market Share 0.4% 0.5% 0.4% 0.5% 0.8% 0.7% 0.8% 2.3% 0.6% 0.9% 2.7% Merged Market Share 1.2% 1.2% 1.3% 1.4% 1.6% 1.2% 1.4% 3.9% 1.4% 1.8% 5.0%
346 Exhibit APP-316, page 4 of 5 SENSITIVITY FOR HENRY HUB GAS PRICE DECREASE BY $2
SUMMER WINTER SPRING / FALL ---------------------------------------------- ------------------------ ------------------------ Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak ------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- -------- PJM-WESTINT Pre-Merger HHI 1,165 1,163 1,186 1,216 1,090 1,022 1,082 1,551 989 1,056 1,288 Post-Merger HHI 1,177 1,175 1,193 1,220 1,102 1,042 1,092 1,577 1,009 1,072 1,320 Change 12 12 8 4 11 20 11 26 20 15 32 FE Capacity (MW) 761 761 471 207 360 968 390 235 963 460 262 GPU Capacity (MW) 2,415 2,415 2,043 1,997 1,911 2,241 1,991 1,971 1,957 1,819 1,717 Merged Capacity (MW) 3,176 3,176 2,514 2,204 2,271 3,209 2,381 2,206 2,919 2,279 1,979 FE Market Share 1.4% 1.4% 0.9% 0.4% 1.0% 2.1% 1.0% 1.2% 2.2% 1.4% 1.6% GPU Market Share 4.4% 4.4% 4.1% 4.3% 5.5% 4.8% 5.2% 10.4% 4.5% 5.5% 10.3% Merged Market Share 5.7% 5.8% 5.0% 4.8% 6.5% 6.8% 6.3% 11.7% 6.7% 6.9% 11.8% PJM-CENTINT Pre-Merger HHI 1,510 1,507 1,540 1,524 1,387 1,391 1,372 1,564 1,358 1,363 1,417 Post-Merger HHI 1,516 1,513 1,544 1,526 1,394 1,402 1,379 1,589 1,369 1,373 1,446 Change 6 6 4 2 7 11 7 26 11 10 29 FE Capacity (MW) 216 216 143 67 139 312 151 229 303 188 199 GPU Capacity (MW) 2,177 2,177 1,811 1,778 1,713 1,993 1,769 1,962 1,698 1,602 1,631 Merged Capacity (MW) 2,392 2,392 1,954 1,845 1,852 2,305 1,920 2,191 2,000 1,790 1,830 FE Market Share 0.5% 0.5% 0.4% 0.2% 0.5% 0.9% 0.5% 1.2% 1.0% 0.8% 1.3% GPU Market Share 5.3% 5.4% 4.9% 5.2% 6.7% 5.9% 6.3% 10.5% 5.5% 6.5% 10.9% Merged Market Share 5.8% 5.9% 5.3% 5.4% 7.2% 6.8% 6.8% 11.7% 6.5% 7.3% 12.2% PJM-EASTINT Pre-Merger HHI 1,490 1,477 1,490 1,463 1,301 1,224 1,262 1,667 1,309 1,223 1,432 Post-Merger HHI 1,497 1,484 1,495 1,466 1,310 1,238 1,271 1,691 1,323 1,235 1,463 Change 7 7 5 3 10 14 9 24 13 12 30 FE Capacity (MW) 216 217 144 68 129 288 135 172 286 167 173 GPU Capacity (MW) 1,863 1,864 1,509 1,486 1,433 1,669 1,460 1,757 1,417 1,339 1,467 Merged Capacity (MW) 2,079 2,081 1,653 1,555 1,563 1,957 1,595 1,929 1,703 1,507 1,640
347 Exhibit APP-316, page 5 of 5 SENSITIVITY FOR HENRY HUB GAS PRICE DECREASE BY $2
SUMMER WINTER SPRING / FALL ---------------------------------------------- ------------------------ ------------------------ Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak ------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- -------- FE Market Share 0.7% 0.7% 0.5% 0.2% 0.7% 1.1% 0.6% 1.1% 1.2% 0.9% 1.3% GPU Market Share 5.6% 5.7% 5.1% 5.2% 7.3% 6.4% 6.9% 11.1% 5.8% 7.0% 11.3% Merged Market Share 6.3% 6.3% 5.5% 5.5% 8.0% 7.5% 7.5% 12.2% 6.9% 7.8% 12.7%
348 EXHIBIT NO. APP-317 349 Exhibit APP-317, page 1 of 5 SENSITIVITY TO MOVE PEPCO SALE OUTSIDE PJM
SUMMER WINTER SPRING / FALL ---------------------------------------------- ------------------------ ------------------------ Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak ------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- -------- FE Pre-Merger HHI 5,228 5,225 5,085 4,333 3,214 4,948 4,193 4,112 4,262 3,519 3,027 Post-Merger HHI 5,242 5,240 5,101 4,369 3,268 4,985 4,235 4,271 4,297 3,562 3,202 Change 15 15 16 36 54 37 42 159 35 43 175 FE Capacity (MW) 11,798 11,788 11,090 10,101 9,965 10,789 10,162 8,175 8,360 7,847 4,973 GPU Capacity (MW) 17 18 18 43 90 41 52 163 35 50 155 Merged Capacity (MW) 11,815 11,805 11,109 10,144 10,055 10,831 10,215 8,338 8,395 7,898 5,129 FE Market Share 71.6% 71.6% 70.5% 64.8% 54.5% 69.8% 63.9% 63.1% 64.3% 57.9% 53.0% GPU Market Share 0.1% 0.1% 0.1% 0.3% 0.5% 0.3% 0.3% 1.3% 0.3% 0.4% 1.7% Merged Market Share 71.7% 71.7% 70.6% 65.1% 55.0% 70.1% 64.2% 64.3% 64.6% 58.3% 54.6% PJM Pre-Merger HHI 1,165 1,164 1,181 1,176 1,149 978 1,136 1,611 939 1,063 1,323 Post-Merger HHI 1,177 1,176 1,190 1,181 1,161 1,001 1,147 1,637 966 1,081 1,355 Change 12 12 9 5 12 23 11 26 26 18 32 FE Capacity (MW) 747 747 459 199 347 948 384 225 958 452 250 GPU Capacity (MW) 2,415 2,415 2,043 1,926 1,911 2,171 1,991 1,971 1,885 1,747 1,717 Merged Capacity (MW) 3,162 3,162 2,502 2,125 2,258 3,119 2,375 2,196 2,843 2,200 1,967 FE Market Share 1.4% 1.4% 1.0% 0.5% 1.0% 2.2% 1.0% 1.2% 2.6% 1.5% 1.5% GPU Market Share 4.4% 4.4% 4.5% 5.0% 5.7% 5.1% 5.4% 10.7% 5.1% 5.9% 10.5% Merged Market Share 5.8% 5.8% 5.6% 5.5% 6.8% 7.3% 6.5% 11.9% 7.7% 7.5% 12.0% AEP Pre-Merger HHI 2,433 2,432 2,384 2,463 3,816 2,241 2,130 2,585 1,816 1,693 2,065 Post-Merger HHI 2,433 2,433 2,385 2,463 3,817 2,241 2,130 2,591 1,816 1,694 2,078 Change 0 0 1 1 1 0 1 6 1 1 12 FE Capacity (MW) 3,012 3,011 3,019 2,968 1,664 1,613 1,694 1,591 2,436 2,558 2,403 GPU Capacity (MW) 16 17 19 23 25 24 42 330 24 43 338 Merged Capacity (MW) 3,027 3,028 3,038 2,991 1,689 1,637 1,736 1,920 2,460 2,601 2,742 FE Market Share 6.6% 6.6% 6.7% 6.7% 4.8% 3.4% 3.5% 3.9% 5.7% 5.9% 6.6% GPU Market Share 0.0% 0.0% 0.0% 0.1% 0.1% 0.0% 0.1% 0.8% 0.1% 0.1% 0.9% Merged Market Share 6.6% 6.6% 6.7% 6.8% 4.9% 3.5% 3.6% 4.7% 5.8% 6.0% 7.6%
350 Exhibit APP-317, page 2 of 5 SENSITIVITY TO MOVE PEPCO SALE OUTSIDE PJM
SUMMER WINTER SPRING / FALL ---------------------------------------------- ------------------------ ------------------------ Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak ------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- -------- APS Pre-Merger HHI 3,888 3,864 3,628 3,089 3,364 4,241 2,359 2,488 3,757 1,981 2,103 Post-Merger HHI 3,891 3,867 3,631 3,093 3,368 4,244 2,368 2,510 3,761 1,992 2,127 Change 3 3 3 5 5 4 10 22 4 11 24 FE Capacity (MW) 324 324 325 431 377 349 840 667 319 763 608 GPU Capacity (MW) 78 80 83 95 103 84 155 298 76 151 286 Merged Capacity (MW) 402 404 408 526 480 433 995 965 395 914 894 FE Market Share 2.3% 2.4% 2.5% 3.2% 3.0% 2.7% 5.1% 4.9% 2.9% 5.2% 5.1% GPU Market Share 0.6% 0.6% 0.6% 0.7% 0.8% 0.6% 0.9% 2.2% 0.7% 1.0% 2.4% Merged Market Share 2.9% 2.9% 3.1% 3.9% 3.8% 3.4% 6.1% 7.2% 3.5% 6.2% 7.4% DPL Pre-Merger HHI 7,115 7,092 6,817 5,475 3,907 5,308 3,766 2,963 4,712 3,243 2,618 Post-Merger HHI 7,115 7,092 6,817 5,476 3,908 5,308 3,767 2,967 4,713 3,244 2,624 Change 0 0 0 0 1 0 1 4 0 1 6 FE Capacity (MW) 137 137 137 211 351 234 408 475 228 397 457 GPU Capacity (MW) 0 0 0 1 3 1 2 9 1 2 12 Merged Capacity (MW) 137 137 137 212 354 235 410 484 229 399 469 FE Market Share 3.5% 3.6% 3.9% 5.8% 7.8% 6.3% 9.0% 10.0% 7.2% 10.0% 10.8% GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.1% 0.0% 0.0% 0.2% 0.0% 0.1% 0.3% Merged Market Share 3.5% 3.6% 3.9% 5.8% 7.9% 6.3% 9.0% 10.2% 7.2% 10.0% 11.1% DQE Pre-Merger HHI 6,207 6,207 6,029 3,964 5,902 3,367 3,016 2,675 3,354 3,168 3,461 Post-Merger HHI 6,207 6,207 6,029 3,965 5,903 3,369 3,020 2,741 3,356 3,173 3,540 Change 0 0 0 2 1 2 4 66 2 5 79 FE Capacity (MW) 591 591 592 1,774 604 1,348 1,714 2,101 1,597 2,031 3,021 GPU Capacity (MW) 0 0 0 1 1 2 4 38 1 3 41 Merged Capacity (MW) 591 591 593 1,775 605 1,349 1,717 2,139 1,599 2,034 3,061 FE Market Share 17.5% 17.5% 18.7% 37.6% 19.4% 27.5% 30.7% 42.6% 36.2% 40.0% 54.3% GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.1% 0.8% 0.0% 0.1% 0.7% Merged Market Share 17.5% 17.5% 18.7% 37.7% 19.5% 27.5% 30.8% 43.4% 36.3% 40.1% 55.0%
351 Exhibit APP-317, page 3 of 5 SENSITIVITY TO MOVE PEPCO SALE OUTSIDE PJM
SUMMER WINTER SPRING / FALL ---------------------------------------------- ------------------------ ------------------------ Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak ------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- -------- MECS Pre-Merger HHI 3,448 3,437 3,290 3,854 2,878 2,643 2,636 3,267 2,363 2,351 2,816 Post-Merger HHI 3,448 3,437 3,290 3,855 2,879 2,643 2,636 3,270 2,364 2,352 2,824 Change 0 0 0 0 1 0 0 2 1 1 8 FE Capacity (MW) 964 963 964 541 1,143 1,184 1,114 1,006 1,633 1,531 1,368 GPU Capacity (MW) 1 1 2 2 11 5 5 18 7 9 34 Merged Capacity (MW) 965 965 965 543 1,155 1,188 1,119 1,025 1,640 1,540 1,402 FE Market Share 4.5% 4.5% 5.5% 3.6% 7.2% 6.3% 6.5% 7.8% 9.9% 10.3% 12.2% GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.1% 0.0% 0.0% 0.1% 0.0% 0.1% 0.3% Merged Market Share 4.5% 4.5% 5.5% 3.6% 7.3% 6.3% 6.5% 7.9% 10.0% 10.4% 12.6% NYPP Pre-Merger HHI 1,166 1,158 1,173 1,064 940 1,161 1,083 1,017 1,001 956 807 Post-Merger HHI 1,166 1,158 1,173 1,064 940 1,161 1,083 1,017 1,001 956 810 Change 0 0 0 0 0 0 0 0 0 0 3 FE Capacity (MW) 10 10 12 8 17 12 8 13 46 33 51 GPU Capacity (MW) 63 64 66 71 84 47 49 107 132 150 322 Merged Capacity (MW) 73 74 78 79 101 59 57 120 178 183 373 FE Market Share 0.0% 0.0% 0.0% 0.0% 0.1% 0.1% 0.0% 0.1% 0.2% 0.2% 0.5% GPU Market Share 0.2% 0.2% 0.2% 0.3% 0.7% 0.2% 0.2% 1.0% 0.5% 0.8% 2.9% Merged Market Share 0.2% 0.2% 0.2% 0.3% 0.8% 0.3% 0.3% 1.1% 0.7% 0.9% 3.4% VEPCO Pre-Merger HHI 4,003 3,951 3,422 3,050 2,706 3,096 2,764 1,968 3,065 2,623 1,722 Post-Merger HHI 4,003 3,952 3,423 3,051 2,707 3,097 2,765 1,976 3,066 2,625 1,735 Change 1 1 1 1 1 1 1 8 1 2 12 FE Capacity (MW) 176 176 181 180 128 104 107 207 148 153 254 GPU Capacity (MW) 100 102 106 113 138 140 142 318 134 147 325 Merged Capacity (MW) 276 278 287 293 266 244 249 525 282 300 578 FE Market Share 0.8% 0.8% 0.9% 1.0% 0.8% 0.6% 0.6% 1.6% 0.9% 1.0% 2.2% GPU Market Share 0.4% 0.5% 0.5% 0.6% 0.8% 0.8% 0.8% 2.4% 0.8% 1.0% 2.8% Merged Market Share 1.2% 1.3% 1.5% 1.6% 1.6% 1.3% 1.5% 4.0% 1.7% 2.0% 5.0%
352 Exhibit APP-317, page 4 of 5 SENSITIVITY TO MOVE PEPCO SALE OUTSIDE PJM
SUMMER WINTER SPRING / FALL ---------------------------------------------- ------------------------ ------------------------ Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak ------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- -------- PJM-WESTINT Pre-Merger HHI 1,165 1,164 1,181 1,176 1,149 978 1,136 1,611 945 1,063 1,323 Post-Merger HHI 1,177 1,176 1,190 1,181 1,161 1,001 1,147 1,637 971 1,081 1,355 Change 12 12 9 5 12 23 11 26 26 18 32 FE Capacity (MW) 747 747 459 199 347 948 384 225 931 452 250 GPU Capacity (MW) 2,415 2,415 2,043 1,926 1,911 2,171 1,991 1,971 1,885 1,747 1,717 Merged Capacity (MW) 3,162 3,162 2,502 2,125 2,258 3,119 2,375 2,196 2,816 2,200 1,967 FE Market Share 1.4% 1.4% 1.0% 0.5% 1.0% 2.2% 1.0% 1.2% 2.5% 1.5% 1.5% GPU Market Share 4.4% 4.4% 4.5% 5.0% 5.7% 5.1% 5.4% 10.7% 5.1% 5.9% 10.5% Merged Market Share 5.8% 5.8% 5.6% 5.5% 6.8% 7.3% 6.5% 11.9% 7.7% 7.5% 12.0% PJM-CENTINT Pre-Merger HHI 1,509 1,509 1,552 1,463 1,482 1,316 1,459 1,611 1,297 1,367 1,433 Post-Merger HHI 1,515 1,514 1,557 1,466 1,490 1,330 1,466 1,637 1,313 1,380 1,462 Change 6 6 5 3 8 13 7 26 16 13 29 FE Capacity (MW) 217 217 148 71 138 321 153 225 316 193 198 GPU Capacity (MW) 2,179 2,179 1,818 1,717 1,717 1,929 1,773 1,971 1,635 1,537 1,642 Merged Capacity (MW) 2,396 2,396 1,966 1,788 1,855 2,251 1,926 2,196 1,950 1,729 1,840 FE Market Share 0.5% 0.5% 0.4% 0.3% 0.6% 1.1% 0.6% 1.2% 1.2% 0.9% 1.3% GPU Market Share 5.3% 5.4% 5.5% 6.1% 7.0% 6.3% 6.5% 10.7% 6.5% 7.1% 11.0% Merged Market Share 5.9% 5.9% 6.0% 6.4% 7.5% 7.4% 7.1% 11.9% 7.7% 8.0% 12.3% PJM-EASTINT Pre-Merger HHI 1,489 1,481 1,422 1,382 1,357 1,178 1,314 1,711 1,209 1,233 1,458 Post-Merger HHI 1,496 1,488 1,428 1,386 1,367 1,196 1,324 1,736 1,230 1,249 1,488 Change 7 7 6 4 10 18 9 24 21 16 30 FE Capacity (MW) 215 216 148 70 131 291 139 171 293 174 170 GPU Capacity (MW) 1,867 1,867 1,521 1,434 1,447 1,607 1,473 1,781 1,358 1,284 1,480 Merged Capacity (MW) 2,082 2,083 1,669 1,504 1,578 1,899 1,611 1,952 1,650 1,457 1,650
353 Exhibit APP-317, page 5 of 5 SENSITIVITY TO MOVE PEPCO SALE OUTSIDE PJM
SUMMER WINTER SPRING / FALL ---------------------------------------------- ------------------------ ------------------------ Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak ------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- -------- FE Market Share 0.7% 0.7% 0.6% 0.3% 0.7% 1.3% 0.7% 1.1% 1.5% 1.0% 1.3% GPU Market Share 5.7% 5.7% 5.8% 6.5% 7.5% 7.1% 7.0% 11.3% 7.0% 7.6% 11.5% Merged Market Share 6.3% 6.3% 6.3% 6.8% 8.1% 8.3% 7.7% 12.4% 8.6% 8.6% 12.8%
354 Pursuant to 18 C.F.R. Section 388.112 Privileged Information Has Been Removed