-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, U0VkAwz3scHrND6NNiU94sM+IjTVyBW+YAa4uLY6TUg75euPXXGrP+YJhmyDy/5u ns2sVnxt6db7AFpjRTVRzw== 0000061611-98-000005.txt : 19980327 0000061611-98-000005.hdr.sgml : 19980327 ACCESSION NUMBER: 0000061611-98-000005 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 1 CONFORMED PERIOD OF REPORT: 19971231 FILED AS OF DATE: 19980326 SROS: AMEX FILER: COMPANY DATA: COMPANY CONFORMED NAME: MAINE PUBLIC SERVICE CO CENTRAL INDEX KEY: 0000061611 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 010113635 STATE OF INCORPORATION: ME FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: SEC FILE NUMBER: 001-03429 FILM NUMBER: 98573641 BUSINESS ADDRESS: STREET 1: 209 STATE ST CITY: PRESQUE ISLE STATE: ME ZIP: 04769-1209 BUSINESS PHONE: 2077685811 MAIL ADDRESS: STREET 1: PO BOX 1209 CITY: PRESQUE ISLE STATE: ME ZIP: 04769-1209 10-K 1 SECURITIES AND EXCHANGE COMMISSION Washington, D. C. 20549 FORM 10-K ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 1997. Commission File No. 1-3429 Maine Public Service Company (Exact name of registrant as specified in its charter) Maine 01-0113635 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 209 State Street, Presque Isle, Maine 04769 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code 207-768-5811 Securities registered pursuant to Section 12(b) of the Act: Name of each exchange Title of each class on which registered Common Stock, $7.00 par value American Stock Exchange Securities registered pursuant to Section 12(g) of the Act: None Title of Class Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X . No . Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ] Aggregate market value of the voting stock held by non-affiliates at March 26, 1998: $22,540,422. The number of shares outstanding of each of the issuer's classes of common stock as of March 26, 1998. Common Stock, $7.00 par value - 1,617,250 shares DOCUMENTS INCORPORATED BY REFERENCE 1. The Company's 1997 Annual Report to Stockholders is incorporated by reference into Parts I, II and IV. 2. The Company's definitive proxy statement, to be filed pursuant to Regulation 14A no later than 120 days after December 31, 1997, which is the end of the fiscal year covered by this report, is incorporated by reference into Part III. (Page 1 of 44 pages) PART I Form 10-K Item 1. Business General The Company was originally incorporated as the Gould Electric Company in April, 1917 by a special act of the Maine legislature. Its name was changed to Maine Public Service Company in August, 1929. Until 1947, when its capital stock was sold to the public, it was a subsidiary of Consolidated Electric & Gas Company. Maine and New Brunswick Electrical Power Company, Limited, the Company's wholly-owned Canadian subsidiary (the "Subsidiary") was incorporated in 1903 under the laws of the Province of New Brunswick, Canada. The properties of the Company and Subsidiary are operated as a single integrated system. The Company engages in the production, transmission and distribution of electric energy to retail and wholesale customers in all of Aroostook County and a small portion of Penobscot County in northern Maine. Geographically, the service territory is approximately 120 miles long and 30 miles wide, with a population of approximately 82,000. The service area of the Company includes one of the most important potato growing and processing sections in the United States. In addition, the area produces wood products, principally pulp wood for paper manufacturing. The Subsidiary is primarily a hydro-electric generating company. It owns and operates the Tinker hydro plant in New Brunswick, Canada, and sells to the Company the energy not needed to supply its wholesale New Brunswick customer. During 1997, sales to the Company amounted to 77,323 MWH out of the 102,681 MWH generated for sale at Tinker. As discussed further in Items 3(a) and (b) of the "Legal Proceedings" section of this Form 10-K, the Company is proceeding with the sale of generating assets in accordance with Maine's new electric utility deregulation law. -2- Form 10-K PART I Item 1. Business - Continued The Company and the Subsidiary's net energy production, including generated and purchased power, required to serve all customers, was 630,457 MWH for the twelve months ended December 31, 1997. The following table sets forth the sources from which the Company and the Subsidiary obtained their power requirements in 1997. 1997 Megawatt-hours Generated Sources of Power or Purchased Net Generation: Hydro 107,734 Steam 26,758 Diesel (429) Total 134,063 Purchases: Nuclear Generated 0 Fossil Fuel Generated 371,689 Biomass Generated 125,199 Total 496,888 Inadvertent Received (494) Total System 630,457 As of June 4, 1984, the Company entered into a Power Purchase Agreement (PPA) with Sherman Power Company, which assigned its interest in the Agreement to Wheelabrator-Sherman Energy Company (W-S), formerly Signal-Sherman Energy Company, (a cogenerator), for 17.6 MW of capacity which began July, 1986. The current contract expires in 2001. As explained in Item 3(e) of the "Legal Proceedings" section of this Form 10-K, the Company and W-S have agreed to a restructuring of the PPA. The amended agreement, approved by the MPUC, should help relieve financial pressure caused by the recent closure of Maine Yankee and help avoid substantial increases in the Company's retail rates. The Board of Directors of the Finance Authority of Maine (FAME) has authorized the issuance and sale of securities which will be used for an up-front payment to W-S. The Company expects that the financing will be completed during the second quarter of 1998. -3- Form 10-K PART I Item 1. Business - Continued Financial Information about Foreign and Domestic Operations Financial Information Relating To Foreign and Domestic Operations (In Thousands of U.S. Dollars) 1997 1996 1995 Revenues from Unaffiliated Customers: Company-United States 54,291 56,521 54,585 Subsidiary-Canada 781 743 694 Intercompany Revenues: Company-United States 728 683 719 Subsidiary-Canada 1,672 2,424 1,877 Operating Income: Company-United States 567 4,585 3,997 Subsidiary-Canada 344 703 367 Income (Loss) before Extraordinary Items Company-United States (2,521) 1,366 503 Subsidiary-Canada 344 745 418 Extraordinary Items, Net of Tax Company-United States - - (6,236) Net Income (Loss) Company-United States (2,521) 1,366 (5,733) Subsidiary-Canada 344 745 418 Identifiable Assets: Company-United States 156,207 109,891 107,138 Subsidiary-Canada 7,274 6,823 6,936 The identifiable assets, by company, are those assets used in each company's operations, excluding intercompany receivables and investments. -4- Form 10-K PART I Item 1. Business - Continued Source of Revenues In 1997, consolidated operating revenues totaled $55,072,196. The percentages of revenues derived from customer classes are as follows: % Residential 37.0 Small Commercial and Industrial 31.6 Large Commercial and Industrial 17.2 Public Authorities 1.2 Sales to Wholesale Customers for Resale 3.9 Other Sales and Other Revenues 9.1 Total 100.0 Sales to wholesale customers for resale includes two wholesale customers that entered into various contracts with the Company in 1996. These contracts contained rates lower than those typically allowed under FERC's traditional ratemaking. Capitalizing on the availability of low cost power in New England, the wholesale customers issued a request for proposal in September, 1994 for their purchased power requirements effective January 1, 1996. Houlton Water Company (Houlton), selected an offer from another utility, and began taking service from that utility starting January 1, 1996. In 1995, sales to Houlton, under an earlier contract, represented 11.1% of the Company's consolidated MWH sales and 8.4% of consolidated operating revenues, making Houlton the Company's largest customer for 1995. The remaining wholesale customers, Van Buren Light and Power District (Van Buren) and Eastern Maine Electric Cooperative, Inc. (EMEC) selected the Company's six-year proposal, which cannot be terminated before December 31, 1998. The new rates for these two customers were effective January 1, 1995. Van Buren and EMEC represented 4.5% of consolidated MWH sales and 2.5% of consolidated operating revenues for the year ended December 31, 1997. During 1996 and 1997, the Company entered into long-term power contracts with five of its largest customers. In exchange for discounts from the Company's standard rates, these customers agreed to purchase all of their electrical requirements from the Company through the year 2000. All five of these customers produced evidence of hardship to continue operations in the area or were investigating self generation, criteria that the Maine Public Utilities Commission (MPUC) reviewed before approving these load-retention contracts. On November 13, 1995, the Maine Public Utilities Commission approved a Stipulation signed by Maine Public Service Company, the -5- Form 10-K PART I Item 1. Business - Continued Commission Staff and the Maine Public Advocate. This Stipulation, which became effective January 1, 1996, established a multi-year rate plan for the Company that will provide our customers with predictable rates through 1999 and shares operating risks and benefits between the Company's shareholders and customers. For more information on the rate plan, see Item 3(g) of the "Legal Proceedings" section of this Form 10- K. For additional discussion on revenues, see the 1997 Annual Report to Stockholders, pages 4 and 5, "Analysis of Financial Condition and Review of Operations-Operating Revenues and Energy Sales" and pages 9 to 11, "Regulatory Proceedings", which information is incorporated herein by reference. Regulation and Rates The Company is subject to the regulatory authority of the Maine Public Utilities Commission (MPUC) as to retail rates, accounting, service standards, territory served, the issuance of securities and various other matters. With respect to wholesale rates and certain other matters, the Company is or may be subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC). The Company maintains its accounts in accordance with the accounting requirements of the FERC which generally conform with the accounting requirements of the MPUC. At this time, the Company is not subject to the Public Utilities Regulatory Policies Act of 1978 ("PURPA") because it has not exceeded the threshold of 2,000,000,000 kilowatt-hours excluding wholesale sales. However, the Maine Legislature has by statute instructed the MPUC that it may consider PURPA standards in rate proceedings before that Commission. The generating facilities of the Company and Subsidiary meet the applicable current environmental regulations of State and Federal governments of the United States and Provincial and Dominion governments of Canada, except for the three diesel stations (12 MW) and the oil- fired generating plant located in Caribou, Maine (23 MW). As discussed in Item 2. "Properties" below, the oil-fired Steam Units 1 and 2 at the Caribou facility have been placed on an inactive status. The Maine Department of Environmental Protection (DEP), in response to the Company's application for air emission licenses, has indicated that the application did not demonstrate that Ambient Air Quality Standards and Increments will not be violated. With the cooperation of the DEP Staff, the Company is studying what steps, if any, are required for licensing, and cannot determine at this time what, if any, additional capital expenditures may be required. As discussed in Items 3(a) and (b) of the "Legal Proceedings" section of this Form 10-K, the Company is proceeding -6- Form 10-K PART I Item 1. Business - Continued with the sale of generating assets in accordance with Maine's new electric deregulation law. See the 1997 Annual Report to Stockholders, pages 9 to 11, "Analysis of Financial Condition and Review of Operations - Regulatory Proceedings", which information is incorporated herein by reference, for additional information on regulatory matters. Franchises and Competition Except for consumers served at retail by the Company's wholesale customers, the Company has practically an exclusive franchise to provide electric energy in the Company's service area. For additional information on changes to the future structure of the electric utility industry in Maine, see Item 3(a) of the "Legal Proceedings" section of this Form 10-K. Employees The information with respect to employees is presented in the 1997 Annual Report to Stockholders, page 9, "Employees", which information is incorporated herein by reference. Subsidiaries and Affiliated Companies The Company owns 100% of the Common Stock of Maine and New Brunswick Electrical Power Company, Limited (the Subsidiary). The Subsidiary owns and operates the Tinker Station located in the Province of New Brunswick, Canada. The Tinker Station has five hydro units with total capacity of 33,500 kilowatts and a small diesel unit of 1,000 kilowatts. The Subsidiary serves the community of Perth-Andover in New Brunswick, with the remaining energy exported to the Parent Company in Maine under license of the National Energy Board of Canada. On June 16, 1988, the export license was renewed to 2008. The Company owns 5% of the Common Stock of Maine Yankee, which operated an 860 MW nuclear power plant (the "Plant") in Wiscasset, Maine. On August 6, 1997, the Board of Directors of Maine Yankee voted to permanently cease power operations and to begin decommissioning the Plant. The Plant experienced a number of operational and regulatory problems and has been shut down since December 6, 1996. The decision to close the Plant permanently was based on an economic analysis of the costs, risks and uncertainties associated with operating the Plant compared to those associated with closing and decommissioning it. The Plant's operating license from the Nuclear Regulatory Commission (NRC) was due to expire on October 21, 2008. -7- Form 10-K PART I Item 1. Business - Continued The Plant generally provided reliable and low-cost power from the time it commenced operations in late 1972 to 1995. Beginning in early 1995, however, Maine Yankee encountered various operational and regulatory difficulties with the Plant. In 1995, the Plant was shut down for almost the entire year to repair a large number of steam generator tubes that were exhibiting defects. Shortly before the Plant was to go back on-line in December 1995, a group with a history of opposing nuclear power released an undated, unsigned, anonymous letter alleging that in 1988 Yankee Atomic (then an affiliated consultant of Maine Yankee) and Maine Yankee had used the results of a faulty computer code as a basis to apply to the NRC for an increase in the Plant's power output. In response to the allegation, on January 3, 1996, the NRC issued a Confirmatory Order that restricted the Plant to 90 percent of its licensed thermal operation level, which restriction was still in effect when the Plant was permanently shut down. As a result of the controversy associated with the allegations, the NRC, at the request of the Governor of Maine, conducted an intensive Independent Safety Assessment (ISA) of the Plant in the Summer and Fall of 1996. On October 7, 1996, the NRC issued its ISA report, which found that while the Plant had been operated safely, there were weaknesses that needed to be addressed, which would require substantial additional spending by Maine Yankee. On December 10, 1996, Maine Yankee responded to the ISA report, acknowledged many of the weaknesses, and committed to revising its operations and procedures to address the NRC's criticisms. Another result of the controversy associated with the allegations was an investigation of Maine Yankee initiated by the NRC's Office of Investigations (OI), which, in turn, referred certain issues to the United States Department of Justice (DOJ) for possible criminal prosecution. Subsequently, on September 27, 1997, the DOJ, through the United States Attorney for Maine, announced that its review had revealed no grounds for criminal prosecution. The Company believes that the OI investigation, however, could ultimately result in the imposition of civil penalties, including fines, on Maine Yankee. In 1996, the Plant was generally in operation at the 90-percent level from late January to early December, except for a two-month outage from mid-July to mid-September. The Plant was shut down again on December 6, 1996, to address several concerns, and has not operated since then. The precipitating event causing the shutdown was the need to evaluate and resolve cable-separation compliance issues, and on December 18, 1996, the NRC issued a Confirmatory Action Letter requiring the Plant to remain shut down until Maine Yankee's plan for resolving the cable-separation issues was accepted by the NRC. Subsequently, Maine Yankee uncovered additional issues, including among others the -8- Form 10-K PART I Item 1. Business - Continued possibility of having to replace defective fuel assemblies, address additional cable-separation issues, and determine the condition of the Plant's steam generators, all of which contributed to further operational uncertainty. On January 29, 1997, the Plant was placed on the NRC's Watch List, and on January 30, 1997, the NRC issued a supplemental Confirmatory Action Letter requiring the resolution of additional concerns before the Plant could be restarted. In December 1996, Maine Yankee requested proposals from several utilities with large and successful nuclear programs to provide a management team, and ultimately contracted with Entergy Nuclear, Inc., effective February 13, 1997, for management services that included providing a new president and regulatory compliance officer. The Entergy-provided management team made progress in addressing technical issues, but a number of operational and regulatory uncertainties remained. On May 27, 1997, the Board of Directors of Maine Yankee voted to minimize spending while preserving the options of restarting the Plant or conveying ownership interests to a third party. After unsuccessful negotiations with one prospective purchaser, Maine Yankee found no other interest in purchasing the Plant and, based on its economic analysis, closed the Plant permanently. As required by the NRC, on August 7, 1997, Maine Yankee certified to the NRC that Maine Yankee had permanently ceased operations and that all fuel assemblies had been permanently removed from the Plant's reactor vessel. On August 27, 1997, Maine Yankee filed the required Post-Shutdown Activities Report with the NRC, describing its planned post-shutdown activities and a proposed schedule. The Company's 5% ownership interest in Maine Yankee's common equity amounted to $4.0 million as of December 31, 1997, and under Maine Yankee's Power Contracts and Additional Power Contracts, the Company is responsible for 5% of the costs of decommissioning the Plant. Maine Yankee's most recent estimate of the cost of decommissioning is $380.4 million, based on a 1997 study by an independent engineering consultant, plus estimated costs of interim spent-fuel storage of $127.6 million, for an estimated total cost of $508 million (in 1997 dollars). The previous estimate for decommissioning, by the same consultant, was $316.6 million (in 1993 dollars). On September 1, 1997, Maine Yankee estimated the sum of the future payments for the closing, decommissioning and recovery of the remaining investment in Maine Yankee to be approximately $930 million, of which the Company's 5% share would be approximately $46.5 million. Legislation enacted in Maine in 1997 calling for restructuring the electric utility industry provides for recovery of decommissioning costs, to the extent -9- Form 10-K PART I Item 1. Business - Continued allowed by federal regulation, through the rates charged by the transmission and distribution companies. Based on the Maine legislation and regulatory precedent established by the FERC in its opinion relating to the decommissioning of the Yankee Atomic nuclear plant, the Company believes that it is entitled to recover substantially all of its share of such costs from its customers and, as of December 31, 1997, is carrying on its consolidated balance sheet a regulatory asset and a corresponding liability in the amount of $43.4 million, which is the $46.5 million discussed above net of the Company's post-September 1, 1997 cost-of-service payments to Maine Yankee. On September 2, 1997, the MPUC released the report of a consultant it had retained to perform a management audit of Maine Yankee for the period January 1, 1994, to June 30, 1997. The report contained both positive and negative conclusions, the latter including: that Maine Yankee's decision in December 1996 to proceed with the steps necessary to restart the Plant was "imprudent", that Maine Yankee's May 27, 1997 decision to reduce restart expenses while exploring a possible sale of the Plant was "inappropriate", based on the consultant's finding that a more objective and comprehensive competitive analysis at that time "might have indicated a benefit for restarting" the Plant; and that those decisions resulted in Maine Yankee incurring $95.9 million in "unreasonable" costs. The Company has expensed its share of these costs. On October 24, 1997, the MPUC issued a Notice of Investigation initiating an investigation of the shutdown decision and of the operation of the Plant prior to shutdown, and announced that it had directed its consultant to extend its review to include those areas. The Company does not know how the MPUC plans to use the consultant's report, but believes the report's negative conclusions are unfounded and may be contradictory. The Company believes it would have substantial constitutional and jurisdictional grounds to challenge any effort in an MPUC proceeding to alter wholesale Maine Yankee rates made effective by the FERC. On November 7, 1997, Maine Yankee and Central Maine Power initiated a legal challenge to the MPUC investigation in the Maine Supreme Judicial Court alleging that such an investigation falls exclusively within the jurisdiction of the FERC and that the MPUC investigation is therefore barred on constitutional grounds. The Company joined in this appeal. The MPUC subsequently stayed its investigation pending the outcome of Maine Yankee's FERC rate case, while indicating that its consultant would continue its extended review. The Maine Supreme Court, on motions of the parties, stayed the appeal pending resolution of the FERC proceeding. During 1997, the Company incurred Maine Yankee replacement power costs of approximately $7,302,000, of which $2,324,000 has been deferred under the Company's rate stabilization plan, and also incurred -10- Form 10-K PART I Item 1. Business - Continued additional operating costs of approximately $3.0 million associated with the efforts to restart and subsequently close Maine Yankee, which have adversely impacted the Company's earnings. The February 1, 1998, rate increase, as described in Item 3(g) of the "Legal Proceedings" section of this Form 10-K, included a portion of these recoverable 1997 Maine Yankee replacement power costs with the remaining costs included in the February 1, 1999 rate increase. However, the collection of future Maine Yankee replacement power costs will be subject to the MPUC's previously-mentioned prudence review of the prudency of closing Maine Yankee. The Company also owns 7.49% of the Common Stock of Maine Electric Power Company, Inc. (MEPCO). MEPCO owns and operates a 345-KV (kilovolt) transmission line about 180 miles long which connects the New Brunswick Power (NB Power) system with the New England Power Pool. The MEPCO transmission line is also the path by which Wyman No. 4 energy is delivered northerly into the NB Power system and then wheeled to the Parent Company through its interconnection with NBEPC at the international border. On December 23, 1997, the Company announced the signing of three separate energy agreements to purchase firm energy and capacity from Hydro-Quebec (H-Q) and Alternative Energy, Inc.'s Beaver Power Plant in Ashland, Maine (AEI) for the replacement of Maine Yankee power, and to market surpluses in partnership with Cinergy, an electric utility headquartered in Cincinnati, Ohio. However, the Company and H-Q were unable to agree on final terms and conditions and agreed to terminate their energy agreement effective March 13, 1998. The Company is negotiating an agreement with NB Power to supply additional energy not provided by AEI to service our customers. The Company and Cinergy will continue their efforts to jointly market available power in Maine and New England. -11- Form 10-K PART I Item 1. Business - Continued Executive Officers The executive officers of the registrant are as follows: Office Continuously Name Age Held Since Paul R. Cariani President and Chief 57 6/1/94 Executive Officer Frederick C. Bustard Vice President, 60 6/1/96 Power Supply & Environment Larry E. LaPlante Vice President, 46 6/1/96 Finance, Administration and Treasurer Stephen A. Johnson Vice President, 50 6/1/90 Customer Service and General Counsel Secretary and Clerk Paul R. Cariani has been an employee of the Company since November 1, 1977, starting as an Assistant to the Treasurer. In May 1978, he was appointed Assistant Treasurer until his election as Treasurer, Secretary and Clerk, on March 1, 1983. In May 1985, he was elected Vice President-Finance and Treasurer effective June 1, 1985. On February 25, 1992, Mr. Cariani was elected a Director of the Company to fill an existing vacancy on the Board. On May 11, 1993, he was elected Executive Vice President, Chief Financial Officer and Treasurer, effective June 1, 1993. Effective June 1, 1994, he was elected President and CEO, replacing the retiring G. Melvin Hovey. Mr. Hovey remains Chairman of the Board of Directors. Frederick C. Bustard was elected to the position of Vice President, Power Supply & Environment effective June 1, 1996. He has been a full- time employee of the Company since June 15, 1959 in various engineering capacities until July 1, 1980, when he was appointed Assistant to the President. On June 1, 1983, he was elected Vice President, Engineering & Operations. On September 1, 1988, he was elected to the new position of Vice President of Customer Service and Division Operations, a position he held until his reappointment to Vice President of Engineering & Operations on June 1, 1990. -12- Form 10-K PART I Item 1. Business - Continued Larry E. LaPlante was elected to the position of Vice President, Finance, Administration and Treasurer on June 1, 1996. He has been an employee of the Company since November 4, 1983, starting as Controller. In May, 1984, he was also appointed Assistant Secretary and Assistant Treasurer until his election as Vice President, Finance and Treasurer effective June 1, 1994. Stephen A. Johnson was elected to the new position of Vice President, Customer Service and General Counsel, effective June 1, 1990. Mr. Johnson also continues in his capacity as Secretary and Clerk of the Company, a position he has held since June 1, 1985. Mr. Johnson was appointed General Counsel of the Company on March 5, 1985. On September 1, 1988, he was elected Vice President of Administration and General Counsel, a position he held until his election as Vice President, Customer Service and General Counsel. Prior to joining the Company Mr. Johnson was the General Counsel of the Maine Public Advocate Office from 1983 to 1985 and prior to that was a Staff Attorney of the Maine Public Utilities Commission. Each executive office is a full-time position and has been the principal occupation of each officer since first elected. All officers were elected to serve until the next annual election of officers and until their successors shall have been duly chosen and qualified. The next annual election of officers will be on May 12, 1998. There are no family relationships among the executive officers. -13- Form 10-K PART I Item 2. Properties The Company owns and operates electric generating facilities consisting of: oil-fired steam units with a total capability of 23,000 kilowatts, diesel generation totaling 12,300 kilowatts, and hydro- electric facilities of 2,300 kilowatts. The Subsidiary owns and operates a hydro-electric plant of 33,500 kilowatts and a small diesel unit with 1,000 kilowatt capacity. As discussed in Items 3(a) and (b) of the "Legal Proceedings" section of this Form 10-K, the Company is proceeding with the sale of generating assets in accordance with the State's new electric deregulation law. The Board of Directors authorized placing on inactive status Steam Units 1 and 2 of the Company's Caribou Generating Facility in Caribou, Maine effective January 1, 1996 and were expected to remain inactive for five years or longer. These two units, which represent 23 MW of capacity, have become surplus to the Company's needs due to the closure of Loring Air Force Base and the loss in 1996 of the Company's largest customer, the Houlton Water Company. During the Units' inactive period, the plant equipment will be protected and maintained by the installation of a dehumidification system that will permit the Plant to return to service in approximately six months. Steam Unit No. 1 went into operation in the early 1950s and Unit No. 2, in the mid 1950s. The Company still has a diesel generation station of approximately 7 MW and a hydro facility of approximately 1 MW and will continue to employ 11 employees at the Caribou facility. As of December 31, 1997, the Company and Subsidiary had approximately 443 pole miles of transmission lines and the Company owned approximately 1,608 miles of distribution lines. The Company is a part-owner of a 600,000 kilowatt oil-fired steam unit built by Central Maine Power Company at its Wyman Station in Yarmouth, Maine. The Company's share of that unit is 3.3455%, or approximately 20,000 kilowatts. Substantially all of the properties owned by the Company are subject to the liens of the First and Second Mortgage Indentures and Deeds of Trust. -14- Form 10-K PART I Item 3. Legal Proceedings (a) Restructuring of Maine's Electric Utility Industry. In the Company's Form 10-K for December 31, 1996 as well as the Form 10-Q for the quarter ended June 30, 1997, the Company described electric utility restructuring efforts in Maine, including the Maine Public Utilities Commission's (MPUC) recommendation to the legislature. After months of hearings and deliberations, the Maine legislature passed L.D. 1804, "An Act to Restructure the State's Electric Industry", which the Governor signed into law on May 29, 1997. The principal provisions of the new law are as follows: 1) Beginning on March 1, 2000, all consumers of electricity have the right to purchase generation services directly from competitive electricity suppliers who will not be subject to rate regulation. 2) By March 1, 2000, the Company, Central Maine Power Company (CMP) and Bangor Hydro-Electric Company (BHE) must divest of all generation related assets and business functions except for: (a) contracts with qualifying facilities, such as the Company's power contract with Wheelabrator-Sherman (W-S), and conservation providers; (b) nuclear assets, namely, the Company's investment in the Maine Yankee Atomic Power Company, however, the MPUC may require divestiture on or after January 1, 2009; (c) facilities located outside the United States, i.e., the Company's hydro facility in New Brunswick, Canada; and (d) assets that the MPUC determines necessary for the operation of the transmission and distribution services. The MPUC can grant an extension of the divestiture deadline if the extension will improve the selling price. For assets not divested, the utilities are required to sell the rights to the energy and capacity from these assets. See item (b) below regarding the divestiture of the Company's generating assets. 3) Billing and metering services will be subject to competition beginning March 1, 2002, but permits the MPUC to establish an earlier date, no sooner than March 1, 2000. -15- Form 10-K PART I Item 3. Legal Proceedings - Continued 4) The Company, through an unregulated affiliate, may market and sell electricity both within and outside its current service territory, without limitation. Both CMP and BHE are limited to 33% of the load within their respective service territories, but may sell an unlimited amount outside their service territories. Consumer-owned utilities are allowed to market and sell within their service territories, but the MPUC can limit or prohibit competition in their service territory, if the tax-exempt status of the consumer-owned utility is threatened. 5) The Company, through a regulated affiliate, will continue to provide transmission and distribution services which will be subject to continued regulation by the MPUC. 6) Maine electric utilities will be permitted a reasonable opportunity to recover legitimate, verifiable and unmitigable costs that are otherwise unrecoverable as a result of retail competition in the electric utility industry. The MPUC shall determine these stranded costs by considering: a) the utility's regulatory assets related to generation, i.e., the Company's unrecovered Seabrook investment; b) the difference between net plant investment in generation assets compared to the market value for those assets; and c) the difference between future contract payments and the market value of the purchased power contracts, i.e., the W-S contract. By July 1, 1999, the MPUC will have estimated the stranded costs for the Company and the manner for the collection of these costs by the transmission and distribution company. Customers reducing or eliminating their consumption of electricity by switching to self-generation, conversion to alternative fuels or utilizing demand-side management measures cannot be assessed exit or entry fees. The Company estimates its stranded costs to be approximately $85 million, based on the completion of the W-S contract restructuring, market power estimates beyond 2000 and regulatory treatment of the Company's remaining Seabrook investment, but does not include any benefits from the Company's sale of generating assets. The MPUC shall include in the rates charged by the -16- Form 10-K PART I Item 3. Legal Proceedings - Continued transmission and distribution utility decommissioning expenses for Maine Yankee. In 2003 and every three years thereafter until the stranded costs are recovered, the MPUC shall review and revaluate the stranded cost recovery. 7) All competitive providers of retail electricity must be licensed and registered with the MPUC and meet certain financial standards, comply with customer notification requirements, adhere to customer solicitation requirements and are subject to unfair trade practice laws. Competitive electricity providers must have at least 30% renewable resources in their energy portfolios, including hydro-electric generation. 8) A standard-offer service will be available, ensuring access for all customers to reasonably priced electric power. Unregulated affiliates of CMP and BHE providing retail electric power are prohibited from providing more than 20% of the load within their respective service territories under the standard offer service, while any unregulated affiliate of the Company does not have a similar restriction. 9) Unregulated affiliates of CMP and BHE marketing and selling retail electric power must adhere to specific codes of conduct, including, among others: a) employees of the unregulated affiliate providing retail electric power must be physically separated from the regulated distribution affiliate and cannot be shared; b) the regulated distribution affiliate must provide equal access to customer information; c) the regulated distribution company cannot participate in joint advertising or marketing programs with the unregulated affiliate providing retail electric power; d) the distribution company and its unregulated affiliated provider of retail electric power must keep separate books of accounts and records; and (e) the distribution company cannot condition or tie the provision of any regulated service to the provision of -17- Form 10-K PART I Item 3. Legal Proceedings - Continued any service provided by the unregulated affiliated provider of electricity. The MPUC shall determine the extent of separation required in the case of the Company to avoid cross- subsidization and shall consider all similar relevant issues as well as the Company's small size. 10) Employees, other than officers, displaced as a result of retail competition will be entitled to certain severance benefits and retraining programs. These costs will be recovered through charges collected by the regulated distribution company. 11) Other provisions of the new law include provisions for: a) consumer education; b) continuation of low-income programs and demand side management activities; c) consumer protection provisions; d) new enforcement authority for the MPUC to protect consumers. The MPUC will conduct several rulemaking proceedings associated with the new restructuring law. The Company is presently reviewing its business operations and the opportunities that the new restructuring law presents. (b) Maine Public Service Company, Divestiture of Generation Assets, MPUC Docket No. 97-670 As reported in item (a) above, the Company is required to obtain the MPUC's approval of a plan to divest itself of all its generation assets by January 1, 1999. On September 9, 1997, the Company, pursuant to this Legislation, submitted to the MPUC its plan for divesting itself of all its power entitlements and generation assets, including its Canadian subsidiary. A hearing was held on this plan on December 18, 1997. By Order issued February 20, 1998, the MPUC approved the Company's plan and ordered it to proceed to divest itself of its generation assets in accordance with the plan. Any final sale of the Company's generation assets must be approved by the MPUC. In its Order approving the divestiture -18- Form 10-K PART I Item 3. Legal Proceedings - Continued plan, the MPUC noted a number of concerns that it would address when the final sale was brought before it for approval. These concerns included whether the sale of the assets of the Canadian subsidiary should be delayed pending the development of a retail market for electricity in Canada or until the MPUC completes its final study on the efficiency of competitive markets in northern Maine (see item (c) below) and whether any sale would create, or exacerbate, a concentration of generation market power to the detriment of MPS's customers. MPS has received and reviewed bids for its generation assets and power entitlements and is now in the process of negotiating the terms of sale with the successful bidders. The Company cannot predict the exact terms of any final sale of these properties nor whether, or under what terms, that sale will be approved by the MPUC. (c) Interim Report by the Maine Public Utilities Commission and the Maine Attorney General Regarding Market Power Issues Raised by the Prospect of Retail Competition in the Electric Industry, MPUC Docket No. 97-877 The Legislation described in item (a) above required the Maine Department of the Attorney General and the MPUC to jointly conduct a study of the various market power issues presented by the introduction of retail competition into Maine's electric utility industry. A final report in this matter is due by December 31, 1998. On February 2, 1998, the MPUC and the Attorney General issued its interim report in this matter. This interim report did not reach any final conclusion or make any recommendations, but did note certain areas of concern. Among the principal areas of concern are: - whether the proposed regulation of transactions between a utility and its marketing affiliate will be sufficient to prevent market dominance by the affiliate or whether an outright ban on affiliate marketing is preferable. - that "special circumstances" in the Company's service territory (such as its direct physical isolation from the New England power grid) indicates that it may be subject to a high degree of market power. Accordingly, the interim report noted, without further elaboration, that -19- Form 10-K PART I Item 3. Legal Proceedings - Continued the Final Report would "evaluate several possible legislative adjustments". In a related matter, and again as required by the Legislation described in item (a), the MPUC, on January 26, 1998, opened an investigation into the feasibility of a direct physical interconnection between the Company's service territory and the New England power grid (MPUC Docket No. 97-586). The MPUC expects to issue a draft report on this matter by December 1, 1998. The Company will be directly involved in this investigation. The Company cannot at this time predict either the ultimate conclusions of the studies described above or the effect of these studies upon the proposed sale of the Company's generation assets or the prospect of retail competition in the Company's service territory. (d) Maine Public Service Company, Request For Open Access Transmission Tariff, FERC Docket No. ER 95-836-000. On March 31, 1995, the Company filed an open access transmission tariff with the Federal Energy Regulatory Commission (FERC). This tariff provides fees for various types and levels of transmission and transmission-related services that are required by transmission customers. The tariff, as filed, substantially increases some of the fees for transmission services and provides separate fees for various transmission-related services. On May 31, 1995, the FERC approved the filed tariff, subject to refund. The filing has been vigorously contested by the Company's wholesale customers. On May 31, 1996, the FERC issued Order 888, a final rule on open transmission access and stranded cost recovery. As a result the Company has refiled its tariff to comply with the Order. A decision by the FERC regarding the fees under the Company's tariff is not expected until later in 1998. The Company cannot predict the FERC's ultimate decision in this matter. (e) Restructured Purchase Power Agreement with Wheelabrator- Sherman The Company has a Power Purchase Agreement (PPA) with the Wheelabrator-Sherman Energy Company (W-S) under which the Company is obligated to purchase the entire output (up to 126,582 MWH) of a 17.6 MW biomass plant owned by W-S. The -20- Form 10-K PART I Item 3. Legal Proceedings - Continued current term of the PPA runs through December 31, 2000 and may be renewed by either party for an additional fifteen years at prices to be determined by mutual agreement or, absent mutual agreement, by the MPUC. On October 15, 1997, the Company and W-S agreed to amend the PPA. Under the terms of this amendment, W-S has agreed to reductions in the price of purchased power of approximately $10 million over the PPA's current term in exchange for up- front payments of $8.7 million. The Company and W-S have also agreed to renew the PPA for an additional six years at agreed- upon prices. The Company believes the amended PPA will help relieve the financial pressure caused by the recent closure of Maine Yankee as well as the need for substantial increases in its retail rates, and is therefore in the best interests of the Company, its customers and shareholders. In order to finance the upfront payment to W-S, the Company concluded that it must obtain funds from the Finance Authority of Maine (FAME); absent FAME financing the Company does not believe it can obtain the funds on terms sufficiently economic to justify the arrangement with W-S. The amended PPA must be approved by the MPUC if FAME financing is to be obtained. The Company's request for this approval was given the MPUC Docket No. 97-727. The Company also asked the MPUC for a determination that any so-called stranded costs created by the amended PPA will be recoverable from customers to the extent permitted by Maine law. On December 22, 1997, the MPUC approved the amended PPA and determined that the additional costs created by the amended PPA will be treated as stranded cost. On February 19, 1998, the FAME Board of Directors voted to provide the Company with the financing necessary to support the amended PPA. The Company is now in the process of negotiating the precise terms of this financing and expects to actually implement the restructured PPA by May 1, 1998, but cannot predict the exact timing or the terms and conditions of the necessary financing. (f) Maine Public Utilities Commission Investigation of the Operation and Shutdown of Maine Yankee Atomic Power Company Generating Facility in Wiscasset, Maine, MPUC Docket No. 97- 781 On October 24, 1997, the MPUC issued a Notice of Investigation regarding the August, 1997 shutdown of the Maine Yankee Power -21- Form 10-K PART I Item 3. Legal Proceedings - Continued Plant (see Item 1. "Subsidiaries and Affiliated Companies", above). The MPUC stated that the "permanent shutdown of the plant presents significant ratemaking issues" such as replacement power costs and stranded cost issues, for all three of Maine Yankee's Maine owners. The announced scope of the investigation is therefore intended to focus on "two separate generic prudence questions .... presented in determining the reasonableness of increased purchased power costs and reasonableness of the recovery of the unamortized Maine Yankee investment: 1. Was the decision to shut down the Maine Yankee Plant prudent? 2. Was the plant prematurely shut down because the plant had been operated or was operating imprudently?" As an owner of Maine Yankee, the Company was made a party to this investigation. The Company believes the MPUC's jurisdiction over Maine Yankee costs and prudence issues is preempted by the Federal Power Act and FERC jurisdiction. If, however, the MPUC should successfully assert jurisdiction over these issues and, if it disallowed substantial amounts of the Maine Yankee-related expenses in retail rates, the effect on the Company's financial condition would be material and adverse. On November 7, 1997, Central Maine Power and Maine Yankee initiated legal challenges to the MPUC investigation in the Maine Supreme Judicial Court alleging that such an investigation falls exclusively within the jurisdiction of the FERC, and that the MPUC's investigation is therefore barred on constitutional grounds. The Company joined that appeal on November 13, 1997. On December 2, 1997, the MPUC issued an Order staying the investigation. The MPUC noted that Maine Yankee had begun a rate proceeding before the FERC on November 6, 1997, which could address the prudence issues raised in the MPUC's own investigation. The MPUC therefore stayed its investigation in order "to avoid unnecessary duplicative efforts by all parties involved". The MPUC reserved the right to reopen the investigation particularly if FERC declines to address the prudence issues of concern to the MPUC "if we feel it necessary to investigate those matters after the FERC proceeding ends." The Company cannot therefore predict -22- Form 10-K PART I Item 3. Legal Proceedings - Continued whether the MPUC will reopen its investigation once the FERC proceeding is concluded. As a result, the Maine Supreme Judicial Court, on December 15, 1997, upon motion by Maine Yankee and its Maine owners, stayed all proceedings in the appeal until the first to occur of either December 31, 1998 or the 30th day after the conclusion of the FERC's investigation. (g) Maine Public Utilities Commission Approves Rate Increase Pursuant to Previously Approved Rate Plan, MPUC Docket No. 97-830. Reference is made to the Company's Form 10-K for December 31, 1996 where the Company's rate stabilization plan approved by the Maine Public Utilities Commission (MPUC) (Docket No. 95- 052) in November, 1995 is described. In addition, in the Company's Form 8-K filed November 19, 1997, the Company announced its annual filing under the rate plan. On November 13, 1997, the Company filed with the MPUC its annual rate increase pursuant to the Company's rate plan. The filing supported an annual increase in retail rates of 7.6% effective February 1, 1998 consisting of the following: - 2.75% specified annual increase provided in the rate plan; - 2.22% increase for 50% of the Maine Yankee replacement power costs in accordance with the Maine Yankee plant outage provisions of the rate plan; and - 2.63% increase in accordance with the profit-sharing mechanism of the rate plan since earnings for the review period, i.e. the twelve months ended September 30, 1997, were more than 300 basis points below the target return on equity. Additional capacity payments to restart Maine Yankee and incremental replacement power costs have adversely impacted the Company's 1997 earnings and triggered the rate plan profit-sharing mechanism noted above. The Company's ability to increase its rates for the profit-sharing and for 50% of Maine Yankee replacement power costs is subject to the MPUC's pending review of the prudency of the decision to close Maine Yankee (see item (f) above). -23- Form 10-K PART I Item 3. Legal Proceedings - Continued In addition, the Company had amended its November, 1997 filing requesting that the savings from the restructured Wheelabrator-Sherman (W-S) Contract, as approved by the MPUC on December 22, 1997 (see item (e) above) be used to offset future Maine Yankee replacement power costs. However, this treatment was again subject to the results of the MPUC's review of the prudency of closing Maine Yankee. The restructuring of the W-S Contract requires an up-front payment of approximately $8.7 million, which the Company intends to finance from funds obtained from the Finance Authority of Maine (FAME), under its rate stabilization program. On January 15, 1998, the Public Advocate and the Company, with the support of the MPUC Staff, reached an agreement on the rate increase for February 1, 1998. The principal elements of the stipulation are as follows: - the rate increase effective February 1, 1998 was 3.9%, consisting of the specified increase of 2.75% and approximately $562,000 of the 1997 recoverable Maine Yankee replacement power costs (1.15%); - the minimum rate increase effective February 1, 1999 will be 3.1%, consisting of a specified increase of 2% and the remaining recoverable 1997 Maine Yankee replacement power costs of $523,000; - Maine Yankee replacement power costs for the period October 1, 1997 through September 30, 1998 will be offset by the 1998 savings under the restructured W-S contract, with the recovery of any incremental Maine Yankee replacement power costs subject to a final order by the MPUC in its previously mentioned review of the prudency of closing Maine Yankee; - the Company wrote off in 1997 unamortized Maine Yankee refueling outage costs of approximately $1,458,000; - the Company waives its right to collect additional revenues for the profit-sharing review period, i.e. the twelve months ended September 30, 1997, since the earnings deficiency was the result of the closing of Maine Yankee and, based on the 3.9% increase granted by the MPUC, the Company expects to earn a reasonable rate of return in 1998 without these additional revenues; - a customer service and reliability standards penalty will be suspended pending review of these standards during the rate plan's mid-term review in September of 1998. -24- Form 10-K PART I Item 3. Legal Proceedings - Continued This agreement was approved by the MPUC on January 26, 1998. The Company was not able to attain its interest coverage tests for the fourth quarter of 1997, but the Banks have granted a waiver. For 1998, the Banks have agreed to amend these interest coverage tests to deal with these additional Maine Yankee costs. Based on the Company's current projections, the Company believes that it can attain these amended interest coverage tests. The Company believes that its rate plan deals effectively with the closing of Maine Yankee, with customers and shareholders sharing the burden equally. However, the Company cannot predict what the MPUC's decisions will be concerning the prudency of closing Maine Yankee. If the Company is adversely impacted by the MPUC prudency decision, or if the Company is unable to complete the financing for the restructured Wheelabrator-Sherman contract, the Company may be required to seek an emergency rate increase and will review all cash expenditures, including the level of dividends. -25- Form 10-K PART I Item 4. Submission of Matters To a Vote of Security Holders At the Company's Annual Meeting of Stockholders, held on May 13, 1997, the only matter voted upon was the uncontested election of the following directors to serve until the 2000 Annual Meeting of Stockholders, each of whom received the votes shown: Non-votes and Nominee For Against Abstentions Robert E. Anderson 1,320,381 49,395 247,474 Nathan L. Grass 1,320,279 49,497 247,474 J. Paul Levesque 1,319,315 50,461 247,474 -26- Form 10-K PART II Item 5. Market for Registrant's Common Equity and Related Stockholder Matters The Company's Common Stock is listed and traded on the American Stock Exchange. As of December 31, 1997, there were 1,436 holders of record of the Company's Common Stock. Dividend data and market price related to the Common Stock are tabulated as follows for the two most recent calendar years: Dividends Market Price Dividends Declared High Low Paid Per Share Per Share 1997 First Quarter $18-3/8 $14-1/8 $ .46 $ .25 Second Quarter $14-3/4 $11-3/8 .25 .25 Third Quarter $12-7/8 $10-3/16 .25 .25 Fourth Quarter $12-13/16 $11-3/8 .25 .25 Total Dividends $1.21 $1.00 1996 First Quarter $22-3/8 $19 $ .46 $ .46 Second Quarter $20-3/8 $16-7/8 .46 .46 Third Quarter $19-1/8 $17-3/8 .46 .46 Fourth Quarter $19-1/2 $17-1/8 .46 .46 Total Dividends $1.84 $1.84 Dividends declared within the quarter are paid on the first day of the succeeding quarter. See Note 7 to the financial statements incorporated herein by reference concerning restrictions on payment of dividends on Common Stock. Item 6. Selected Financial Data A five-year summary of selected financial data (1993-1997) is included on page 13 of the Company's 1997 Annual Report to Stockholders, which summary is incorporated herein by reference. -27- Form 10-K PART II Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations The information required to be furnished in response to this Item is submitted as pages 4 to 12, Exhibit 13, 1997 Annual Report to Shareholders, which pages are hereby incorporated herein by reference. Information regarding "Construction" is also furnished in Note 10, "Commitments, Contingencies, and Regulatory Matters", of the Notes to the Consolidated Financial Statements, pages 25 to 29 of the 1997 Annual Report to Shareholders, which pages are hereby incorporated herein by reference. -28- Form 10-K PART II Item 8. Financial Statements and Supplementary Data (a) The following financial statements and supplementary data are included in the Company's 1997 Annual Report to Stockholders on pages 14 through 29 and page 34, and are incorporated herein by reference: Statements of Consolidated Operations for the years ended December 31, 1997, 1996 and 1995. Statements of Consolidated Cash Flows for the years ended December 31, 1997, 1996 and 1995. Consolidated Balance Sheets as of December 31, 1997 and 1996. Statements of Consolidated Common Shareholders' Equity for the years ended December 31, 1997, 1996 and 1995. Consolidated Statements of Capitalization as of December 31, 1997 and 1996. Notes to Consolidated Financial Statements. Independent Accountants' Report. Item 9. Changes In And Disagreements With Accountants On Accounting and Financial Disclosure For many years, including fiscal year 1995, the firm of Deloitte & Touche, LLP, (Deloitte & Touche) independent public accountants, was engaged by the Company as the principal independent accountant to audit the Company's financial statements. On March 1, 1996, the Company's entire Board of Directors, based on a recommendation of the Audit Committee of the Board, voted to engage the firm of Coopers & Lybrand, L.L.P., (Coopers & Lybrand) independent public accountants, as the Company's principal accountant beginning with the 1996 fiscal year audit and not to use the services of Deloitte & Touche. This change in accountants followed the Company's issuance, in November 1995, of a request for proposal to six major independent accounting firms to audit the Company's financial statements. The Company issued this request solely to determine whether it could reduce the fees it pays for accounting services. Three firms, including Deloitte & Touche and Coopers and Lybrand, responded to the request. Based solely upon the Audit Committee's review of those responses, and the terms of the request, the Board determined to engage Coopers & Lybrand, whose bid was substantially lower than any -29- Form 10-K PART II Item 9. Changes In And Disagreements With Accountants On Accounting and Financial Disclosure - Continued other received by the Company, as the Company's principal accountant for a term of at least three years, beginning in fiscal year 1996. As a result of this vote, the Company informed Deloitte & Touche that it would not renew its year to year engagement letter with that firm. Deloitte & Touche's report on the Company's financial statements for fiscal year 1995 did not contain an adverse opinion or disclaimer of opinion or any modification or qualification. At no time during the Company's two most recent fiscal years of Deloitte & Touche's engagement or any time thereafter has there been any disagreement between the Company and the firm on any matter of accounting principles or practices, financial statement disclosure or auditing scope or procedure. At no time during the Company's two most recent fiscal years of Deloitte & Touche's engagement or any time thereafter did any event occur between the Company and the firm that would require further reporting in this Form 10-K. At no time during the Company's two most recent fiscal years of Deloitte & Touche's engagement and any time thereafter prior to the Company's engaging Coopers & Lybrand did the Company consult Coopers & Lybrand regarding either the application of accounting principles to a specified transaction, either completed or proposed, or the type of audit opinion that might be rendered on the Company's financial statements. -30- Form 10-K PART III Item 10. Directors and Executive Officers of the Registrant Information with regard to the Directors of the registrant is set forth in the proxy statement of the registrant relating to its 1998 Annual Meeting of Stockholders, which information is incorporated herein by reference. Certain information regarding executive officers is set forth under the caption "Executive Officers" in Item 1 of Part I of this Form 10-K and also in the proxy statement of the registrant relating to the 1998 Annual Meeting of Stockholders, under "Compliance with Section 16(a) of the Securities and Exchange Act of 1934", which information is incorporated by reference. Item 11. Executive Compensation Information for this item is set forth in the proxy statement of the registrant relating to its 1998 Annual Meeting of Stockholders, which information (with the exception of the "Board Executive Compensation Committee Report") is incorporated herein by reference. Item 12. Security Ownership of Certain Beneficial Owners and Management Information for this item is set forth in the proxy statement of the registrant relating to its 1998 Annual Meeting of Stockholders, which information is incorporated herein by reference. Item 13. Certain Relationships and Related Transactions Not applicable. -31- Form 10-K PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K (a) (1) Financial Statements Incorporated by reference into Part II of this report from pages 14 through 29 and page 34 of the 1997 Annual Report to Stockholders: Statements of Consolidated Operations for years ended December 31, 1997, 1996 and 1995. Statements of Consolidated Cash Flows for the years ended December 31, 1997, 1996 and 1995. Consolidated Balance Sheets as of December 31, 1997 and 1996. Statements of Consolidated Common Shareholders' Equity for the years ended December 31, 1997, 1996 and 1995. Consolidated Statements of Capitalization as of December 31, 1997 and 1996. Notes to Consolidated Financial Statements. Independent Accountants' Report. (2) Financial Statement Schedules Included in Part IV of this report: -32- Form 10-K PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K - Continued Page Report of Independent Public Accountants 43 Schedule II - Valuation of Qualifying Accounts 44 and Reserves Schedules other than those listed above are omitted for the reason that they are not required or are not applicable, or the required information is shown in the financial statements or notes thereto. (3) Exhibits Certain of the following exhibits are filed herewith. Certain other of the following exhibits have heretofore been filed with the Commission and are incorporated herein by reference. (* indicates filed herewith). 3(a) Restated Articles of Incorporation with all amendments through May 8, 1990. (Exhibit 3(a) to 1990 form 10-K) 3(b) By-laws of the Company, as amended through May 12, 1987. (Exhibit 3(b) to 1987 Form 10-K) 4(a) Indenture of Mortgage and Deed of Trust defining the rights of the holders of the Company's First Mortgage Bonds. (Exhibit 4(a) to 1980 Form 10-K) 4(b) First Supplemental Indenture. (Exhibit 4(b) to 1980 Form 10-K) 4(c) Second Supplemental Indenture. (Exhibit 4(c) to 1980 Form 10-K) 4(d) Third Supplemental Indenture. (Exhibit 4(d) to 1980 Form 10-K) 4(e) Fourth Supplemental Indenture. (Exhibit 4(e) to 1980 Form 10-K) 4(f) Fifth Supplemental Indenture. (Exhibit A to Form 8-K dated May 10, 1968) 4(g) Sixth Supplemental Indenture. (Exhibit A to Form 8-K dated April 10, 1973) -33- Form 10-K PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K - Continued 4(h) Seventh Supplemental Indenture. (Exhibit A to Form 8-K dated November 7, 1975) 4(i) Eighth Supplemental Indenture. (Exhibit 4(i) to 1980 Form 10-K) 4(j) Ninth Supplemental Indenture. (Exhibit B to Form 10-Q for the second quarter of 1978) 4(k) Tenth Supplemental Indenture. (Exhibit 4(k) to 1980 Form 10-K) 4(l) Eleventh Supplemental Indenture. (Exhibit 4(l) to 1982 Form 10-K) 4(m) Indenture defining the rights of the holders of the Company's 9 7/8% debentures. (Exhibit A to Form 8-K, dated June 10, 1970) 4(n) Indenture defining the rights of the holders of the Company's 14% debentures. (Exhibit 4(n) to 1982 Form 10-K) 4(o) Twelfth Supplemental Indenture. (Exhibit 4(o) to Form 10-Q for the quarter ended September 30, 1984) 4(p) Thirteenth Supplemental Indenture. (Exhibit 4(p) to Form 10-Q for the quarter ended September 30, 1984) 4(q) Fourteenth Supplemental Indenture, Dated July 1, 1985. (Exhibit 4(q) to 1985 Form 10-K) 4(r) Fifteenth Supplemental Indenture, Dated March 1, 1986. (Exhibit 4(r) to 1985 Form 10-K) 4(s) Sixteenth Supplemental Indenture, Dated September 1, 1991. (Exhibit 4(s) to the Company's 1991 Form 10-K). 9 Not applicable. 10(a)(1) Joint Ownership Agreement with Public Service of New Hampshire in respect to construction of two nuclear generating units designated as Seabrook Units 1 and 2, together with related -34- Form 10-K PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K - Continued amendments to date. (Exhibit 10 to 1980 Form 10-K) 10(a)(2) Twentieth Amendment to Joint Ownership Agreement (Exhibit 10(a)(6) to the Company's 1986 Form 10-K) 10(a)(3) Twenty-Second Amendment to Joint Ownership Agreement. (Exhibit 10(a)(3) to the 1988 Form 10-K) 10(b)(1) Capital Funds Agreement, dated as of May 20, 1968 between Maine Yankee Atomic Power Company and the Company. (Exhibit 10(b)(1) to Form 10-Q for the quarter ended March 31, 1983) 10(b)(2) Power Contract, dated as of May 20, 1968 between Maine Yankee Atomic Power Company and the Company. (Exhibit 10(b)(2) to Form 10-Q for the quarter ended March 31, 1983) 10(c)(1) Participation Agreement, as of June 20, 1969, with Maine Electric Power Company, Inc. (Exhibit 10(c)(1) to Form 10-Q for the quarter ended March 31, 1983) 10(c)(2) Agreement, as of June 20, 1969, among the Company and the other Maine Participants. (Exhibit 10(c)(2) to Form 10-Q for quarter ended March 31, 1983) 10(c)(3) Power Purchase and Transmission Agreement Supplement to Participation Agreement, dated as of August 1, 1969, with Maine Electric Power Company, Inc. (Exhibit 10(c)(3) to Form 10-Q for quarter ended March 31, 1983) 10(c)(4) Supplement Amending Participation Agreement, as of June 24, 1970, with Maine Electric Power Company, Inc., (Exhibit 10(c)(4) to Form 10-Q for quarter ended March 31, 1983) 10(c)(5) Second Supplement to Participation Agreement, dated as of December 1, 1971, including as Exhibit A the Unit Participation Agreement dated November 15, 1971, as amended, between Maine Electric Power Company, Inc. and the New Brunswick Electric Power Commission. (Exhibit -35- Form 10-K PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K - Continued 10(c)(5) to Form 10-Q for quarter ended March 31, 1983) 10(c)(6) Agreement and Assignment, as of August 1, 1977, by Connecticut Light & Power Company, Hartford Electric Company, Holyoke Water Power Company, Holyoke Power Company, Western Massachusetts Electric Company and the Company. (Exhibit 10(c)(6) to Form 10-Q for the quarter ended March 31, 1983) 10(c)(7) Amendment dated November 30, 1980 to Agreement and Assignment as of August 1, 1977, between Connecticut Light & Power Company, Hartford Electric Company, Holyoke Water Power Company, Holyoke Power Company, Western Massachusetts Electric Company and the Company. (Exhibit 10(c)(7) to Form 10-Q for the quarter ended March 31, 1983) 10(c)(8) Assignment Agreement as of January 1, 1981, between Central Maine Power Company and the Company. (Exhibit 10(c)(8) to Form 10-Q for the quarter ended March 31, 1983) 10(d) Wyman Unit #4 Agreement for Joint Ownership as of November 1, 1974, with Amendments 1, 2, and 3, dated as of June 30, 1975, August 16, 1976, December 31, 1978, respectively. (Exhibit 10(d) to Form 10-Q for the quarter ended March 31, 1983) 10(e) Agreement between Sherman Power Company and Maine Public Service Company, dated June 4, 1984, with amendments dated July 12, 1984 and February 14, 1985. (Exhibit 10(f) to 1984 Form 10-K) 10(f) Credit Agreement, dated as of October 8, 1987 among the Registrant and The Bank of New York, Bank of New England, N.A., The Merrill Trust Company and The Bank of New York, as agent for the Participating Banks (Exhibit 10(g) to Form 8-K dated October 13, 1987) 10(g) Amendment No. 1, dated as of October 8, 1989, to the Revolving Credit Agreement, dated as of October 8, 1987, among the Registrant and The -36- Form 10-K PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K - Continued Bank of New York, Bank of New England, N.A., Fleet Bank (formerly the Merrill Trust Company) and The Bank of New York as agent for the participating banks (Exhibit 10(l) to Form 8-K dated September 22, 1989). 10(h) Amendment No. 2, dated as of June 5, 1992, to the Revolving Credit Agreement, among the Registrant and The Bank of New York, Bank of New England, N.A., Shawmut Bank and the Bank of New York, as agent for the participating banks. (Exhibit 10(h) to the Company's 1992 Form 10-K) 10(i) Indenture of Second Mortgage and Deed of Trust, dated as of October 1, 1985, made by the Registrant to J. Henry Schroder Bank and Trust Company, as Trustee. (Exhibit 10(i) to Form 8-K dated November 1, 1985) 10(j) First Supplemental Indenture Dated March 1, 1991. (Exhibit 10(i) to the Company's 1991 Form 10-K). 10(k) Second Supplemental Indenture Dated September 1, 1991. Exhibit 10(j) to the Company's 1991 Form 10-K). 10(l) Agency Agreement dated as of October 1, 1985, between J. Henry Schroder Bank and Trust Company, as Trustee under the Indenture of Second Mortgage and Deed of Trust dated as of October 1, 1985, made by the Registrant to J. Henry Schroder Bank and Trust Company, as Trustee, and Continental Illinois National Bank and Trust Company, as Trustee, under an Indenture of Mortgage and Deed of Trust, dated as of October 1, 1945, as amended and supplemented, made by the Registrant to Continental Illinois National Bank and Trust Company, as Trustee (Exhibit 10(j) to Form 8-K dated November 1, 1985) Executive Compensation Plans and Arrangements 10(m) Employment Contract between Frederick C. Bustard and Maine Public Service Company dated -37- Form 10-K PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K - Continued August 22, 1989. (Exhibit 10(h) to 1989 Form 10-K) 10(n) Employment Contract between Paul R. Cariani and Maine Public Service Company dated August 22, 1989. (Exhibit 10(l) to 1989 Form 10-K) 10(o) Employment Contract between Stephen A. Johnson and Maine Public Service Company dated August 22, 1989. (Exhibit 10(m) to 1989 Form 10-K) 10(p) Employment Contract between Larry E. LaPlante and Maine Public Service Company, dated May 9, 1995. 10(q) Maine Public Service Company, Prior Service Executive Retirement Plan, dated May 12, 1992. (Exhibit 10(s) to 1992 Form 10-K). 10(r) Maine Public Service Company Pension Plan. (Exhibit 10(t) to 1992 Form 10-K). 10(s) Maine Public Service Company Retirement Savings Plan. (Exhibit 10(u) to 1992 Form 10- K). 10(t) Third Supplemental Indenture Dated as of June 1, 1996. 10(u) Amendment No. 3, dated as of October 8, 1995, to the Revolving Credit Agreement, dated as of October 7, 1987, among the Registrant and The Bank of New York, Shawmut Bank of Boston, Fleet Bank of Maine, and The Bank of New York, an agent for the participating Banks. 11 Not applicable. 12 Not applicable. *13 1997 Annual Report to Shareholders. 16 March 8, 1996 Letter regarding change in certifying accountant from Deloitte & Touche LLP 18 Not applicable. 19 Not applicable. -38- Form 10-K PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K - Continued 21 Maine and New Brunswick Electrical Power Company, Limited, a Canadian corporation. 22 Not applicable. 23 Not applicable. 99(a) Agreement of Purchase and Sale between Maine Public Service and Eastern Utilities Associates, dated April 7, 1986 (Exhibit 28(a) to Form 10-Q for the quarter ended June 30, 1986). 99(b) Addendum to Agreement of Purchase and Sale, dated June 26, 1986 (Exhibit 28(b) to Form 10- Q for the Quarter ended June 30, 1986). 99(c) Stipulation between Maine Public Service Company, the Staff of the Commission and the Maine Public Utilities Commission and the Maine Public Advocate, dated July 14, 1986 (Exhibit 28(c) to Form 10-Q for the quarter ended June 30, 1986). 99(d) Amendment to July 14, 1986 Stipulation, dated July 18, 1986 (Exhibit 28(d) to Form 10-Q for the quarter ended June 30, 1986). 99(e) Order of the Maine Public Utilities Commission dated July 21, 1986, Docket Nos 84-80, 84-113 and 86-3. 99(f) Order of the Maine Public Utilities Commission, dated May 9, 1986, Docket Nos. 84- 113 and 86-3 (with attached Stipulations). (Exhibit 28(r) to 1986 Form 10-K). 99(g) Order of the Maine Public Utilities Commission, dated July 31, 1987, Docket Nos. 84-80, 84-113, 87-96 and 87-167 (with attached Stipulation) (Exhibit 28(i) to 1988 Form 10-K). 99(h) Agreement between Maine Public Service Company and various current Seabrook Nuclear Project Joint Owners, dated January 13, 1989 (Exhibit 28(o) to 1988 Form 10-K). -39- Form 10-K PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K - Continued 99(i) Order of the Maine Public Utilities Commission dated November 30, 1995 (with attached Stipulation) in Docket No. 95-052. (Exhibit 28(p) to 1995 Form 10-K). 99(j) Order of the Federal Energy Regulatory Commission dated May 31, 1995 in Docket No. ER 95-836-000. (Exhibit 28(r) to 1995 Form 10- K). 99(k) Order of Maine Public Utilities Commission dated June 26, 1996 in Docket 95-052 (Rate Design) *99(l) Independent Auditors Report of Deloitte & Touche L.L.P. dated February 14, 1996 regarding year ended December 31, 1995. *99(m) Amendment No. 1, dated as of March 28, 1997, to the Letter of Credit and Reimbursement Agreement, dated as of June 1, 1996, among the Registrant, The Bank of New York, Fleet Bank of Maine, and The Bank of New York, as Agent and Issuing Bank. *99(n) Amendment No. 4, dated as of March 28, 1997, to the Revolving Credit Agreement, dated as of October 8, 1987, by and among the Registrant, the signatory Banks thereto and The Bank of New York, as Agent. *99(o) Order of Maine Public Utilities Commission dated January 30, 1998 in Docket No. 97-830 (Annual Increase under Rate Stabilization Plan). *99(p) Interim Report of the MPUC and Maine Attorney General regarding market power issues raised by the prospect of the retail competition in the electric industry in Docket No. 97-877. *99(q) Order by the Maine Public Utilities Commission dated January 15, 1998 in Docket No. 97-727. -40- Form 10-K PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K - Continued (b) A Form 8-K was filed on: January 31, 1997, under item 5, Other Events; February 14, 1997, under item 5, Other Events; March 7, 1997, under item 5, Other Events; March 31, 1997, under item 5, Other Events and item 7, Exhibits; June 4, 1997, under item 5, Other Events; September 4, 1997, under item 5, Other Events; October 15, 1997, under item 5, Other Events; November 19, 1997, under item 5, Other Events; December 23, 1997, under item 5, Other Events; and January 28, 1998, under item 5, Other Events. SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 26th of March, 1998. MAINE PUBLIC SERVICE COMPANY By: /s/ Larry E. LaPlante Larry E. LaPlante Vice President, Finance, Administration and Treasurer -41- Form 10-K Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons in the capacities and on the date indicated. Signature Title Date Chairman of the Board, /s/ G. M. Hovey and Director 3/6/98 (G. Melvin Hovey) /s/ Paul R. Cariani President and Director 3/6/98 (Paul R. Cariani) /s/ Robert E. Anderson Director 3/6/98 (Robert E. Anderson) /s/ Donald F. Collins Director 3/6/98 (Donald F. Collins) /s/ D. James Daigle Director 3/6/98 (D. James Daigle) /s/ Richard G. Daigle Director 3/6/98 (Richard G. Daigle) Director (J. Gregory Freeman) /s/ Deborah L. Gallant Director 3/6/98 (Deborah L. Gallant) /s/ Nathan L. Grass Director 3/6/98 (Nathan L. Grass) /s/ J. Paul Levesque Director 3/6/98 (J. Paul Levesque) -42- REPORT OF INDEPENDENT ACCOUNTANTS To the Directors and Shareholders of Maine Public Service Company We have audited the consolidated financial statements of Maine Public Service Company and its subsidiary, Maine and New Brunswick Electrical Power Company, Limited, as of December 31, 1997 and 1996, and for the years then ended, which financial statements are included on pages 14 through 29 of the 1997 Annual Report to Shareholders of Maine Public Service Company and incorporated by reference herein. We have also audited the financial statement schedules as of December 31, 1997 and 1996, listed in the index on page 33 of this Form 10-K. These financial statements and financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedules based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Maine Public Service Company and its subsidiary as of December 31, 1997 and 1996, and the consolidated results of their operations and their cash flows for the years then ended in conformity with generally accepted accounting principles. In addition, in our opinion, the financial statement schedules referred to above, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information required to be included therein. /s/ Coopers & Lybrand, LLP Portland, Maine February 13, 1998 -43- Maine Public Service Company & Subsidiary Valuation of Qualifying Accounts & Reserves For the Years Ended December 31, 1997, 1996, & 1995 Column A Column B Column C Column D Column E Additions: Deductions: Balance Recoveries Accounts Balance at Costs of Accounts Written Off at Beginning & Previously As End of Description of Period Expenses Written Off Uncollectible Period Reserve Deducted From Asset To Which It Applies: Allowance for Uncollectible Accounts Year Ended December 31: 1997 207,029 182,706 124,397 299,132 215,000 1996 214,130 182,000 102,627 291,728 207,029 1995 214,215 150,800 109,390 260,275 214,130 -44- Exhibit 13 Maine Public Service Company 1997 Annual Report We put a lot of energy into Northern Maine (Page 1) Maine Public Service Company (System Map) The primary goal of Maine Public Service Company is to supply reliable, economical electrical power to Northern Maine. The Company is an investor- owned electric utility with a wholly-owned subsidiary, Maine and New Brunswick Electrical Power Company, Ltd., located at Tinker, New Brunswick. Together both companies provide energy to more than 35,000 retail customers in a 3,600 square mile area. Maine Public Service Company has a favorable mixture of generation sources made up of power produced by hydro-electric and oil-fueled facilities, as well as two independent wood-burning cogenerators. The system is strengthened by electrical interconnections with New Brunswick, Canada, allowing electrical support from the New Brunswick system and indirectly from the Hydro-Quebec system. Major business activities in the area center around the production of agricultural and forest products. Service was provided at a high reliability rate over the last year, and it is our aim to meet customer needs fully and efficiently, at the lowest possible cost. Table of Contents Profile and Table of Contents 1 President's Letter 2-3 Analysis of Financial Condition and Review of Operations - 1997 4-11 Shareholder Information 12 Five-Year Summary of Selected Financial Data 13 Financial Statements and Notes 14-29 Consolidated Financial Statistics 30-31 Consolidated Operating Statistics 32-33 Independent Accountants' Report 34 Directors 35 Executive Officers and Stock Transfer Information 36 (Photo) Walter M. Reed, Jr., age 74, died unexpectedly while golfing at Aroostook Valley Country Club, August 21, 1997. A champion golfer and well-known retired businessman, Walter served as President of Maine Potato Growers for 22 years. He had been a Director of Maine Public Service Company since February 28, 1979, serving on the Pension Investment Committee and Budget and Finance Committee. With sadness we remember and appreciate the efforts of our valued friend. Maine Public Service Company 209 State Street P. O. Box 1209 Presque Isle, Maine 04769-1209 Tel. No. (207) 768-5811 * FAX No. (207) 764-6586 Home Page: http://www.mainerec.com/mpsco.html * E-Mail: mainepub@ mfx.net (Pages 2 and 3) (Photo) Bell-Ringing Ceremony in New York -- With a solid rap on the American Stock Exchange bell, MPS President Paul R. Cariani, left, opened stock trading at precisely 9:30 a.m. on December 5, 1997. The event marked the Company's 50th anniversary of trading on the Exchange. Looking on from Cariani's left are Amex Senior Vice President Delia Emmons; MPS Vice President of Finance, Administration, and Treasurer Larry LaPlante; and Amex Executive Vice President James Duffy. MPS stock is listed on the Amex under the ticker symbol "MAP". President's Letter to our Shareholders and Employees The pace of change quickened in 1997 and the year turned out to be one of the most challenging of your Company's 80-year history. Although we suffered a loss of $1.35 per share, we have made significant progress in restoring the financial health of the Company and are moving forward with positive developments in order to compete under future deregulation. We have increased our efforts in marketing and economic development. As you know, the 1994 closure of Loring Air Force Base and the 1996 loss of our largest customer, Houlton Water Company, have placed continued financial challenges before us. Greatly compounding our difficulties, the closure of Maine Yankee in 1997 cost this Company $2.94 per share in 1997 and is the primary reason for this year's unfavorable financial performance. Despite these adverse circumstances, the Company has taken several steps to improve its financial condition; steps that I believe will substantially improve our results in 1998 and beyond. These developments are: * Settlement of the third year of our rate plan; * Restructuring of the Wheelabrator-Sherman power contract; * Potential sale of our Generation Assets; * Development of a Marketing Subsidiary; and * Improved economic development activity within our service territory. Settlement of Rate Plan Through negotiations with the MPUC Staff and Public Advocate, we settled the third year of our rate stabilization plan with a 3.9% rate increase effective February 1, 1998. As part of the agreement, we wrote off nearly $1.5 million of Maine Yankee expenses in 1997. This rate settlement will improve our financial position in 1998 and is in the best interest of all concerned. Even with this rate increase, MPS will continue to be competitive with other investor-owned utilities throughout New England. Restructuring Supply Contract We have recently received approval from the Maine Public Utilities Commission to buy down and restructure our power supply contract with Wheelabrator-Sherman. This restructuring will substantially reduce our expenses beginning 1998. We expect to finance the buy-down through the Finance Authority of Maine (FAME). Sale of Generation Assets The Maine retail access law, passed in 1997, requires an open competitive market for generation, beginning March 1, 2000. In order to facilitate that free market, the law requires all electric utilities to divest of generating assets by March 1, 2000. In order to take advantage of a currently favorable market in the Northeast, the Company opened bidding on its generation assets in August, 1997. Based on preliminary results of the bid process, we are confident we will receive fair value and look forward to finalizing the sale in 1998. The retail access law permits electric utilities a reasonable opportunity to recover legitimate, verifiable and unmitigable costs (otherwise known as stranded costs) that are unrecoverable as a result of retail competition. We believe the sale of our generating assets, along with the restructured W-S contract, will substantially reduce our stranded costs and, thereby, facilitate its recovery. MPUC proceedings in 1998 will address stranded costs as well as rates and other restructuring issues. Both the sale of our generating assets and stranded costs are subject to MPUC approval. A New Marketing Subsidiary Changes in electric regulation will present a number of opportunities. Anticipating retail access, MPS is developing a marketing subsidiary, although the subsidiary's formation must be approved by the MPUC. We are working with Cinergy, an electric utility headquartered in Cincinnati, Ohio, to market power. The marketing group is actively trading wholesale power as well as researching products and services that may be marketable in an unregulated, competitive environment. Economic Development This year, we will witness the opening of two call centers within our service territory, one at Loring Commerce Center (former Air Base) and one in Presque Isle. These new businesses are solid evidence of northern Maine's emerging economic recovery, along with the restart of a wood-fired generating plant in our service territory. We have an agreement in principle with our Banks that satisfies our interest coverage tests and will restructure our credit agreement. This agreement resolves issues pertaining to violations of our interest coverage tests and potential defaults on our debt instruments caused by the closure of Maine Yankee. Although the loss of Maine Yankee posed a financial hardship for us, the decision to close the plant was based on an economic analysis of the costs, risks, and uncertainties of operating the plant compared to closing and decommissioning the site. As explained elsewhere in this report, the MPUC may challenge the prudency of this decision. Overall, I am pleased with the progress of the Company and believe that we are putting our finances in order and are preparing for retail access. To summarize, the aforementioned events should allow the Company to maintain competitive rates, satisfy the financial covenants of our lenders, and maintain our current dividend, barring any unanticipated developments. I want to thank you for your trust, confidence, and the opportunity to lead your Company into the next century. And, as always, our employees continue to dedicate themselves and exhibit the highest degree of professionalism and work ethic, and I thank them for that. Sincerely, Paul R. Cariani President and CEO (Page 4) Analysis of Financial Condition and Review of Operations - 1997 RESULTS OF OPERATIONS Operating Revenues and Energy Sales Consolidated operating revenues and MWH sales for the years 1997, 1996, and 1995 are as follows: Consolidated Operating Revenues and Megawatt Hours Sold 1997 1996 1995 (Dollars in Thousands) Dollars MWH Dollars MWH Dollars MWH Residential $20,391 167,368 $19,961 169,298 $19,081 168,640 Commercial & Industrial - Large 9,452 134,741 10,112 134,588 9,437 128,478 Commercial & Industrial - Small 17,419 168,976 16,420 163,804 15,723 165,914 Other Retail 1,468 13,323 1,523 13,166 1,701 14,859 Total Retail 48,730 484,408 48,016 480,856 45,942 477,891 Sales for Resale 2,168 57,578 2,096 55,958 6,955 123,793 Total Primary 50,898 541,986 50,112 536,814 52,897 601,684 Secondary Sales 2,140 52,648 4,797 229,141 619 22,115 Total Sales of Electricity 53,038 594,634 54,909 765,955 53,516 623,799 Other 2,034 2,355 1,763 Total Operating Revenues $55,072 $57,264 $55,279 Primary sales for 1997 were 541,986 MWH, which were approximately 1.0% higher than primary sales of 536,814 MWH in 1996 and 9.9% lower than sales of 601,684 MWH in 1995. As reflected in the table above, the loss of Houlton Water Company (HWC), a sales for resale customer, due to a competitive bid effective January 1, 1996, is the principle reason for the primary sales decrease from 1995 to 1996. In 1995, HWC, the Company's largest customer, represented 11.1% of consolidated MWH sales and 8.4% of consolidated operating revenues. MWH sales for resale were 2.9% higher in 1997 than 1996 because of increased sales to Eastern Maine Electrical Co-op and Perth-Andover Electric Light Commission. Retail sales were 484,408 MWH in 1997, an increase of 3,552 MWH or .7% over 1996 sales of 480,856 MWH, primarily due to the re-utilization of the former Loring AFB by small commercial customers. Compared to 1995, retail sales increased 1.4% reflecting increased sales to two large industrial customers: J. Paul Levesque & Sons (a wood products customer) and McCain Foods (a foods product customer). During 1996 and 1997, the Company entered into long-term contracts with five of its largest customers. In exchange for discounts from the Company's standard rates, these customers agreed to purchase all of their electrical requirements from the Company through the year 2000. All five of these customers produced evidence of hardship to continue operations in the area or were investigating self generation, criteria that the Maine Public Utilities Commission (MPUC) reviewed before approving these load-retention contracts. Secondary sales for 1997 of $2,140,000 were $2,657,000 lower than those sales in 1996 and $1,521,000 higher than sales in 1995. The Company's Maine Yankee entitlement was sold in 1996 during periods of surplus capacity while in 1997 and 1995 the plant was out of service, as further discussed in the "Maine Yankee" section of this Annual Report. During the three-year period, the Company entered into arrangements with other utilities to sell its Wyman Unit No. 4 and Maine Yankee entitlements, when available, for varying lengths of time at existing market rates. This energy was replaced, when necessary, with system purchases, avoiding off-system wheeling costs. The MPUC has jurisdiction over retail rates. As more fully explained in the "Regulatory Proceedings - Four-Year Rate Stabilization Plan" section of this Annual Report, the MPUC approved the four-year rate plan effective January 1, 1996 with increases of 4.4% and 2.9% effective on January 1, 1996 and February 1, 1997, respectively. The four-year rate plan allows for annual increases in retail rates and eliminated the fuel clause. Prior to the four-year rate plan, the Company had not sought a base rate increase since November 1, 1992. (Page 5) A fuel clause increase of $1.4 million was approved by the MPUC effective April 1, 1995. The Company's customer rates are competitive among investor-owned utilities in Maine and New England. The Federal Energy Regulatory Commission (FERC) has jurisdiction over U.S. wholesale rates, included as sales for resale in the previous table and discussion. Energy Supply The Company's most economical source of supply is hydro energy, which was 80.7% of normal production levels in 1997 and provided 17.1% of the Company's energy supply. In 1996, hydro production was 126.5% of normal and provided 21.1% of the Company's energy supply. Hydro production in 1995 was 90.8% of normal and accounted for 18.3% of the Company's total energy supply. The availability of low cost hydro reduces the need for more expensive sources of energy. Maine Yankee was out of service for all of 1997 and operated for only a few weeks in 1995. As more fully explained in the "Maine Yankee" section of this Annual Report, following an economic analysis, the Maine Yankee Board of Directors voted on August 6, 1997, to shut down the plant permanently. During 1996, Maine Yankee was restricted to 90% of rated capacity but was able to provide 31.1% of the Company's total energy supply. In 1995, the nuclear plant was taken out of service to re-sleeve the steam generator tubes and thus only contributed 1.5% of the Company's energy supply. To offset the loss of Maine Yankee production, the Company purchased replacement energy from various sources, including but not limited to New Brunswick Power, on a competitive basis. These purchases accounted for 58.9% and 57.5% of the Company's energy supply in 1997 and 1995 respectively, compared to 30.5% in 1996. The Company's oil-fired generating facilities provided 4.2% of the Company's energy supply in 1997, compared to 1.2% in 1996 and 3.6% in 1995. In 1986, under an agreement ordered by the MPUC, the Company began purchasing the output from an 17.6 MW wood-burning independent power producer, currently owned by Wheelabrator-Sherman (W-S). As more fully explained in the "Regulatory Proceedings - Restructured Agreement with Wheelabrator-Sherman" section of this Annual Report, the Company and W-S have agreed on a new purchase power arrangement. These mandated purchases from this facility represented 19.8% of the Company's energy supply in 1997, compared to 16.1% and 19.1% in 1996 and 1995, respectively. On December 19, 1997, the Company announced the signing of an agreement for the purchase of power until 2000 from Alternative Energy's Beaver Power Plant in Ashland, Maine, as a replacement for Maine Yankee energy. Electric Output By Source (Percent) 1997 1996 1995 Oil 4.2 1.2 3.6 Cogeneration 19.8 16.1 19.1 Purchases 58.9 30.5 57.5 Nuclear - 31.1 1.5 Hydro 17.1 21.1 18.3 Total 100.0 100.0 100.0 Operating Expenses For the three-year period 1995-1997, purchased power expenses are as follows: (Dollars in Thousands) 1997 1996 1995 Wheelabrator-Sherman $15,911 $15,593 $14,507 Maine Yankee 12,303 10,185 7,972 NB Power 10,786 3,498 9,091 System Purchases 1,308 2,544 408 Total Purchased Power 40,308 31,820 31,978 Deferred Fuel (3,699) (1,375) (4,937) Fuel Expense Write-Off - - 3,500 Net Purchased Power $36,609 $30,445 $30,541 Wheelabrator-Sherman's slight increase in 1997 expenses compared to 1996 was caused by a contractual price increase of 5% partially offset by a 2.7% decrease in output. For 1997, 1996 and 1995, these mandated purchases from Wheelabrator-Sherman represented 39.5%, 49.0%, and 45.4%, respectively, of total purchased power expenses. As more fully explained in the "Maine Yankee" section of this Annual Report, Maine Yankee was out of service in 1997. The joint owners of the nuclear plant voted to close the plant permanently in August, 1997. The Company purchased replacement energy primarily from NB Power, an increase of $7.3 million in 1997 over 1996. As part of a rate stipulation approved by the Maine Public Utilities Commission on January 30, 1998, the Company agreed to a 1997 write-off of $1.5 million of deferred capacity charges related to the 1997 Maine Yankee refueling. The increase in 1997 Maine Yankee expenses also reflects the efforts to restart the plant in early 1997 before the owners voted to start decommissioning. System purchases in 1997 decreased by $1,236,000 compared to 1996, respectively, due to decreased power marketing activities, as discussed in the "Operating Revenues and Energy Sales" section of this Annual Report. Deferred fuel expense, a component of purchased power, was a negative $3,699,000 in 1997, compared to a negative $1,375,000 in 1996 and a negative $4,937,000 in 1995. Negative deferred fuel indicates expenses deferred to a period when these costs will be collected in rates. As more fully discussed in the "Regulatory Proceedings - Four-Year Rate Stabilization Plan" section of this Annual Report, the fuel clause adjustment was eliminated effective on January 1, 1996 with the exception of the annual Wheelabrator-Sherman deferral of fuel expenses of $1.5 million and, in the event of a Maine Yankee outage exceeding six consecutive months, the Company's Rate Stabilization Plan provides a sharing mechanism. This provision went into effect on June 6, 1997, with approximately $2.3 million deferred through the end of 1997, subject to future collection. As part of the 1995 rate plan, the Company wrote off $3.5 million, before income taxes, of the replacement power costs associated with the Maine Yankee outage, which had been deferred under the previous fuel clause. (Page 6) Other operation and maintenance expenses for the three-year period are as follows: (Dollars in Thousands) 1997 1996 1995 Generation Fuel Expense $ 893 $ 387 $ 824 Other 1,321 1,571 2,031 2,214 1,958 2,855 Transmission and Distribution 3,609 4,228 3,668 Customer Accounting and General Administrative 6,947 7,629 6,740 Total $12,770 $13,815 $13,263 Fuel expenses for generation increased by $506,000 in 1997 compared to 1996 with the increased generation at Wyman Unit No. 4, an oil-fired generating facility. Other generation expenses decreased by $250,000 reflecting a decrease in labor costs at the Company's wholly owned subsidiary's facilities and reduced expenses at Wyman Unit No. 4. Transmission and distribution expenses decreased $619,000 in 1997, compared to 1996 reflecting decreased power marketing wheeling activities and higher than normal tree trimming in 1996. Customer accounting and general and administrative expenses decreased $682,000 from $7,629,000 in 1996 to $6,947,000 in 1997 due to medical expense savings of $473,000 and pension costs of $402,000 related to an early retirement program in March 1996. Maine Yankee The Company owns 5% of the Common Stock of Maine Yankee, which operated an 860 MW nuclear power plant (the "Plant") in Wiscasset, Maine. On August 6, 1997, the Board of Directors of Maine Yankee voted to permanently cease power operations and to begin decommissioning the Plant. The Plant experienced a number of operational and regulatory problems and has been shut down since December 6, 1996. The decision to close the Plant permanently was based on an economic analysis of the costs, risks and uncertainties associated with operating the Plant compared to those associated with closing and decommissioning it. The Plant's operating license from the Nuclear Regulatory Commission (NRC) was due to expire on October 21, 2008. The Plant generally provided reliable and low-cost power from the time it commenced operations in late 1972 to 1995. Beginning in early 1995, however, Maine Yankee encountered various operational and regulatory difficulties with the Plant. In 1995, the Plant was shut down for almost the entire year to repair a large number of steam generator tubes that were exhibiting defects. Shortly before the Plant was to go back on-line in December 1995, a group with a history of opposing nuclear power released an undated, unsigned, anonymous letter alleging that in 1988 Yankee Atomic (then an affiliated consultant of Maine Yankee) and Maine Yankee had used the results of a faulty computer code as a basis to apply to the NRC for an increase in the Plant's power output. In response to the allegation, on January 3, 1996, the NRC issued a Confirmatory Order that restricted the Plant to 90 percent of its licensed thermal operation level, which restriction was still in effect when the Plant was permanently shut down. As a result of the controversy associated with the allegations, the NRC, at the request of the Governor of Maine, conducted an intensive Independent Safety Assessment (ISA) of the Plant in the Summer and Fall of 1996. On October 7, 1996, the NRC issued its ISA report, which found that while the Plant had been operated safely, there were weaknesses that needed to be addressed, which would require substantial additional spending by Maine Yankee. On December 10, 1996, Maine Yankee responded to the ISA report, acknowledged many of the weaknesses, and committed to revising its operations and procedures to address the NRC's criticisms. Another result of the controversy associated with the allegations was an investigation of Maine Yankee initiated by the NRC's Office of Investigations (OI), which, in turn, referred certain issues to the United States Department of Justice (DOJ) for possible criminal prosecution. Subsequently, on September 27, 1997, the DOJ, through the United States Attorney for Maine, announced that its review had revealed no grounds for criminal prosecution. The Company believes that the OI investigation, however, could ultimately result in the imposition of civil penalties, including fines, on Maine Yankee. In 1996, the Plant was generally in operation at the 90-percent level from late January to early December, except for a two-month outage from mid-July to mid-September. The Plant was shut down again on December 6, 1996, to address several concerns, and has not operated since then. The precipitating event causing the shutdown was the need to evaluate and resolve cable-separation compliance issues, and on December 18, 1996, the NRC issued a Confirmatory Action Letter requiring the Plant to remain shut down until Maine Yankee's plan for resolving the cable-separation issues was accepted by the NRC. Subsequently, Maine Yankee uncovered additional issues, including among others the possibility of having to replace defective fuel assemblies, address additional cable-separation issues, and determine the condition of the Plant's steam generators, all of which contributed to further operational uncertainty. On January 29, 1997, the Plant was placed on the NRC's Watch List, and on January 30, 1997, the NRC issued a supplemental Confirmatory Action Letter requiring the resolution of additional concerns before the Plant could be restarted. In December 1996, Maine Yankee requested proposals from several utilities with large and successful nuclear programs to provide a management team, and ultimately contracted with Entergy Nuclear, Inc., effective February 13, 1997, for management services that included providing a new president and regulatory compliance officer. The Entergy-provided management team made progress in addressing technical issues, but a number of operational and regulatory uncertainties remained. On May 27, 1997, the Board of Directors of Maine Yankee voted to minimize spending while preserving the options of restarting the Plant or conveying ownership interests to a third party. After unsuccessful negotiations with one prospective purchaser, Maine Yankee found no other interest in purchasing the Plant and, based on its economic analysis, closed the Plant permanently. As required by the NRC, on August 7, 1997, Maine Yankee certified to the NRC that Maine Yankee had permanently ceased operations and that all fuel assemblies had been permanently removed from the Plant's reactor vessel. On August 27, 1997, Maine Yankee filed the required Post-Shutdown Activities Report with the NRC, describing its planned post-shutdown activities and a proposed schedule. (Page 7) The Company's 5% ownership interest in Maine Yankee's common equity amounted to $4.0 million as of December 31, 1997, and under Maine Yankee's Power Contracts and Additional Power Contracts, the Company is responsible for 5% of the costs of decommissioning the Plant. Maine Yankee's most recent estimate of the cost of decommissioning is $380.4 million, based on a 1997 study by an independent engineering consultant, plus estimated costs of interim spent-fuel storage of $127.6 million, for an estimated total cost of $508 million (in 1997 dollars). The previous estimate for decommissioning, by the same consultant, was $316.6 million (in 1993 dollars). On September 1, 1997, Maine Yankee estimated the sum of the future payments for the closing, decommissioning and recovery of the remaining investment in Maine Yankee to be approximately $930 million, of which the Company's 5% share would be approximately $46.5 million. Legislation enacted in Maine in 1997 calling for restructuring the electric utility industry provides for recovery of decommissioning costs, to the extent allowed by federal regulation, through the rates charged by the transmission and distribution companies. Based on the Maine legislation and regulatory precedent established by the FERC in its opinion relating to the decommissioning of the Yankee Atomic nuclear plant, the Company believes that it is entitled to recover substantially all of its share of such costs from its customers and, as of December 31, 1997, is carrying on its consolidated balance sheet a regulatory asset and a corresponding liability in the amount of $43.4 million, which is the $46.5 million discussed above net of the Company's post-September 1, 1997 cost-of-service payments to Maine Yankee. On September 2, 1997, the MPUC released the report of a consultant it had retained to perform a management audit of Maine Yankee for the period January 1, 1994, to June 30, 1997. The report contained both positive and negative conclusions, the latter including: that Maine Yankee's decision in December 1996 to proceed with the steps necessary to restart the Plant was "imprudent", that Maine Yankee's May 27, 1997 decision to reduce restart expenses while exploring a possible sale of the Plant was "inappropriate", based on the consultant's finding that a more objective and comprehensive competitive analysis at that time "might have indicated a benefit for restarting" the Plant; and that those decisions resulted in Maine Yankee incurring $95.9 million in "unreasonable" costs. The Company has expensed its share of these costs. On October 24, 1997, the MPUC issued a Notice of Investigation initiating an investigation of the shutdown decision and of the operation of the Plant prior to shutdown, and announced that it had directed its consultant to extend its review to include those areas. The Company does not know how the MPUC plans to use the consultant's report, but believes the report's negative conclusions are unfounded and may be contradictory. The Company believes it would have substantial constitutional and jurisdictional grounds to challenge any effort in an MPUC proceeding to alter wholesale Maine Yankee rates made effective by the FERC. On November 7, 1997, Maine Yankee and Central Maine Power initiated a legal challenge to the MPUC investigation in the Maine Supreme Judicial Court alleging that such an investigation falls exclusively within the jurisdiction of the FERC and that the MPUC investigation is therefore barred on constitutional grounds. The Company joined in this appeal. The MPUC subsequently stayed its investigation pending the outcome of Maine Yankee's FERC rate case, while indicating that its consultant would continue its extended review. The Maine Supreme Court, on motions of the parties, stayed the appeal pending resolution of the FERC proceeding. During 1997, the Company incurred Maine Yankee replacement power costs of approximately $7,302,000, of which $2,324,000 has been deferred under the Company's rate stabilization plan, and also incurred additional operating costs of approximately $3.0 million associated with the efforts to restart and subsequently close Maine Yankee, which have adversely impacted the Company's earnings. The February 1, 1998, rate increase, as described in the "Regulatory Proceedings - Four-Year Rate Stabilization Plan" section of this Annual Report, included a portion of these recoverable 1997 Maine Yankee replacement power costs with the remaining costs included in the February 1, 1999 rate increase. However, the collection of future Maine Yankee replacement power costs will be subject to the MPUC's previously-mentioned prudence review of the prudency of closing Maine Yankee. Earnings and Dividends For 1997, the loss per share was $1.35 based on a loss of $2,177,137. Earnings per share in 1996 were $1.31 based on net income available for Common Stock of $2,110,694. For 1995, earnings per share before and after extraordinary items were $.57 and a loss of $3.29, respectively. The average shares outstanding for all three years were 1,617,250. As discussed in the "Maine Yankee" section of this Annual Report, the plant did not operate during 1997 and was shut down permanently in August 1997. The related replacement power and increased capacity expenses reduced earnings by $2.94 per share compared to 1996. In 1995, extraordinary write-offs of $6.2 million, net of income taxes, or $3.86 per share, to eliminate the Company's remaining wholesale investment in Seabrook and other wholesale plant were an element of the four-year rate stabilization plan approved by the Maine Public Utilities Commission on November 13, 1995. In addition, the implementation of the rate plan included a charge of $2.1 million, or $1.30 per share, to operating expenses for previously deferred retail fuel representing the replacement power expenses incurred during the Maine Yankee resleeving outage in 1995. Refer to the "Regulatory Proceedings - Four-Year Rate Stabilization Plan" section of this Annual Report for further discussion. The Company's return on equity for 1997 was a negative 6.02% compared to 5.48% for 1996 and a negative 12.33%, after extraordinary items, for 1995. Your Board of Directors reduced the quarterly dividend from $.46 to $.25 per share effective for the April 1, 1997 payment. The dividends paid in 1997 were $1.21 per share and $1.84 per share in both 1996 and 1995. The dividend reduction, along with other actions to control 1997 construction expenditures and operating expenses, was required to improve the Company's cash flows in response to the difficulties at Maine Yankee. For additional information, see the "Liquidity and Capital Resources" section of this Annual Report. (Page 8) Liquidity and Capital Resources The accompanying "Statements of Consolidated Cash Flows" reflect the Company's liquidity and financial strength. The statements report the net cash flows generated from or used for operating, financing, and investing activities. In 1997, the additional replacement power and capacity expenses to restart and subsequently to close and start decommissioning Maine Yankee significantly reduced the Company's earnings and cash flows. As a result, the Company had to increase short-term borrowing by $5,800,000 to fund operating and construction activities and pay dividends. The Company also withdrew $2.0 million from proceeds held in trust from the 1996 tax-exempt bonds, based on qualifying property additions. As of December 31, 1997, $2.3 million remained in trust to be withdrawn by June 1999. Net cash flows used in operating activities were $1.7 million. The Company paid dividends of $1.2 million, made debt payments of $1.3 million, and invested $2.7 million in electric plant. In 1996, net cash flows generated from operating activities were $7.4 million. During 1996, $15 million in tax-exempt bonds were issued with the proceeds used to refund a $10 million series issued in 1991. The remaining $5 million of proceeds were deposited with the trustee to be withdrawn based on qualifying property additions and eligible issuance costs. During 1996, the Company withdrew $1.1 million from these proceeds, paid dividends of $3 million, made additional long-term debt payments of $1.3 million and invested $3.4 million in electric plant. During 1996, the Company did not require any additional short-term borrowings to meet working capital requirements. The previously mentioned write-offs required by the rate plan in late 1995, the impact of the closure of Loring Air Force Base in the Fall of 1994, and the extended outage required for the resleeving of Maine Yankee all adversely impacted 1995 earnings, resulting in a loss of $5.3 million. Despite the loss, net cash flows generated from operating activities were $3.4 million in 1995, which reflect Maine Yankee replacement power costs of $5.7 million and resleeving costs of $1.3 million. In 1995, the Company borrowed an additional $1.4 million utilizing its short-term credit facilities. During 1995, the Company paid $3 million in dividends, made debt payments of $65,000 and invested $3.4 million in electric plant. For additional information regarding construction expenditures for 1995 to 1997 and anticipated construction expenditures for 1998, see Note 10, "Commitments, Contingencies, and Regulatory Matters - Construction Program", of the Notes to Consolidated Financial Statements. The Company uses short-term borrowings to satisfy working capital requirements. As previously mentioned, in 1997 the Company required additional short-term borrowings from its credit facilities. The Company ended 1997 with $7.2 million of notes outstanding under the credit facilities, while $1.4 million was outstanding at the end of both 1996 and 1995. During 1995 to 1997, required borrowing under the Company's credit facilities were all below the existing prime rate. For additional information on the short-term credit facility, see Note 5, "Short-Term Credit Arrangements", of the Notes to Consolidated Financial Statements. On June 19, 1996, the Maine Public Utilities Financing Bank (MPUFB) issued $15 million of its tax-exempt bonds due April 1, 2021 (the 1996 Series) on behalf of the Company. The proceeds of the new 1996 Series were used to refund the $10 million 1991 tax-exempt Series through the payment of a refunding note from Fleet Bank of Maine and provided $5 million for the acquisition of qualifying property. Pursuant to the long-term note issued under a loan agreement between the Company and the MPUFB, the Company has agreed to make payments to the MPUFB for the principal and interest on the bonds. Concurrently, pursuant to a letter of credit and reimbursement agreement, the Company caused a Direct Pay Letter of Credit for an initial term of three years to be issued by the Bank of New York for the benefit of the holders of such bonds. To secure the Company's obligations under the letter of credit and reimbursement agreement, the Company issued a second mortgage bond to the Bank of New York, as Agent, under the reimbursement agreement, in the amount of $15,875,000. The Company has the option of selecting weekly, monthly, annual or term interest rate periods for the 1996 Series. The initial interest period selected by the Company was weekly, and the initial weekly interest rate was 3.75% per annum. At the end of 1997, the cumulative effective interest rate since issuance for this series was 5.705%. The Company has the ability to finance through the issuance of Common and Preferred Stock. The Company is authorized to issue up to 3,000,000 shares of Common Stock. In addition, the Company's restated articles of incorporation authorize the issuance of $200,000 shares of Preferred Stock with the par value of $100 per share and 200,000 shares of Preferred Stock with the par value of $25 per share. The Company can also issue First Mortgage Bonds of $6.5 million and Second Mortgage Bonds of $24 million without bondable property additions. In order to maintain the Company's common equity at levels appropriate for an investor-owned utility, the Company has repurchased 250,000 shares at a cost of $5,714,376. The original five-year program approved by the Maine Public Utilities Commission (MPUC) expired in September 1994. On November 1, 1994, the MPUC approved the Company's application to repurchase up to an additional 300,000 shares over a five-year period. With the write-offs required by the rate plan and the operating loss in 1997, the Company does not anticipate using the program to adjust its capital structure. In early 1997, in anticipation of a lengthy and expensive outage to restart Maine Yankee, the Company obtained amendments to the short-term revolving credit agreement and the letter of credit supporting the 1996 revenue bonds. These amendments, dated March 28, 1997, modified interest coverage tests to exclude Maine Yankee incremental replacement power costs through September 30, 1997. Under the amendment to the revolving credit agreement, the Company was obligated to issue a first mortgage bond of $11 million by May 15, 1997 as collateral for the maximum amount of its obligations under the agreement. After receiving approval from the Maine Public Utilities Commission on April 28, 1997, the Company issued the bonds on May 5, 1997. As discussed in the "Maine Yankee" section of this Annual Report, the Maine Yankee owners subsequently voted to close the nuclear power plant and start decommissioning. However, the previously-mentioned amendments did not cover additional Maine Yankee replacement and capacity expenses in the fourth quarter of 1997, and the Company was not able to attain its interest coverage tests. (Page 9) The Banks have granted a waiver for these fourth quarter coverage tests. For 1998, the Banks have agreed to amend these interest coverage tests to deal with these additional Maine Yankee costs. Based on the Company's current projections, the Company believes that it can attain these amended interest coverage tests. The final sinking fund payment for the 7-1/8% Series of First Mortgage Bonds of $2.9 million will be made during 1998. The Company estimates that additional short-term borrowings of $2 million will be needed to satisfy the payment. Based on current projections, the Company estimates that operating cash flows will be sufficient to cover its other sinking fund payments, construction activities and other financial obligations. Employees At the end of 1997, the Parent Company had 149 full-time employees compared to 155 for 1996. The Subsidiary had 9 full-time employees for 1997 compared to 10 for 1996. Consolidated payroll costs were $6.5 million for both 1997 and 1996. Local 1837 of the International Brotherhood of Electrical Workers ratified a three-year contract with the Parent Company, effective on October 1, 1996. The agreement included a 2.9% wage increase in the first year and a 2.75% increase in each of the last two years of the contract. The Subsidiary and Local 1733 of the International Brotherhood of Electrical Workers ratified a one-year contract extension effective January 1, 1998. The new agreement includes a wage increase of 1.93% for the calendar year 1998. The three-year contract that expired December 31, 1997 allowed annual wage increases of 3.25%. Regulatory Proceedings Industry Restructuring On May 29, 1997, legislation titled "An Act to Restructure the State's Electric Industry" was signed into law by the Governor of Maine. The principal provisions with accounting impact on the Company are as follows: 1. Beginning on March 1, 2000, all consumers of electricity have the right to purchase generation services directly from competitive electricity suppliers who will not be subject to rate regulation. 2. By March 1, 2000, the Company, Central Maine Power Company (CMP), and Bangor Hydro-Electric Company (BHE) must divest themselves of all generation related assets and business functions except for: a) contracts with qualifying facilities, such as the Company's power contract with Wheelabrator-Sherman (W-S), and conservation providers; b) nuclear assets, namely, the Company's investment in the Maine Yankee Atomic Power Company; c) facilities located outside the United States, i.e., the Company's hydro facility in New Brunswick, Canada: and d) assets that the MPUC determines necessary for the operation of the transmission and distribution services. As required by the electric utility industry restructuring legislation discussed above, the Company has offered for sale all of its generating capacity, including its Canadian subsidiary, with a total net book value of $11.0 million as of December 31, 1997. This plan has been approved by the Maine Public Utilities Commission, which must also approve the ultimate sale of these assets. The Company believes it will take at least a full year to complete this divestiture process, which began in late August, 1997. Bids for the assets were solicited and collected on January 15, 1998, and negotiations with the successful bidders are currently underway. The Company cannot predict the final outcome of the proposed divestiture. 3. The Company, through a regulated affiliate, will continue to provide transmission and distribution services which will be subject to continued rate regulation by the MPUC. 4. Maine electric utilities will be permitted a reasonable opportunity to recover legitimate, verifiable and unmitigable costs that are otherwise unrecoverable as a result of retail competition in the electric utility industry (so-called "stranded costs"). The MPUC shall determine these stranded costs by considering: a) the utility's regulatory assets related to generation, i.e., the Company's unrecovered Seabrook investment; b) the difference between net plant investment in generation assets compared to the market value for those assets; and c) the difference between future contract payments and the market value of the purchased power contracts, i.e., the W-S contract. By July 1, 1999, the MPUC will have estimated the stranded costs or the Company and the manner for the collection of these costs by the transmission and distribution company. Customers reducing or eliminating their consumption of electricity by switching to self-generation, conversion to alternative fuels or utilizing demand-side management measures cannot be assessed exit or entry fees. The Company estimates its stranded costs to be approximately $85 million, based on the completion of the W-S contract restructuring, market power estimates beyond 2000 and regulatory treatment of the Company's remaining Seabrook investment, but does not include any benefits from the Company's sale of generating assets. 5. The MPUC shall include in the rates charged by the transmission and distribution utility decommissioning expenses for Maine Yankee. In 2003, and every three years thereafter until the stranded costs are recovered, the MPUC shall review and adjust the stranded cost recovery amounts and related transition charges. However, the MPUC may adjust the amounts at any point in time that they deem appropriate. Since the legislation provides for our recovery of stranded costs by the transmission and distribution company, the Company will continue to recognize existing regulatory assets and plant costs as provided by Emerging Issues Task Force 97-4 "Deregulation of the Pricing of Electricity" (EITF 97-4). (Page 10) 6. Employees other than officers, displaced as a result of retail competition will be entitled to certain severance benefits and retraining programs. These costs will be recovered through charges collected by the regulated transmission and distribution company. The MPUC will conduct several rulemaking proceedings associated with the new restructuring law. The Company is presently reviewing its business operations and the opportunities that the new restructuring law presents. In accordance with EITF 97-4 when all of the details of the restructuring plan are determined by the MPUC rulemaking, the Company will discontinue application of the Statement of Financial Accounting Standards No. 71 (SFAS 71), "Accounting for the Effects of Certain Types of Regulations", for the generating segment of its business jurisdiction. As a result, the Company continues to defer certain costs as regulatory assets in instances where recovery through future regulatory cash flows is anticipated. Four-Year Rate Stabilization Plan On November 13, 1995, the Maine Public Utilities Commission (MPUC) approved a stipulation signed by the Company, the Commission Staff, and the Maine Public Advocate. This stipulation, effective January 1, 1996, established a multi-year rate plan for the Company that provides our customers with predictable rates through 1999 and shares operating risks and benefits between the Company's shareholders and customers. Under the terms of the stipulation, which applies cost of service principles, the Company's retail rates were increased by 4.4% and 2.9% on January 1, 1996 and February 1, 1997, respectively. The Company has the right to receive additional annual increases in retail rates of 2.75% on February 1, 1998 and February 1, 1999. The Company has agreed that it will seek no other increases, for either base or fuel rates, except as provided under the terms of the plan. There will be no fuel clause adjustments for the duration of the plan. The Company, under the terms of the plan, recognized write-offs in 1995, totaling approximately $8,340,000, net of income taxes, or approximately $5.16 per share. As a result of the application of SFAS No. 101 "Accounting for the Discontinuation of Application of FASB Statement No. 71", approximately $4,846,000, net of income taxes, of the Company's investment in the Seabrook nuclear project previously allocated to wholesale sales and $1,390,000, net of income taxes, of other wholesale plant investment and regulatory assets have been written off and classified as extraordinary items. The remaining segments of the Company continue to meet the criteria of SFAS No. 71 "Accounting for the Effects of Certain Types of Regulation". In addition, $2,104,000, net of income taxes, of deferred retail fuel has been charged to operating expenses. The Company will also be permitted to defer $1,500,000 annually of the costs of its purchases from Wheelabrator-Sherman during each of the four years of the rate plan. The plan permits the Company to recover this deferred amount, up to a total of $6,000,000, in rates beginning in the year 2001. See "Restructured Agreement with Wheelabrator-Sherman" below. The rate plan provides for the deferral, until the year 2000, of approximately $1.3 million, net of income taxes, of uncollected retail fuel at the beginning of the rate plan, while an additional $300,000, net of income taxes, will be collected in rates over the rate plan period. The increases are subject to adjustments resulting from the operation of a profit-sharing mechanism, as well as the mandated cost and plant outage provisions of the plan. The profit-sharing mechanism is based on a target return on equity of 11%, calculated using certain retail ratemaking methodologies, and is available for the rate increases in 1998 and 1999. The profit-sharing mechanism establishes a bandwidth of 300 basis points around the target return on equity. All gains or losses within that bandwidth will be borne entirely by the Company's shareholders. Any earnings above or below the bandwidth will be shared 50/50 by shareholders and customers. Moreover, the Company is allowed to terminate the rate plan and file for a general rate increase if its earnings fall 500 or more basis points below the target return on equity during any twelve-month period during the term of the plan. The plan also provides that if either Maine Yankee or Wheelabrator-Sherman ceases operation for more than six months, the Company will be permitted to adjust its allowed rate increases by half of the net costs or net savings resulting from an outage. Any net costs or net savings realized during the first six months of the outage would accrue entirely to shareholders. The Company is also permitted to adjust the annual increases because of certain mandated costs, such as tax or accounting changes, if any such change affects the Company's annual revenue requirements by more than $300,000. The Company's success under the rate plan was dependent on normal operation of Maine Yankee. As discussed in the "Maine Yankee" section of this Annual Report, Maine Yankee owners voted to close the plant in August of 1997 and the additional expenses associated with restarting and subsequently the efforts to close the plant materially reduced the Company's earnings and cash flows. As previously mentioned, the MPUC is awaiting the FERC's decision on Maine Yankee's FERC rate case before addressing issues regarding the prudency of closing the nuclear power plant. With these uncertainties concerning Maine Yankee, the Company negotiated with the MPUC staff and the Public Advocate to modify the rate plan to deal with these Maine Yankee costs and issues to assure reasonable rates for our customers and reasonable returns to our stockholders. On January 26, 1998, the MPUC approved a 3.9% February 1, 1998 rate increase, according to terms of a stipulation agreed to by the Company and the Public Advocate, with the support of the MPUC staff. The principal elements of the agreement are as follows: 1. The rate increase effective February 1, 1998 was 3.9%, consisting of the specified increase of 2.75% and approximately $562,000 of the 1997 recoverable Maine Yankee replacement power costs (1.15%); 2. The minimum rate increase effective February 1, 1999 will be 3.1%, consisting of a specified increase of 2.0% and the remaining recoverable 1997 Maine Yankee replacement power costs of $523,000; 3. Maine Yankee replacement power costs for the period October 1, 1997 through September 30, 1998 will be offset by the 1998 savings under the restructured Wheelabrator-Sherman contract (See "Restructured Agreement with Wheelabrator-Sherman", below) with the recovery of any incremental Maine Yankee replacement power costs subject to a final order by the MPUC in its review of the prudency of closing Maine Yankee; (Page 11) 4. The Company wrote off unamortized Maine Yankee refueling outage costs of approximately $1,458,000 in 1997; 5. The Company waives its right to collect additional revenues for the profit-sharing review period, i.e. the twelve months ended September 30, 1997, since the earnings deficiency was the result of the closing of Maine Yankee and, based on the 3.9% increase granted by the MPUC, the Company expects to earn a reasonable rate of return in 1998 without these additional revenues; 6. Maine Yankee replacement power costs for the period October 1, 1998 through February 29, 2000 will be deferred for subsequent recovery in retail rates, subject to the MPUC's final order on its prudency review. With the resolution of the uncertainties regarding the near-term recovery of Maine Yankee replacement power costs, the Company has negotiated amendments to the Company's revolving credit agreement and letter of credit and reimbursement agreement supporting the tax-exempt bond issue to avoid violation of interest coverage tests. The Company believes that its rate plan deals effectively with the closing of Maine Yankee, with customers and shareholders sharing the burden equally. However, the Company cannot predict what the MPUC's decisions will be concerning the prudency of closing Maine Yankee. If the Company is adversely impacted by the MPUC prudency decision, or if the Company is unable to complete the financing for the restructured Wheelabrator-Sherman contract, the Company may be required to seek an emergency rate increase and will review all cash expenditures, including the level of dividends. Restructured Agreement with Wheelabrator-Sherman The Company has been attempting for several years to restructure the terms of its current Power Purchase Agreement (PPA) with Wheelabrator-Sherman (W-S). The Company was ordered into the PPA by the MPUC in 1986, which required the purchase of the entire output (up to 126,582 MWH) of a 17.6 MW biomass plant trough December 31, 2000. Under the earlier agreement, either party could renew the agreement for an additional fifteen years at prices to be determined by mutual agreement, or absent mutual agreement, by the MPUC. By agreement dated October 15, 1997, the Company and W-S have finally amended the PPA. Under the terms of this amendment, W-S agreed to reductions in the price of purchased power of approximately $10 million over the PPA's current term in exchange for an up-front payment of $8.7 million. The Company and W-S also agreed to renew the PPA for an additional six years at agreed-upon prices. The Company believes the amended PPA will help relieve the financial pressure caused by the recent closure of Maine Yankee as well as the need for substantial increases in its retail rates, and is, therefore, in the best interests of the Company, its customers, and shareholders. The Company intends to finance the up-front payment to W-S from funds obtained from the Finance Authority of Maine (FAME). Absent FAME financing, the Company does not believe it could obtain the funds on terms sufficiently economic to justify the arrangement with W-S. In its filing with MPUC, the Company further asked the MPUC for a determination that any so-called stranded cost created by the amended PPA will be recoverable from customers to the extent permitted by Maine law. On December 22, 1997, the MPUC approved the amended purchase power agreement and determined that the up-front costs created by the amended PPA will be treated as stranded cost and, therefore, recovered in rates of the transmission and distribution company. On February 19, 1998, the Board of Directors of FAME authorized the issuance and sale of securities under FAME's electric rate stabilization program. The Company expects to complete the financing during the second quarter of 1998. Open Access Transmission Tariff On March 31, 1995, the Company filed an open access transmission tariff with the Federal Energy Regulatory Commission (FERC). This tariff provides fees for various types and levels of transmission and transmission-related services that are required by transmission customers. The tariff, as filed, substantially increases some of the fees for transmission services and provides separate fees for various transmission-related services. On May 31, 1995, the FERC approved the filed tariff, subject to refund. The filing has been vigorously contested by the Company's wholesale customers. In April, 1996, the FERC issued Order 888, a final rule on open transmission access and stranded cost recovery. As a result, the Company refiled its tariff on July 9, 1996 to comply with the Order. Utilities are required to file tariffs under which they would provide transmission services, comparable to that which they provide themselves, to third parties on a non-discriminatory basis. A decision by the FERC is not expected until later in 1998. The Company cannot predict FERC's ultimate decision in this matter. The Company has not recognized approximately $902,000 collected from our transmission customers under the temporary tariff, since the rates are subject to refund. Upon final FERC approval of the open access transmission tariff, the Company will recognize the allowable portion of the revenues and refund the remainder to our transmission customers. Year 2000 Issues The Year 2000 issue is the result of computer programs being written using two digits rather than four to define the applicable year. Computer programs that have date-sensitive software using two digits would recognize a date using "00" as the year 1900 rather than the year 2000, resulting in system failure or miscalculations. The Company will be replacing the one major software application containing the problem in response to the industry restructuring prior to 2000. The Company has reviewed other internal and external interfaces, including its Banks, and determined no further modifications are necessary and that a material impact on the Company's financial position or results of operation is not likely. (Page 12) Forward-Looking Statements The above discussion may contain "forward-looking statements", as defined in the Private Securities Litigation Reform Act of 1995, related to expected future performance or our plans and objectives. Actual results could potentially differ materially from these statements. Therefore, there can be no assurance that actual results will not materially differ from expectations. Factors that could cause actual results to differ materially from our projections include, among other matters, electric utility restructuring; future economic conditions; changes in tax rates, interest rates or rates of inflation; and developments in our legislative, regulatory, and competitive environment. Shareholder Information General The Company's Common Stock is listed and traded on the American Stock Exchange. As of December 31, 1997 and 1996, Common Stock shares issued and outstanding were 1,617,250. As of December 31, 1997, shares were held by 1,436 shareholders or nominees in forty-nine states, the District of Columbia, Canada, Poland, and the United Kingdom. The annual meeting of shareholders is held each year on the second Tuesday in May at the Company's headquarters in Presque Isle. Market price and dividend information relative to the two most recent calendar years are shown in the tabulation below. Income Tax Status of 1997 Dividends The Company has determined that the Common Stock dividends paid in 1997 are fully taxable for federal income tax purposes. These determinations are subject to review by the Internal Revenue Service, and shareholders will be notified of any significant changes. Market Dividends Dividends Price Paid Declared High Low Per Share Per Share 1997 First Quarter $18-3/8 $14-1/8 $ .46 $ .25 Second Quarter $14-3/4 $11-3/8 .25 .25 Third Quarter $12-7/8 $10-3/16 .25 .25 Fourth Quarter $12-13/16 $11-3/8 .25 .25 Total Dividends $1.21 $1.00 1996 First Quarter $22-3/8 $19 $ .46 $ .46 Second Quarter $20-3/8 $16-7/8 .46 .46 Third Quarter $19-1/8 $17-3/8 .46 .46 Fourth Quarter $19-1/2 $17-1/8 .46 .46 Total Dividends $1.84 $1.84 Dividends declared within the quarter are paid on the first day of the succeeding quarter. (Page 13) Five-Year Summary of Selected Financial Data 1997 1996 1995 1994 1993 Operating Revenues $55,072,196 $57,264,165 $55,278,726 $58,368,085 $60,476,212 Income (Loss) Before Extraordinary Items $(2,177,137) $ 2,110,694 $ 920,500 $ 4,845,647 $ 5,300,840 Extraordinary Items, Net of Taxes - - (6,235,812) - - Net Income (Loss) Available for Common Stock $(2,177,137) $ 2,110,694 $(5,315,312) $ 4,845,647 $ 5,300,840 Basic Earnings (Loss) Per Share of Common Stock Income (Loss) Before Extraordinary Items $(1.35) $1.31 $0.57 $2.99 $3.19 Extraordinary Items - - (3.86) - - Net Income (Loss) $(1.35) $1.31 $(3.29) $2.99 $3.19 Dividends Per Share of Common Stock: Declared Basis $1.00 $1.84 $1.84 $1.84 $1.78 Paid Basis $1.21 $1.84 $ 1.84 $ 1.84 $1.76 Total Assets $163,480,739 $116,714,374 $114,074,091 $122,375,442 $124,936,558 Long-Term Debt Outstanding $39,805,000 $41,120,000 $37,435,000 $37,500,000 $39,365,000 Less amount due within one year 4,155,000 1,315,000 1,315,000 65,000 1,865,000 Long-Term Debt $35,650,000 $39,805,000 $36,120,000 $37,435,000 $37,500,000 (Page 14) MAINE PUBLIC SERVICE COMPANY AND SUBSIDIARY Statements of Consolidated Operations Year Ended December 31, 1997 1996 1995 Operating Revenues $55,072,196 $57,264,165 $55,278,726 Operating Expenses Purchased Power 36,608,989 30,444,691 30,541,496 Other Operation and Maintenance 12,769,987 13,814,768 13,262,894 Depreciation 2,497,364 2,447,585 2,438,528 Amortization 1,641,819 1,649,871 1,838,966 Taxes Other Than Income 1,618,208 1,664,685 1,653,228 Provision (Benefit) for Income Taxes (975,093) 1,954,747 1,179,336 Total Operating Expenses 54,161,274 51,976,347 50,914,448 Operating Income 910,922 5,287,818 4,364,278 Other Income (Deductions) Equity in Income of Associated Companies 477,426 350,008 360,684 Allowance for Equity Funds Used During Construction 18,964 7,120 3,667 Provision for Income Taxes (61,183) (103,681) (73,269) Other - Net 59,866 95,678 27,172 Total 495,073 349,125 318,254 Income Before Interest Charges and Extraordinary Items 1,405,995 5,636,943 4,682,532 Interest Charges Long-Term Debt and Notes Payable 3,592,474 3,529,867 3,763,395 Less Allowance for Borrowed Funds Used During Construction (9,342) (3,618) (1,363) Total 3,583,132 3,526,249 3,762,032 Income (Loss) Before Extraordinary Items (2,177,137) 2,110,694 920,500 Extraordinary Items, Net of Taxes of $1,917,399 - - (6,235,812) Net Income (Loss) Available for Common Stock $(2,177,137) $2,110,694 $(5,315,312) Basic Earnings (Loss) Per Share of Common Stock Income (Loss) Before Extraordinary Items $(1.35) $1.31 $.57 Extraordinary Items - - (3.86) Net Income (Loss) $(1.35) $1.31 $(3.29) Average Shares Outstanding 1,617,250 1,617,250 1,617,250 See Notes to Consolidated Financial Statements. (Page 15) MAINE PUBLIC SERVICE COMPANY AND SUBSIDIARY Statements of Consolidated Cash Flows Year Ended December 31, 1997 1996 1995 Cash Flow From Operating Activities Net Income (Loss) $(2,177,137) $2,110,694 $(5,315,312) Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operations: Depreciation 2,497,364 2,447,585 2,438,528 Amortization 1,677,399 1,649,871 1,838,966 Extraordinary Items, After Income Taxes - - 6,235,812 Deferred Income Taxes - Net 812,897 (377,355) 1,165,623 Deferred Investment Tax Credits (72,267) (74,662) (77,027) Allowance for Funds Used During Construction (28,306) (10,738) (5,030) Income on Tax-Exempt Bonds- Restricted Funds (159,114) (118,443) - Change in Deferred Regulatory and Debt Issuance Costs (2,304,765) (267,768) (4,795,603) Change in Deferred Revenues 272,716 275,846 353,653 Change in Benefit Obligations 546,080 874,267 301,164 Change in Current Assets and Liabilities: Accounts Receivable and Unbilled Revenue (800,549) 1,023,602 (246,124) Deferred Fuel and Purchased Energy Cost (562,000) - 442,416 Other Current Assets (1,266,582) (366,995) 39,540 Accounts Payable 396,259 244,157 1,150,497 Accrued Taxes and Interest (82,632) (161,894) 11,374 Other Current Liabilities (19,530) (16,673) 4,291 Other - Net (448,950) 153,205 (115,579) Net Cash Flow Provided By (Used For) Operating Activities (1,719,117) 7,384,699 3,427,189 Cash Flow From Financing Activities Dividend Payments (1,212,938) (2,975,740) (2,975,740) Tax-Exempt Bond Issuance Costs - (398,585) - Issuance of Tax-Exempt Bonds - 15,000,000 - Drawdown of Tax-Exempt Bond Proceeds 1,950,692 1,063,969 - Retirements of Long-Term Debt (1,315,000)(11,315,000) (65,000) Short-Term Borrowings, Net 5,800,000 - 1,400,000 Net Cash Flow Provided By (Used In) Financing Activities 5,222,754 1,374,644 (1,640,740) Cash Flow Used In Investing Activities Investment in Restricted Funds - (5,000,000) - Investment in Electric Plant (2,723,828) (3,444,515) (3,428,784) Net Cash Flow Used In Investing Activities (2,723,828) (8,444,515) (3,428,784) Increase (Decrease) in Cash and Cash Equivalents 779,809 314,828 (1,642,335) Cash and Cash Equivalents at Beginning of Year 1,290,911 976,083 2,618,418 Cash and Cash Equivalents at End of Year $2,070,720 $1,290,911 $ 976,083 Supplemental Disclosure of Cash Flow Information: Cash Paid During The Year For: Interest $3,360,855 $3,536,812 $3,499,198 Income Taxes (1997 is net of tax refunds of $577,000) $(370,709) $2,939,776 $ 235,076 See Notes to Consolidated Financial Statements. (Page 16) MAINE PUBLIC SERVICE COMPANY AND SUBSIDIARY Consolidated Balance Sheets December 31, Assets 1997 1996 Utility Plant Electric Plant in Service $96,395,964 $94,969,297 Less Accumulated Depreciation 47,230,455 45,415,398 Net Electric Plant in Service 49,165,509 49,553,899 Construction Work-In-Progress 699,232 461,435 Total 49,864,741 50,015,334 Investments in Associated Companies 4,128,804 3,658,627 Net Utility Plant and Investments in Associated Companies 53,993,545 53,673,961 Current Assets: Cash and Cash Equivalents 2,070,720 1,290,911 Deposits for Interest and Dividends 64,024 805,512 Accounts Receivable (less allowance for uncollectible accounts in 1997, $215,000 and 1996, $207,028) 5,787,770 5,020,921 Unbilled Revenue 1,686,420 1,652,720 Deferred Fuel and Purchased Energy Costs 687,000 125,000 Current Deferred Income Taxes - 221,578 Inventory 1,230,922 1,194,222 Income Tax Refund Receivable 1,965,852 713,389 Prepayments 223,333 245,914 Total 13,716,041 11,270,167 Other Assets Uncollected Maine Yankee Decommissioning Costs 43,429,478 - Recoverable Seabrook Costs (less accumulated amortization and write-off in 1997, $26,888,235; in 1996, $25,464,603) 26,298,775 27,722,407 Regulatory Assets-SFAS 109 & 106 13,606,672 12,713,312 Restricted Investments (at cost, which approximates market) 2,262,896 4,054,474 Deferred Fuel and Purchased Energy Costs 7,135,137 3,950,512 Unamortized Debt Expense (less accumulated amortization in 1997, $579,513 ; in 1996, $386,573) 799,246 936,376 Deferred Regulatory Costs (less accumulated amortization in 1997, $1,132,024; in 1996, $1,222,948) 1,013,875 1,756,605 Miscellaneous 1,225,074 1,114,752 Total 95,771,153 52,248,438 Total Assets $163,480,739 $117,192,566 See Notes to Consolidated Financial Statements. (Page 17) Capitalization and Liabilities December 31, 1997 1996 Capitalization (see accompanying statements): Common Shareholders' Equity $34,297,362 $ 38,091,749 Long-Term Debt 35,650,000 39,805,000 Total 69,947,362 77,896,749 Current Liabilities: Long-Term Debt Due Within One Year 4,155,000 1,315,000 Notes Payable to Banks 7,200,000 1,400,000 Accounts Payable 4,279,331 3,026,567 Accounts Payable - Associated Companies 623,821 1,182,394 Accrued Employee Benefits 968,079 1,266,011 Deferred Income Taxes Related to Deferred Fuel Costs 6,493 - Dividends Declared 404,313 743,936 Customer Deposits 42,617 62,147 Taxes Accrued 77,448 135,759 Interest Accrued 802,363 826,684 Total 18,559,465 9,958,498 Deferred Credits: Deferred Revenues 902,215 629,499 Uncollected Maine Yankee Decommissioning Costs 43,429,478 - Income Taxes 25,722,328 24,172,421 Investment Tax Credits 648,206 720,473 Miscellaneous 4,271,685 3,814,926 Total 74,973,912 29,337,319 Commitments, Contingencies, and Regulatory Matters (Note 10) Total Capitalization and Liabilities $163,480,739 $117,192,566 (Page 18) MAINE PUBLIC SERVICE COMPANY AND SUBSIDIARY Statement of Consolidated Common Shareholders' Equity Par Value Paid-In Retained Treasury Shares Issued Capital Earnings Stock Balance, January 1, 1995 1,617,250 $13,070,750 $38,317 $39,853,156 $(5,714,376) Net Loss (5,315,312) Dividends: Common Stock ($1.84 per share) (2,975,740) Balance, December 31, 1995 1,617,250 13,070,750 38,317 31,562,104 (5,714,376) Net Income 2,110,694 Dividends: Common Stock ($1.84 per share) (2,975,740) Balance, December 31, 1996 1,617,250 13,070,750 38,317 30,697,058 (5,714,376) Net Loss (2,177,137) Dividends: Common Stock ($1.00 per share) (1,617,250) Balance, December 31, 1997 1,617,250 $13,070,750 $38,317 $26,902,671 $(5,714,376) See Notes to Consolidated Financial Statements. (Page 19) MAINE PUBLIC SERVICE COMPANY AND SUBSIDIARY Consolidated Statements of Capitalization December 31, 1997 1996 Common Shareholders' Equity Common Stock, $7 Par Value-Authorized 3,000,000 Shares in 1997 and 1996; Issued 1,867,250 Shares in 1997 and 1996 $13,070,750 $13,070,750 Paid-In-Capital 38,317 38,317 Retained Earnings 26,902,671 30,697,058 Total 40,011,738 43,806,125 Treasury Stock-Total Shares of 250,000 in 1997 and 1996, at cost (5,714,376) (5,714,376) Total $34,297,362 $38,091,749 Long-Term Debt First Mortgage and Collateral Trust Bonds: 7-1/8% Due Serially through 1998-Interest Payable, May 1 and November 1 * $ 2,880,000 $ 2,920,000 7.95% Due Serially through 2003-Interest Payable, March 1 and September 1 * 1,925,000 1,950,000 9.775% Due Serially through 2011-Interest Payable, March 1 and September 1 * 15,000,000 15,000,000 Second Mortgage and Collateral Trust Bonds: 9.6% Due Serially through 2001-Interest Payable, March 1 and September 1 * 5,000,000 6,250,000 Public Utility Refunding Revenue Bonds- Series 1996: Due 2021-Variable Interest Payable Monthly (4.05% as of December 31, 1997) 15,000,000 15,000,000 Total Outstanding 39,805,000 41,120,000 Less-Amount Due Within One Year 4,155,000 1,315,000 Total $35,650,000 $39,805,000 Current Maturities and Redemption Requirements for the Succeeding Five Years Are as Follows: Long-Term Debt: 1998 $ 4,155,000 1999 $ 1,275,000 2000 $ 1,275,000 2001 $ 2,635,000 2002 $ 2,635,000 Thereafter $27,830,000 * Subject to early redemption premiums as defined in the bond indentures. See Notes to Consolidated Financial Statements. (Page 20) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. ACCOUNTING POLICIES Regulations Maine Public Service Company (the Company) is subject to the regulatory authority of the Maine Public Utilities Commission (MPUC) and, with respect to wholesale rates, the Federal Energy Regulatory Commission (FERC). As a result of the ratemaking process, the applications of accounting principles by the Company differ in certain respects from applications by non-regulated businesses. Consolidation and Basis of Presentation The accompanying consolidated financial statements include the accounts of the Company and its wholly-owned Canadian subsidiary, Maine and New Brunswick Electrical Power Company, Limited (the Subsidiary). All intercompany balances and transactions have been eliminated in consolidation. 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 and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Foreign Currency Translation The functional currency of the Subsidiary is the U.S. dollar. Accordingly, translation gains and losses are included in other income. Income and expenses of the Subsidiary are translated at rates of exchange prevailing at the time the income is earned or the expenses are incurred, except for depreciation which is translated at rates existing on the applicable in-service dates. Assets and liabilities are translated at year-end exchange rates, except for utility plant which is translated at rates existing on the applicable in-service dates. Deferred Fuel and Purchased Energy Costs Prior to 1996, electric rates included adjustment clauses for fuel and purchased energy costs, through which costs above or below base rate levels are recoverable from or refundable to customers. Fluctuations between current base rates and actual costs are deferred until recovered or refunded through subsequent adjustment clauses, in order to properly match costs with the related revenues. With the exception of Wheelabrator-Sherman fuel costs and the sharing provisions for Maine Yankee replacement power, the adjustment clauses have been discontinued under the terms of the 4-year rate plan beginning in 1996. Revenue Recognition Operating revenues include sales billed on a cycle billing basis and estimated unbilled revenues for electric service rendered prior to the normal billing cycle. On May 31, 1995, the FERC approved a temporary wheeling tariff in the Company's open access transmission filing. The Company has not recognized the additional revenues of $902,000 from the temporary tariff, since the increase in the rates charged to our transmission customers are subject to refund. The Company will recognize these deferred revenues, after any adjustment for refunds, when the FERC approves a final tariff in the open access transmission tariff filing. Utility Plant Utility Plant is stated at original cost of contracted services, direct labor and materials, as well as related indirect construction costs including general engineering, supervision, and similar overhead items and allowances for the cost of equity and borrowed funds used during construction (AFUDC). The cost of utility plant which is retired, including the cost of removal less salvage, is charged to accumulated depreciation. The cost of maintenance and repairs, including replacement of minor items of property, are charged to maintenance expense as incurred. The Company's property, with minor exceptions, is subject to First and Second Mortgage liens. Costs which are disallowed or are expected to be disallowed for recovery through rates are charged to income at the time such disallowance is probable. As further explained in Note 10, "Commitments, Contingencies, and Regulatory Matters", certain utility plant previously allocated for ratemaking to the wholesale customers was written off during 1995, resulting in an extraordinary loss. Depreciation and Amortization Utility plant depreciation is provided on composite bases using the straight-line method. The composite depreciation rate, expressed as a percentage of average depreciable plant in service, was approximately 3.01%, 2.99%, and 2.96% for 1997, 1996, and 1995, respectively. Bond issuance costs and premiums paid upon early retirements are amortized over the terms of the related debt. Recoverable Seabrook costs an deferred regulatory expenses are amortized over the period allowed by regulatory authorities in the related rate orders. Recoverable Seabrook costs are being amortized principally over thirty years (Note 10). Costs associated with relicensing hydro facilities are amortized over the thirty-year license period. Income Taxes Statement of Financial Accounting Standards No. 109 (SFAS 109), "Accounting for Income Taxes", requires an asset and liability approach to accounting and reporting income taxes. SFAS No. 109 prohibits net-of-tax accounting and requires the establishment of deferred taxes on all differences between the tax basis of assets or liabilities and their basis for financial reporting. The Company has deferred investment tax credits and amortizes the credits over the remaining estimated useful life of the related utility plant. The Company records regulatory assets or liabilities related to certain deferred tax liabilities or assets, representing its expectation that, consistent with current and expected ratemaking, those taxes will be recovered from or returned to customers through future rates. Investments in Associated Companies The Company records its investments in Associated Companies (see Note 3) using the equity method. Pledged Assets The Common Stock of the Subsidiary is pledged as additional collateral for the First and Second Mortgage and collateral trust bonds of the Company. Inventory Inventory is stated at average cost. (Page 21) Cash and Cash Equivalents For purposes of the Statements of Cash Flows, the Company considers all highly liquid securities with a maturity, when purchased, of three months or less to be cash equivalents. Accounting Pronouncements In February, 1997, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 128, "Earnings per Share". The Company adopted SFAS No. 128 in 1997 with no material impact to financial reporting, financial position, or results of operations. During 1997, the FASB issued SFAS No. 130, "Reporting Comprehensive Income", SFAS No. 131, "Disclosure about Segments of an Enterprise and Related Information", and SFAS No. 132, "Employees' Disclosures about Pensions and Other Postretirement Benefits". The adoption of these statements will have no material impact to the Company's existing financial reporting, financial position, or results of operations. Reclassifications Certain reclassifications have been made to the 1996 and 1995 financial statements in order to conform to the 1997 presentation. 2. INCOME TAXES A summary of Federal, Canadian and State income taxes charged (credited) to income is presented below. For accounting and ratemaking purposes, income tax provisions included in "Operating Expenses" reflect taxes applicable to revenues and expenses allowable for ratemaking purposes. The impact of the extraordinary write-offs described in Note 10, "Commitments, Contingencies, and Regulatory Matters" is highlighted in the table below. The tax effect of items not included in rate base are allocated as "Other Income (Deductions)". 1997 1996 1995 Current income taxes $(1,654,540) $2,510,445 $164,009 Deferred income taxes 812,897 (377,355) (687,190) Investment credits, net (72,267) (74,662) (141,613) Total income taxes $(913,910) $2,058,428 $(664,794) Allocated to: Operating income $(975,093) $1,954,747 $1,179,336 Other income 61,183 103,681 73,269 Extraordinary Items - - (1,917,399) Total $(913,910) $2,058,428 $(664,794) The effective income tax rates differ from the U.S. statutory rate as follows: 1997 1996 1995 Statutory rate (34.0)% 34.0% (34.0)% Excess Canadian taxes 3.3 4.2 1.6 Amortization of recoverable Seabrook costs 9.1 6.7 5.5 State income taxes (5.9) 5.4 (1.7) Seabrook wholesale write-off - - 16.7 Other (2.1) (.9) .8 Effective rate (29.6)% 49.4% (11.1)% The elements of deferred income tax expense (credit) are as follows: (Dollars in Thousands) 1997 1996 1995 Temporary Differences at Statutory Rates: Seabrook - costs $ (200) $ (200) $ (234) Liberalized depreciation 80 166 219 AFUDC-borrowed funds (38) (52) (63) Deferred fuel 1,479 559 582 Deferred regulatory expense (266) (345) 829 Unbilled and deferred revenue (108) (110) (141) Accrued pension and postretirement benefits (182) (414) 40 Other 48 19 (66) Total temporary differences - operations 813 (377) 1,166 Extraordinary Items - - (1,853) Total temporary differences - statutory rates $ 813 $ (377) $ (687) (Page 22) The Company has not accrued U.S. income taxes on the undistributed earnings of the Subsidiary, as the withholding taxes due on the distribution of any remaining amount would be principally offset by foreign tax credits. No dividends were received from the Subsidiary in 1997 and 1995, while dividends were $736,492 in 1996. In 1996, earnings from the Subsidiary exceeded the dividend by $8,608. The following summarizes accumulated deferred income taxes established on temporary differences under SFAS 109 as of December 31, 1997 and 1996. (Dollars in Thousands) 1997 1996 Seabrook $14,489 $15,273 Property 9,565 8,104 Regulatory expenses 1,540 1,201 Deferred fuel 1,631 978 Pension and post- retirement benefits (847) (670) Other (656) (714) Net accumulated deferred income taxes $25,722 $24,172 3. INVESTMENTS IN ASSOCIATED COMPANIES The Company owns 5% of the Common Stock of Maine Yankee Atomic Power Company (Maine Yankee), a jointly-owned nuclear electric power company, and 7.49% of the Common Stock of the Maine Electric Power Company (MEPCO), a jointly-owned electric transmission company. For additional information, see Note 10, "Commitments, Contingencies, and Regulatory Matters - Capacity Arrangements" regarding the closing of Maine Yankee. Dividends received during 1997, 1996, and 1995 from Maine Yankee were approximately $75,000, $333,750, and $172,500, respectively, and from MEPCO approximately $7,600 in each year. Substantially all earnings of Maine Yankee and MEPCO are distributed to investor companies. Condensed financial information (unaudited) for Maine Yankee and MEPCO is as follows: (Dollars in Thousands) Maine Yankee MEPCO 1997 1996 1995 1997 1996 1995 Earnings Operating revenues $238,586 $185,661 $205,977 $25,123 $55,391 $49,699 Earnings applicable to Common Stock $7,613 $6,640 $7,060 $1,463 $220 $105 Company's equity share of net earnings $381 $332 $353 $110 $16 $8 Investment Total assets $1,368,143 $602,061 $580,958 $4,362 $10,727 $6,025 Less: Preferred stock 17,400 18,000 18,600 - - - Long-term debt 76,665 83,332 89,999 420 620 - Other liabilities and deferred credits 1,195,128 429,392 401,158 1,578 9,110 5,147 Net assets $78,950 $71,337 $71,201 $2,364 $997 $878 Company's equity in net assets $3,948 $3,567 $3,560 $177 $75 $66 (Page 23) 4. INVESTMENT IN JOINTLY-OWNED UTILITY PLANT The Company has a 3.3455% ownership interest in a jointly-owned utility plant, W. F. Wyman Unit No. 4 (Wyman), an oil-fired generation plant. The Company's proportionate share of the direct expenses of Wyman are included in the corresponding operating expenses in the statements of consolidated operations. The Company's share in the plant at December 31, 1997 and 1996 is as follows: (Dollars in Thousands) 1997 1996 Electric plant in service $6,976 $5,924 Accumulated depreciation (4,450) (3,231) Net electric plant in service $2,526 $2,693 5. SHORT-TERM CREDIT ARRANGEMENTS The Company has a revolving credit arrangement with two banks. The revolving credit agreement provides for borrowings up to $10 million through October 1998 and is subject to extension with the consent of all participating banks. The Company can utilize, at its discretion, two types of loan options: A Loans, which are provided on a pro rata basis in accordance with each participating bank's share of the commitment amount, and B Loans, which are provided as arranged between the Company and each of the participating banks. The A Loans, at the Company's option, bear interest equal to either the agent bank's prime rate or LIBOR-based pricing. The Company also pays a quarterly commitment fee of .375% of the unused portion of the A Loans. The B Loans bear interest as arranged between the Company and the participating bank. As of December 31, 1997, A Loans totalling $7.2 million were outstanding under this arrangement at 6.5%. As of December 31, 1996, a B Loan for $1.4 million was outstanding at 5.5625%. The Subsidiary has a $200,000 (Canadian) bank line of credit agreement providing for interest at the bank's prime rate. There were no borrowings under this arrangement during 1997. 6. BENEFIT PLANS U.S. Defined Benefit Pension Plan The Company has an insured non-contributory defined benefit pension plan covering substantially all employees. Benefits under the plan are based on employees' years of service and compensation prior to retirement. The Company's policy has been to fund pension costs accrued. For the 1997, 1996, and 1995 plan years, the Company has made contributions of $305,000 in 1998, $282,000 in 1997, and $284,000 in 1996, respectively. The periodic pension cost is comprised of the components listed below as determined using the projected unit credit actuarial cost method. For 1995 and 1996, the Company implemented reduction in force programs. In 1995, these early retirement benefits were deferred and will be amortized over five years in accordance with the rate plan, while for 1996, the increased pension liability was expensed. The components of the net pension cost for 1997, 1996, and 1995 are as follows: (Dollars in Thousands) 1997 1996 1995 Service costs for benefits earned during the period $ 323 $ 298 $ 264 Interest cost on projected benefit obligation 964 939 932 Return on plan assets: Actual (2,645) (1,251) (2,021) Deferred 1,662 298 1,111 Total (983) (953) (910) Net amortization and deferral 1 (2) (2) Net Pension Cost 305 282 284 Early retirement benefits - 402 231 Total Pension Costs $ 305 $ 684 $ 515 The following table sets forth the plan's funded status, obligations, and assumptions as of December 31, 1997 and 1996: (Dollars in Thousands) 1997 1996 Accumulated benefit obligation: Vested $11,865 $11,016 Non-vested 169 153 Total $12,034 $11,169 Projected benefit obligation $(14,685) $(13,041) Fair value of assets 15,123 13,067 Funded status 438 26 Unrecognized prior service costs 817 892 Unrecognized transition amount (403) (481) Unrecognized gain (2,445) (2,008) Accrued Pension Cost $(1,593) $(1,571) Assumptions: Discount rate 7.0% 7.5% Salary increases 4.5% 4.5% Expected return on assets 8.5% 8.5% On December 31, 1997, plan assets consisted of annuity contracts, equity and debt securities, U.S. Treasury obligations, and cash equivalents. Retirement Savings Plan The Company has adopted a defined contribution plan (under Section 401(k) of the Internal Revenue Code) covering substantially all of the Company's employees. Participants may elect to defer from 1% to 15% of current compensation, and the Company contributes such amounts to the plan. The Company also matches contributions, with a maximum matching contribution of 1% of current compensation. Participants are 100% vested at all times in contributions made on their behalf. The Company's matching contributions to the plan were approximately $55,000, $54,000, and $41,000 in 1997, 1996, and 1995, respectively. (Page 24) Health Care Benefits In addition to providing pension benefits, the Company provides certain health care benefits to eligible employees and retirees. All employees share in the cost of their medical benefits, in addition to plan deductibles and coinsurance payments, approximately 14.5% in 1997. Effective with retirements after January 1, 1995, only retirees with at least twenty years of service will be eligible for these benefits. In addition, eligible retirees will contribute to the cost of their coverage starting at 60% for retirees with twenty years of service with the contribution phasing out over the next ten years of service so that retirees with thirty or more years of service do not contribute toward their coverage. The components of net postretirement benefit costs are as follows: (Dollars in Thousands) 1997 1996 1995 Service costs for benefits $103 $ 98 $ 97 Interest cost 343 321 365 Amortization of transition obligation 211 213 213 Total costs 657 632 675 Current payments for retiree obligations allowed in Company's cost of service (217) (233) (207) Additional SFAS 106 costs $440 $399 $468 Based on prior Maine Public Utilities Commission (MPUC) accounting orders, the Company established a regulatory asset of approximately $1,061,000, representing deferred postretirement benefits. As an element of its four-year rate plan, the Company began recovering these deferred expenses over a ten-year period, along with the annual expenses in excess of pay-as-you-go expenses, starting in 1996. The MPUC requires the Company to establish and make payments to an independent external trust fund for the purpose of funding future postretirement health care costs at such time as customers are paying for these costs in their rates. The Company has not established the external trust fund, but will seek approval from the MPUC for a funding plan. The Company's accumulated postretirement benefit obligation and funding status consist of the following: (Dollars in Thousands) 1997 1996 Retirees $(2,710) $(2,283) Fully eligible actives (838) (1,295) Other actives (1,385) (892) Accumulated postretirement benefit obligation (4,933) (4,470) Transition obligation 3,181 3,394 Net gain (341) (762) Accrued postretirement benefit cost $(2,093) $(1,838) There were no unrecognized prior service costs. For 1997 and 1996, the Company used an assumed weighted average discount rate of 7% and 7.5%, respectively. The health care cost trend rate used for 1997 was 8%, with the ultimate trend rate of 5% reached in two years. A one percentage-point increase in the assumed health care cost trend rates for each future year would result in an increase in the accumulated pension benefit obligation by $704,000, and the aggregate of the service and the interest cost components of the net periodic postretirement benefit cost for 1997 would increase by $78,000. 7. COMMON SHAREHOLDERS' EQUITY The Maine Public Utilities Commission has authorized the repurchase of the Company's Common Stock in order to maintain the Company's capital structure at levels appropriate for an investor-owned electric utility. Under an open market program that was extended through November, 1999, the Company has purchased 250,000 shares at a cost of $5.7 million, all of which are held as treasury shares. Under the most restrictive provisions of the Company's long-term debt indentures and short-term credit arrangements, retained earnings (plus dividends declared on Common Stock) available for the distribution of cash dividends on Common Stock were $26,902,671 at December 31, 1997. 8. REFINANCING On June 19, 1996, the Maine Public Utilities Financing Bank (MPUFB) issued $15 million of its tax-exempt bonds due April 1, 2021 (the 1996 Series) on behalf of the Company. The proceeds of the new 1996 Series were used to refund a note from Fleet Bank of Maine, which was used to redeem the 1991 Series and provided $5 million for the acquisition of qualifying property, of which $2.3 million remains in trust as of December 31, 1997. Pursuant to the long-term note issued under a loan agreement between the Company and the MPUFB, the Company has agreed to make payments to the MPUFB for the principal and interest on the bonds. Concurrently, pursuant to a letter of credit and reimbursement agreement, the Company caused a Direct Pay Letter of Credit for an initial term of three years to be issued by the Bank of New York for the benefit of the holders of such bonds. To secure the Company's obligations under the letter of credit and reimbursement agreement, the Company issued a second mortgage bond to the Bank of New York, as Agent, under the reimbursement agreement, in the amount of $15,875,000. The Company has the option of selecting weekly, monthly, annual or term interest rate periods for the 1996 Series, and has, since issuance, selected the weekly interest period. After considering issuance costs and credit enhancement fees, the effective interest rate since issuance as of December 31, 1997 has been 5.705%. 9. FAIR VALUE OF FINANCIAL INSTRUMENTS The Company's financial instruments consist primarily of cash in banks, receivables, and debt. The carrying amounts for cash, receivables, and short-term debt approximate their fair value due to the short-term nature of these items. At December 31, 1997, the Company's long-term debt had a carrying value of approximately $39.8 million and a fair value of approximately $43.0 million. (Page 25) 10. COMMITMENTS, CONTINGENCIES, AND REGULATORY MATTERS Four-Year Rate Plan Approved On November 13, 1995, the Maine Public Utilities Commission (MPUC) approved a stipulation signed by the Company, the Commission Staff, and the Maine Public Advocate. This stipulation, effective January 1, 1996, established a multi-year rate plan for the Company that provides our customers with predictable rates through 1999 and shares operating risks and benefits between the Company's shareholders and customers. Under the terms of the stipulation, which applies cost of service principles, the Company's retail rates were increased by 4.4% and 2.9% on January 1, 1996 and February 1, 1997, respectively. The Company has the right to receive additional annual increases in retail rates of 2.75% on February 1, 1998 and February 1, 1999. The Company has agreed that it will seek no other increases, for either base or fuel rates, except as provided under the terms of the plan. There will be no fuel clause adjustments for the duration of the plan. The Company, under the terms of the plan, recognized write-offs in 1995, totaling approximately $8,340,000, net of income taxes, or approximately $5.16 per share. As a result of the application of SFAS No. 101 "Accounting for the Discontinuation of Application of FASB Statement No. 71", approximately $4,846,000, net of income taxes, of the Company's investment in the Seabrook nuclear project previously allocated to wholesale sales and $1,390,000, net of income taxes, of other wholesale plant investment and regulatory assets have been written off and classified as extraordinary items. The remaining segments of the Company continue to meet the criteria of SFAS No. 71 "Accounting for the Effects of Certain Types of Regulation". In addition, $2,104,000, net of income taxes, of deferred retail fuel has been charged to operating expenses. The Company will also be permitted to defer $1,500,000 annually of the costs of its purchases from Wheelabrator-Sherman during each of the four years of the rate plan. The plan permits the Company to recover this deferred amount, up to a total of $6,000,000, in rates beginning in the year 2001. The rate plan provides for the deferral, until the year 2000, of approximately $1.3 million, net of income taxes, of uncollected retail fuel at the beginning of the rate plan, while an additional $300,000, net of income taxes, will be collected in rates over the rate plan period. The increases are subject to adjustments resulting from the operation of a profit-sharing mechanism, as well as the mandated cost and plant outage provisions of the plan. The profit-sharing mechanism is based on a target return on equity of 11%, calculated using certain retail ratemaking methodologies, and is available for the rate increases in 1998 and 1999. The profit-sharing mechanism establishes a bandwidth of 300 basis points around the target return on equity. All gains or losses within that bandwidth will be borne entirely by the Company's shareholders. Any earnings above or below the bandwidth will be shared 50/50 by shareholders and customers. Moreover, the Company is allowed to terminate the rate plan and file for a general rate increase if its earnings fall 500 or more basis points below the target return on equity during any twelve-month period during the term of the plan. The plan also provides that if either Maine Yankee or Wheelabrator-Sherman ceases operation for more than six months, the Company will be permitted to adjust its allowed rate increases by half of the net costs or net savings resulting from an outage. Any net costs or net savings realized during the first six months of the outage would accrue entirely to shareholders. The Company is also permitted to adjust the annual increases because of certain mandated costs, such as tax or accounting changes, if any such change affects the Company's annual revenue requirements by more than $300,000. The Company's success under the rate plan was dependent on normal operation of Maine Yankee. Maine Yankee owners voted to close the plant in August of 1997 and the additional expenses associated with restarting and subsequently the efforts to close the plant materially reduced the Company's earnings and cash flows. The MPUC is awaiting the FERC's decision on Maine Yankee's FERC rate case before addressing issues regarding the prudency of closing the nuclear power plant. With these uncertainties concerning Maine Yankee, the Company negotiated with the MPUC staff and the Public Advocate to modify the rate plan to deal with these Maine Yankee costs and issues to assure reasonable rates for our customers and reasonable returns to our stockholders. On January 26, 1998, the MPUC approved a 3.9% February 1, 1998 rate increase, according to terms of a stipulation agreed to by the Company and the Public Advocate, with the support of the MPUC staff. The principal elements of the agreement are as follows: 1. The rate increase effective February 1, 1998 was 3.9%, consisting of the specified increase of 2.75% and approximately $562,000 of the 1997 recoverable Maine Yankee replacement power costs (1.15%); 2. The minimum rate increase effective February 1, 1999 will be 3.1%, consisting of a specified increase of 2.0% and the remaining recoverable 1997 Maine Yankee replacement power costs of $523,000; 3. Maine Yankee replacement power costs for the period October 1, 1997 through September 30, 1998 will be offset by the 1998 savings under the restructured Wheelabrator-Sherman contract, with the recovery of any incremental Maine Yankee replacement power costs subject to a final order by the MPUC in its review of the prudency of closing Maine Yankee; 4. The Company wrote off unamortized Maine Yankee refueling outage costs of approximately $1,458,000 in 1997; 5. The Company waives its right to collect additional revenues for the profit-sharing review period, i.e. the twelve months ended September 30, 1997, since the earnings deficiency was the result of the closing of Maine Yankee and, based on the 3.9% increase granted by the MPUC, the Company expects to earn a reasonable rate of return in 1998 without these additional revenues; 6. Maine Yankee replacement power costs for the period October 1, 1998 through February 29, 2000 will be deferred for subsequent recovery in retail rates, subject to the MPUC's final order on its prudency review. The Company was not able to attain its interest coverage tests for the fourth quarter of 1997, but the Banks have granted a waiver. For 1998, the Banks have agreed to amend these interest coverage tests to deal with these additional Maine Yankee costs. Based on the (Page 26) Company's current projections, the Company believes that it can attain these amended interest coverage tests. The Company believes that its rate plan deals effectively with the closing of Maine Yankee, with customers and shareholders sharing the burden equally. However, the Company cannot predict what the MPUC's decisions will be concerning the prudency of closing Maine Yankee. If the Company is adversely impacted by the MPUC prudency decision, or if the Company is unable to complete the financing for the restructured Wheelabrator-Sherman contract, the Company may be required to seek an emergency rate increase and will review all cash expenditures, including the level of dividends. Discontinuance of SFAS 71 for Wholesale Business Segment The wholesale market for electric power is now competitive, as evidenced by the Company's loss of a major wholesale customer, Houlton Water Company. The rates that the Company is now charging its remaining wholesale customers are based on market pricing and not rate base/rate of return regulatory formulas. For this reason, the Company has discontinued the application of Statement of Financial Accounting Standards No. 71 (SFAS 71), "Accounting for the Effects of Certain Types of Regulation", for its wholesale segment of its business jurisdiction. In accordance with the application of SFAS No. 101 "Accounting for the Discontinuation of Application of FASB Statement No. 71", these write-offs were classified as extraordinary items associated with the discontinuance in 1995. Industry Restructuring On May 29, 1997, legislation titled "An Act to Restructure the State's Electric Industry" was signed into law by the Governor of Maine. The principal provisions with accounting impact on the Company are as follows: 1. Beginning on March 1, 2000, all consumers of electricity have the right to purchase generation services directly from competitive electricity suppliers who will not be subject to rate regulation. 2. By March 1, 2000, the Company, Central Maine Power Company (CMP), and Bangor Hydro-Electric Company (BHE) must divest themselves of all generation related assets and business functions except for: a) contracts with qualifying facilities, such as the Company's power contract with Wheelabrator-Sherman (W-S), and conservation providers; b) nuclear assets, namely, the Company's investment in the Maine Yankee Atomic Power Company; c) facilities located outside the United States, i.e., the Company's hydro facility in New Brunswick, Canada; and d) assets that the MPUC determines necessary for the operation of the transmission and distribution services. As required by the electric utility industry restructuring legislation discussed above, the Company has offered for sale all of its generating capacity, including its Canadian subsidiary, with a total net book value of $11.0 million as of December 31, 1997. This plan has been approved by the Maine Public Utilities Commission, which must also approve the ultimate sale of these assets. The Company believes it will take at least a full year to complete this divestiture process, which began in late August, 1997. Bids for the assets were solicited and collected on January 15, 1998, and negotiations with current bidders are currently underway. The Company cannot predict the final outcome of the proposed divestiture. 3. The Company, through a regulated affiliate, will continue to provide transmission and distribution services which will be subject to continued rate regulation by the MPUC. 4. Maine electric utilities will be permitted a reasonable opportunity to recover legitimate, verifiable and unmitigable costs that are otherwise unrecoverable as a result of retail competition in the electric utility industry (so-called "stranded costs"). The MPUC shall determine these stranded costs by considering: a) the utility's regulatory assets related to generation, i.e., the Company's unrecovered Seabrook investment; b) the difference between net plant investment in generation assets compared to the market value for those assets; and c) the difference between future contract payments and the market value of the purchased power contracts, i.e., the W-S contract. By July 1, 1999, the MPUC will have estimated the stranded costs for the Company and the manner for the collection of these costs by the transmission and distribution company. Customers reducing or eliminating their consumption of electricity by switching to self-generation, conversion to alternative fuels or utilizing demand-side management measures cannot be assessed exit or entry fees. The Company estimates its stranded costs to be approximately $85 million, based on the completion of the W-S contract restructuring, market power estimates beyond 2000 and regulatory treatment of the Company's remaining Seabrook investment, but does not include any benefits from the Company's sale of generating assets. 5. The MPUC shall include in the rates charged by the transmission and distribution utility decommissioning expenses for Maine Yankee. In 2003, and every three years thereafter until the stranded costs are recovered, the MPUC shall review and adjust the stranded cost recovery amounts and related transition charges. However, the MPUC may adjust the amounts at any point in time that they deem appropriate. Since the legislation provides for our recovery of stranded costs by the transmission and distribution company, the Company will continue to recognize existing regulatory assets and plant costs as provided by Emerging Issues Task Force 97-4 "Deregulation of the Pricing of Electricity" (EITF 97-4). 6. Employees other than officers, displaced as a result of retail competition will be entitled to certain severance benefits an retraining programs. These costs will be recovered through charges collected by the regulated transmission and distribution company. The MPUC will conduct several rulemaking proceedings associated with the new restructuring law. The Company is presently (Page 27) reviewing its business operations and the opportunities that the new restructuring law presents. In accordance with EITF 97-4 when all of the details of the restructuring plan are determined by the MPUC rulemaking, the Company will discontinue application of the Statement of Financial Accounting Standards No. 71 (SFAS 71), "Accounting for the Effects of Certain Types of Regulations", for the generating segment of its business jurisdiction. As a result, the Company continues to defer certain costs as regulatory assets in instances where recovery through future regulatory cash flows is anticipated. Seabrook Nuclear Power Project In 1986, the Company sold its 1.46% ownership interest in the Seabrook Nuclear Power Project with a cost of approximately $92.1 million for $21.4 million. Both the MPUC and the FERC allowed recovery of the Company's remaining investment in Seabrook Units 1 and 2, adjusted by disallowed costs and sale proceeds, with the costs being amortized over thirty years. With the adoption of the Company's rate plan and the discontinuance of SFAS 71 for the Company's wholesale business, as previously discussed, the Company wrote off its remaining wholesale Seabrook costs of approximately $4,846,000, net of income taxes, in 1995. Recoverable Seabrook costs at December 31, 1997 and 1996 are as follows: (Dollars in Thousands) 1997 1996 Retail $43,136 $43,136 Accumulated Amortization (16,837) (15,414) Retail, Net $26,299 $27,722 Nuclear Insurance In 1988, Congress extended the Price-Anderson Act for fifteen years and increased the maximum liability for a nuclear-related accident. In the event of a nuclear accident, coverage for the higher liability now provided for by commercial insurance coverage will be provided by a retrospective premium of up to $79.3 million for each reactor owned, with a maximum assessment of $10 million per reactor for any year. These limits are also subject to inflation indexing at five-year intervals as well as an additional 5% surcharge, should total claims exceed funds available to pay such claims. Based on the Company's 5% equity ownership in Maine Yankee (see Note 3), the Company's share of any retrospective premium would not exceed approximately $4.0 million or $.5 million annually, without considering inflation indexing. Capacity Arrangements The Company owns 5% of the Common Stock of Maine Yankee, which operated an 860 MW nuclear power plant (the "Plant") in Wiscasset, Maine. On August 6, 1997, the Board of Directors of Maine Yankee voted to permanently cease power operations and to begin decommissioning the Plant. The Plant experienced a number of operational and regulatory problems and has been shut down since December 6, 1996. The decision to close the Plant permanently was based on an economic analysis of the costs, risks and uncertainties associated with operating the Plant compared to those associated with closing and decommissioning it. The Plant's operating license from the Nuclear Regulatory Commission (NRC) was due to expire on October 21, 2008. The Plant generally provided reliable and low-cost power from the time it commenced operations in late 1972 to 1995. Beginning in early 1995, however, Maine Yankee encountered various operational and regulatory difficulties with the Plant. In 1995, the Plant was shut down for almost the entire year to repair a large number of steam generator tubes that were exhibiting defects. Shortly before the Plant was to go back on-line in December 1995, a group with a history of opposing nuclear power released an undated, unsigned, anonymous letter alleging that in 1988 Yankee Atomic (then an affiliated consultant of Maine Yankee) and Maine Yankee had used the results of a faulty computer code as a basis to apply to the NRC for an increase in the Plant's power output. In response to the allegation, on January 3, 1996, the NRC issued a Confirmatory Order that restricted the Plant to 90 percent of its licensed thermal operation level, which restriction was still in effect when the Plant was permanently shut down. As a result of the controversy associated with the allegations, the NRC, at the request of the Governor of Maine, conducted an intensive Independent Safety Assessment (ISA) of the Plant in the Summer and Fall of 1996. On October 7, 1996, the NRC issued its ISA report, which found that while the Plant had been operated safely, there were weaknesses that needed to be addressed, which would require substantial additional spending by Maine Yankee. On December 10, 1996, Maine Yankee responded to the ISA report, acknowledged many of the weaknesses, and committed to revising its operations and procedures to address the NRC's criticisms. Another result of the controversy associated with the allegations was an investigation of Maine Yankee initiated by the NRC's Office of Investigations (OI), which, in turn, referred certain issues to the United States Department of Justice (DOJ) for possible criminal prosecution. Subsequently, on September 27, 1997, the DOJ, through the United States Attorney for Maine, announced that its review had revealed no grounds for criminal prosecution. The Company believes that the OI investigation, however, could ultimately result in the imposition of civil penalties, including fines, on Maine Yankee. In 1996, the Plant was generally in operation at the 90-percent level from late January to early December, except for a two-month outage from mid-July to mid-September. The Plant was shut down again on December 6, 1996, to address several concerns, and has not operated since then. The precipitating event causing the shutdown was the need to evaluate and resolve cable-separation compliance issues, and on December 18, 1996, the NRC issued a Confirmatory Action Letter requiring the Plant to remain shut down until Maine Yankee's plan for resolving the cable-separation issues was accepted by the NRC. Subsequently, Maine Yankee uncovered additional issues, including among others the possibility of having to replace defective fuel assemblies, address additional cable-separation issues, and determine the condition of the Plant's steam generators, all of which contributed to further operational uncertainty. On January 29, 1997, the Plant was placed on the NRC's Watch List, and on January 30, 1997, the NRC issued a supplemental Confirmatory Action Letter requiring the resolution of additional concerns before the Plant could be restarted. In December 1996, Maine Yankee requested proposals from several utilities with large and successful nuclear programs to provide a management team, and ultimately contracted with Entergy Nuclear, Inc., effective February 13, 1997, for management services that included providing a new president and regulatory compliance officer. The Entergy-provided management team made progress in addressing technical issues, but a number of operational and regulatory uncertainties remained. On May 27, 1997, the Board of Directors of Maine Yankee voted to minimize spending while preserving the options of restarting the Plant or conveying ownership interests to a third party. After unsuccessful negotiations with one prospective purchaser, Maine (Page 28) Yankee found no other interest in purchasing the Plant and, based on its economic analysis, closed the Plant permanently. As required by the NRC, on August 7, 1997, Maine Yankee certified to the NRC that Maine Yankee had permanently ceased operations and that all fuel assemblies had been permanently removed from the Plant's reactor vessel. On August 27, 1997, Maine Yankee filed the required Post-Shutdown Activities Report with the NRC, describing its planned post-shutdown activities and a proposed schedule. The Company's 5% ownership interest in Maine Yankee's common equity amounted to $4.0 million as of December 31, 1997, and under Maine Yankee's Power Contracts and Additional Power Contracts, the Company is responsible for 5% of the costs of decommissioning the Plant. Maine Yankee's most recent estimate of the cost of decommissioning is $380.4 million, based on a 1997 study by an independent engineering consultant, plus estimated costs of interim spent-fuel storage of $127.6 million, for an estimated total cost of $508 million (in 1997 dollars). The previous estimate for decommissioning, by the same consultant, was $316.6 million (in 1993 dollars). On September 1, 1997, Maine Yankee estimated the sum of the future payments for the closing, decommissioning and recovery of the remaining investment in Maine Yankee to be approximately $930 million, of which the Company's 5% share would be approximately $46.5 million. Legislation enacted in Maine in 1997 calling for restructuring the electric utility industry provides for recovery of decommissioning costs, to the extent allowed by federal regulation, through the rates charged by the transmission and distribution companies. Based on the Maine legislation and regulatory precedent established by the FERC in its opinion relating to the decommissioning of the Yankee Atomic nuclear plant, the Company believes that it is entitled to recover substantially all of its share of such costs from its customers and, as of December 31, 1997, is carrying on its consolidated balance sheet a regulatory asset and a corresponding liability in the amount of $43.4 million, which is the $46.5 million discussed above net of the Company's post-September 1, 1997 cost-of-service payments to Maine Yankee. On September 2, 1997, the MPUC released the report of a consultant it had retained to perform a management audit of Maine Yankee for the period January 1, 1994, to June 30, 1997. The report contained both positive and negative conclusions, the latter including: that Maine Yankee's decision in December 1996 to proceed with the steps necessary to restart the Plant was "imprudent", that Maine Yankee's May 27, 1997 decision to reduce restart expenses while exploring a possible sale of the Plant was "inappropriate", based on the consultant's finding that a more objective and comprehensive competitive analysis at that time "might have indicated a benefit for restarting" the Plant; and that those decisions resulted in Maine Yankee incurring $95.9 million in "unreasonable" costs. The Company has expensed its share of these costs. On October 24, 1997, the MPUC issued a Notice of Investigation initiating an investigation of the shutdown decision and of the operation of the Plant prior to shutdown, and announced that it had directed its consultant to extend its review to include those areas. The Company does not know how the MPUC plans to use the consultant's report, but believes the report's negative conclusions are unfounded and may be contradictory. The Company believes it would have substantial constitutional and jurisdictional grounds to challenge any effort in an MPUC proceeding to alter wholesale Maine Yankee rates made effective by the FERC. On November 7, 1997, Maine Yankee and Central Maine Power initiated a legal challenge to the MPUC investigation in the Maine Supreme Judicial Court alleging that such an investigation falls exclusively within the jurisdiction of the FERC and that the MPUC investigation is therefore barred on constitutional grounds. The Company joined in this appeal. The MPUC subsequently stayed its investigation pending the outcome of Maine Yankee's FERC rate case, while indicating that its consultant would continue its extended review. The Maine Supreme Court, on motion of the parties, stayed the appeal pending resolution of the FERC proceeding. During 1997, the Company incurred Maine Yankee replacement power costs of approximately $7,302,000, of which $2,324,000 has been deferred under the Company's rate stabilization plan, and also incurred additional operating costs of approximately $3.0 million associated with the efforts to restart and subsequently close Maine Yankee, which have adversely impacted the Company's earnings. The February 1, 1998, rate increase included a portion of these recoverable 1997 Maine Yankee replacement power costs with the remaining costs included in the February 1, 1999 rate increase. However, the collection of future Maine Yankee replacement power costs will be subject to the MPUC's previously-mentioned prudence review of the prudency of closing Maine Yankee. On January 1, 1996 the Company placed Steam Units 1 and 2, totalling 23 MW, of the generating facility in Caribou, Maine on inactive status. During the Units' inactive period, the plant equipment will be protected and maintained by the installation of a dehumidification system that will permit the units to return to service in approximately six months. As discussed above, the Company is seeking buyers for this and the other generating facilities as required by the Industry Restructuring legislation. The Company also owns 7.49% of the Common Stock of Maine Electric Power Company, Inc., (MEPCO). MEPCO owns and operates a 345-KV (kilovolt) transmission line about 180 miles long which connects the New Brunswick Power (NB Power) system with the New England Power Pool. The MEPCO transmission line is also the path by which Wyman Unit No. 4 energy is delivered northerly into the NB Power system and then wheeled to the Parent Company through its interconnection with NB Power at the international border. In July, 1986, Wheelabrator-Sherman, formerly Signal-Sherman Energy Co. (W-S), owner of an 17.6 MW wood-burning cogenerator plant, began selling power to the Company. The Company purchases the entire output from the cogenerator under a Purchase Power Agreement (PPA) ordered by the MPUC that will expire in 2001. This PPA includes a 5% annual price increase. During 1997, 1996, and 1995, purchases from W-S were $15,911,000, $15,593,000, and $14,507,000, respectively. The Company has been attempting for several years to restructure the terms of its current PPA. By agreement dated October 15, 1997, the Company and W-S have finally amended the PPA. Under the terms of this amendment, W-S agreed to reductions in the price of purchased power of approximately $10 million over the PPA's current term in exchange for an up-front payment of $8.7 million. The Company and W-S also agreed to renew the PPA for an additional six years at agreed-upon prices. The Company believes the amended PPA will help relieve the financial pressure caused by the recent closure of Maine Yankee as well as the need for substantial increases in its retail rates, and is, therefore, in the best interests of the Company, its customers, and shareholders. (Page 29) The Company intends to finance the up-front payment to W-S from funds obtained from the Finance Authority of Maine (FAME). Absent FAME financing, the Company does not believe it could obtain the funds on terms sufficiently economic to justify the arrangement with W-S. In its filing with MPUC, the Company further asked the MPUC for a determination that any so-called stranded cost created by the amended PPA will be recoverable from customers to the extent permitted by Maine law. On December 22, 1997, the MPUC approved the amended purchase power agreement and determined that the up-front costs created by the amended PPA will be treated as stranded cost and, therefore, recovered in rates of the transmission and distribution company. On February 19, 1998, the Board of Directors of FAME authorized the issuance and sale of securities under FAME's electric rate stabilization program. The Company expects to complete the financing during the second quarter of 1998. On December 19, 1997, the Company announced the signing of an agreement for the purchase of power until 2000 from Alternative Energy's Beaver Power Plant in Ashland, Maine, as a replacement for Maine Yankee energy. Construction Program Expenditures on additions, replacements and equipment for the years ended December 31, 1997, 1996, and 1995, along with 1998 estimated expenditures, are as follows: (Dollars in Thousands) 1998 1997 1996 1995 (Unaudited Estimates) Parent Company Generation $15 $92 $345 $131 Transmission 757 491 322 364 Distribution 2,688 1,636 2,080 1,993 General 714 425 626 845 Total Parent 4,174 2,644 3,373 3,333 Subsidiary 32 80 72 96 Total $4,206 $2,724 $3,445 $3,429 11. QUARTERLY INFORMATION (unaudited) Quarterly financial data for the two years ended December 31, 1997 is as follows: (Dollars in Thousands Except Per Share Amounts) 1997 by Quarter 1st 2nd 3rd 4th Operating revenues $15,368 $12,339 $12,385 $14,980 Operating expenses (14,847) (11,871) (12,773) (14,670) Operating income 521 468 (388) 310 Interest charges (848) (888) (894) (953) Other income-net 73 67 153 202 Net income $(254) $(353) $(1,129) $(441) Earnings per common share $(0.16) $(0.22) $(0.70) $(0.27) 1996 by Quarter 1st 2nd 3rd 4th Operating revenues $15,625 $14,780 $12,763 $14,096 Operating expenses (13,330) (13,397) (12,627) (12,622) Operating income 2,295 1,383 136 1,474 Interest charges (922) (851) (875) (878) Other income-net 78 77 84 110 Net income $1,451 $609 $(655) $706 Earnings per common share $0.90 $0.38 $(0.41) $0.44 (Page 30 and 31) MAINE PUBLIC SERVICE COMPANY and Subsidiary (Unaudited) All share information and per share amounts reflect the stock split on March 3, 1989. Consolidated Financial Statistics 1997 1996 1995 Capitalization Including Bank Borrowings (year-end) Debt (including amount due within one year) 57.82% 52.75% 49.92% Preferred Stock (including amount due within one year) 0% 0% 0% Common Shareholders' Equity 42.18% 47.25% 50.08% Times Interest Earned - * Before Income Taxes 0.14 2.18 2.51 After Income Taxes 0.39 1.60 1.80 Times Interest and Preferred Dividends Earned - * After Income Taxes 0.39 1.60 1.80 Embedded Cost of Long-Term Debt (year-end) 7.96% 8.01% 9.36% Embedded Cost of Preferred Stock (year-end) 0% 0% 0% Common Shares Outstanding (year-end) 1,617,250 1,617,250 1,617,250 Basic Earnings Per Share of Common Stock (average shares) Income Before Cumulative Effect of Accounting Change and Extraordinary Items $(1.35) $1.31 $ .57 Cumulative Effect of Accounting Change - - - Extraordinary Items - - (3.86) Net Income (Loss) $(1.35) $1.31 $(3.29) Dividends Per Share of Common Stock Declared Basis $1.00 $1.84 $1.84 Paid Basis $1.21 $1.84 $1.84 Common Stock Dividend Payout Ratio - ** - 140.46% 98.40% Book Value Per Share of Common Stock (year-end) $21.21 $23.55 $ 24.09 Market Price Per Share of Common Stock High $18 3/8 $22 3/8 $23 7/8 Low $10 1/4 $16 7/8 $19 7/8 Close $12 $18 1/8 $21 3/8 Price Earnings Ratio (year-end) + - 13.84 - Number of Common Shareholders (year-end) 1,436 1,619 1,634 Consolidated Financial Statistics 1994 1993 1992 1991 Capitalization Including Bank Borrowings (year-end) Debt (including amount due within one year) 44.25% 45.83% 50.16% 53.01% Preferred Stock (including amount due within one year) 0% 0% 0% 0% Common Shareholders' Equity 55.75% 54.17% 49.84% 46.99% Times Interest Earned - * Before Income Taxes 3.25 3.49 3.01 2.81 After Income Taxes 2.26 2.36 2.09 2.00 Times Interest and Preferred Dividends Earned - * After Income Taxes 2.26 2.36 2.09 2.00 Embedded Cost of Long-Term Debt (year-end) 9.36% 9.14% 9.14% 9.28% Embedded Cost of Preferred Stock (year-end) 0% 0% 0% 0% Common Shares Outstanding (year-end) 1,617,250 1,660,250 1,660,250 1,660,250 Basic Earnings Per Share of Common Stock (average shares) Income Before Cumulative Effect of Accounting Change and Extraordinary Items $2.99 $3.19 $2.93 $2.62 Cumulative Effect of Accounting Change - - - - Extraordinary Items - - - - Net Income (Loss) $2.99 $3.19 $2.93 $2.62 Dividends Per Share of Common Stock Declared Basis $1.84 $1.78 $1.76 $1.68 Paid Basis $l.84 $l.76 $1.74 $1.68 Common Stock Dividend Payout Ratio - ** 61.54% 55.80% 60.07% 64.12% Book Value Per Share of Common Stock (year-end) $29.22 $28.02 $26.61 $25.44 Market Price Per Share of Common Stock High $27 3/8 $31 1/4 $26 7/8 $26 3/8 Low $20 1/2 $25 5/8 $24 1/4 $20 3/4 Close $20 3/4 $25 7/8 $25 7/8 $26 3/8 Price Earnings Ratio (year-end) + 6.94 8.11 8.83 10.07 Number of Common Shareholders (year-end) 1,650 1,720 1,768 1,823 Consolidated Financial Statistics 1990 1989 1988 1987 Capitalization Including Bank Borrowings (year-end) Debt (including amount due within one year) 49.40% 43.12% 47.76% 49.32% Preferred Stock (including amount due within one year) 0% 0% 0% 0% Common Shareholders' Equity 50.60% 52.86% 47.83% 42.36% Times Interest Earned - * Before Income Taxes 3.24 3.21 3.07 2.27 After Income Taxes 2.22 2.26 2.29 1.69 Times Interest and Preferred Dividends Earned - * After Income Taxes 2.18 2.09 2.05 1.49 Embedded Cost of Long-Term Debt (year-end) 9.92% 9.71% 10.80% 10.98% Embedded Cost of Preferred Stock (year-end) 0% 9.74% 9.74% 11.20% Common Shares Outstanding (year-end) 1,761,050 1,849,550 1,865,666 1,862,478 Basic Earnings Per Share of Common Stock (average shares) Income Before Cumulative Effect of Accounting Change and Extraordinary Items $2.58 $2.71 $3.12 $1.59 Cumulative Effect of Accounting Change - - - .45 Extraordinary Items - - - - Net Income (Loss) $2.58 $2.71 $3.12 $2.04 Dividends Per Share of Common Stock Declared Basis $1.68 $1.575 $1.175 $ .80 Paid Basis $l.66 $l.55 $1.025 $ .75 Common Stock Dividend Payout Ratio - ** 65.12% 58.12% 37.66% 39.22% Book Value Per Share of Common Stock (year-end) $24.38 $23.39 $22.26 $20.41 Market Price Per Share of Common Stock High $23 3/8 $24 7/8 $20 13/16 $15 7/16 Low $19 1/2 $20 5/16 $11 7/8 $11 1/2 Close $22 1/4 $22 3/8 $20 1/2 $12 9/16 Price Earnings Ratio (year-end) + 8.62 8.26 6.57 6.16 Number of Common Shareholders (year-end) 2,061 1,919 1,933 2,045 * Consolidated income before cumulative effect of accounting change and extraordinary items. Includes AFUDC and Deferred Return on Seabrook Investment. Excludes all regulatory write-offs in 1995. ** 1997 net loss produces a ratio which is not meaningful. Before regulatory write-offs in 1995. + 1997 and 1995 net losses produce ratios which are not meaningful. (Circle Charts) 1997 Sources of Income Millions of Dollars (Total $55.6) and Percent of Total Residential $20.4 Million [36.7%] Commercial $17.4 Million [31.3%] Industrial $9.5 Million [17.1%] Other Electric Sales $5.8 Million [10.4%] Other Income $2.5 Million [4.5%] 1997 Distribution of Income Millions of Dollars (Total $55.6) and Percent of Total Fuel & Purchased Power $37.5 Million [67.4%] Wages and Employee Benefits $6.9 Million [12.4%] Taxes $0.6 Million [1.1%] Other Operating Expenses $9.2 Million [16.5%] Interest $3.6 Million [6.5%] Common Dividends $1.6 Million [2.9%] Retained Earnings $(3.8) Million [(6.8%)] Year-End Capitalization Chart (Page 32 and 33) MAINE PUBLIC SERVICE COMPANY and Subsidiary (Unaudited) Consolidated Operating Statistics 1997 1996 1995 Operating Revenues Residential $20,391,688 $19,961,192 $19,080,662 Commercial and Industrial - Small 17,418,761 16,420,167 15,723,439 Commercial and Industrial - Large 9,452,158 10,111,758 9,437,409 Municipal Street Lighting 546,071 538,890 524,616 Area Lighting 268,208 273,985 272,896 Other Municipal and Other Public Authorities 653,563 710,106 903,370 Other Electric Utilities 4,307,528 6,893,598 7,573,360 Other Operating Revenues 2,034,219 2,354,469 1,762,974 Total Operating Revenues $55,072,196 $57,264,165 $55,278,726 Number of Customers (average) Residential 28,561 28,515 28,385 Commercial and Industrial - Small 5,586 5,541 5,465 Commercial and Industrial - Large 15 15 15 Municipal Street Lighting 39 38 38 Area Lighting 1,063 1,059 1,048 Other Municipal and Other Public Authorities 5 5 5 Other Electric Utilities 11 10 9 Total Customers 35,280 35,183 34,965 Net Generation, Purchases and Sales (thousands of kilowatt-hours) Net Generation: Steam 26,758 10,201 22,867 Hydro 107,734 168,993 121,252 Diesel (429) (674) 1,046 Purchases: Nuclear Generated - 249,083 9,718 Fossil Fuel Generated 496,888 372,431 508,266 Inadvertent Received (Delivered) (494) 741 (1,449) Total 630,457 800,775 661,700 Losses, Unaccounted for and Unbilled 34,128 33,303 36,411 Company Use 1,695 1,517 1,490 Electricity Sold 594,634 765,955 623,799 Sales: Residential 167,368 169,298 168,640 Commercial and Industrial-Small 168,976 163,804 165,914 Commercial and Industrial-Large 134,741 134,588 128,478 Municipal Street Lighting 1,676 1,658 1,655 Area Lighting 1,443 1,418 1,457 Other Municipal and Other Public Authorities 10,204 10,090 11,747 Other Electric Utilities 110,226 285,099 145,908 Total Sales 594,634 765,955 623,799 Average Use and Revenue Per Residential Customer Kilowatt-hours 5,860 5,937 5,941 Revenue $ 713.97 $ 700.02 $ 672.21 Revenue per Kilowatt-hour 12.18c 11.79c 11.31c MAINE PUBLIC SERVICE COMPANY and Subsidiary (Unaudited) Consolidated Operating Statistics 1994 1993 1992 1991 Operating Revenues Residential $19,646,681 $19,669,749 $18,704,900 $19,194,469 Commercial and Industrial - Small 15,614,453 15,177,992 13,787,720 13,991,693 Commercial and Industrial - Large 9,225,131 9,554,566 8,891,123 10,105,693 Municipal Street Lighting 517,793 512,439 499,814 512,640 Area Lighting 271,115 269,925 261,984 267,518 Other Municipal and Other Public Authorities 2,105,933 3,597,514 3,761,815 3,977,098 Other Electric Utilities 8,481,483 9,188,561 8,150,094 7,328,914 Other Operating Revenues 2,505,496 2,505,466 2,626,190 2,460,062 Total Operating Revenues $58,368,085 $60,476,212 $56,683,640 $57,838,087 Number of Customers (average) Residential 28,300 28,220 28,102 28,052 Commercial and Industrial-Small 5,418 5,364 5,261 5,205 Commercial and Industrial-Large 16 16 15 15 Municipal Street Lighting 38 38 38 38 Area Lighting 1,048 1,061 1,075 1,091 Other Municipal and Other Public Authorities 8 8 8 8 Other Electric Utilities 9 8 7 7 Total Customers 34,837 34,715 34,506 34,416 Net Generation, Purchases and Sales (thousands of kilowatt-hours) Net Generation: Steam 18,559 26,456 33,509 28,868 Hydro 118,759 148,719 130,407 135,619 Diesel (153) 169 (636) (178) Purchases: Nuclear Generated 326,334 282,199 263,313 307,769 Fossil Fuel Generated 290,172 288,487 300,930 246,172 Inadvertent Received (Delivered) 651 (1,053) (2,232) 1,861 Total 754,322 744,977 725,291 720,111 Losses, Unaccounted for and Unbilled 42,880 43,944 43,686 42,114 Company Use 1,518 1,542 1,462 1,499 Electricity Sold 709,924 699,491 680,143 676,498 Sales: Residential 175,685 176,732 176,814 176,028 Commercial and Industrial -Small 167,485 162,949 155,267 149,709 Commercial and Industrial -Large 127,327 135,029 129,981 139,931 Municipal Street Lighting 1,642 1,630 1,864 2,336 Area Lighting 1,472 1,482 1,538 1,591 Other Municipal and Other Public Authorities 28,621 53,021 58,388 57,687 Other Electric Utilities 207,692 168,648 156,291 149,216 Total Sales 709,924 699,491 680,143 676,498 Average Use and Revenue Per Residential Customer Kilowatt-hours 6,208 6,263 6,292 6,275 Revenue $ 694.23 $ 697.01 $ 665.61 $ 684.25 Revenue per Kilowatt-hour 11.18c 11.13c 10.58c 10.90c MAINE PUBLIC SERVICE COMPANY and Subsidiary (Unaudited) Consolidated Operating Statistics 1990 1989 1988 1987 Operating Revenues Residential $18,189,325 $18,537,902 $17,787,713 $15,948,095 Commercial and Industrial - Small 12,708,677 13,379,207 12,374,719 10,700,466 Commercial and Industrial - Large 10,115,772 9,785,058 9,673,266 7,736,051 Municipal Street Lighting 505,063 573,351 559,478 541,853 Area Lighting 262,845 288,378 285,979 273,570 Other Municipal and Other Public Authorities 3,611,220 3,736,851 3,546,473 2,955,417 Other Electric Utilities 9,649,398 10,980,817 9,244,874 8,735,459 Other Operating Revenues 1,701,167 (62,314) 649,746 527,707 Total Operating Revenues $56,743,467 $57,219,250 $54,122,248 $47,418,618 Number of Customers (average) Residential 27,983 27,737 27,358 27,074 Commercial and Industrial-Small 5,108 4,940 4,866 4,789 Commercial and Industrial-Large 15 17 18 17 Municipal Street Lighting 38 38 37 37 Area Lighting 1,114 1,155 1,166 1,238 Other Municipal and Other Public Authorities 8 8 8 8 Other Electric Utilities 7 8 7 7 Total Customers 34,273 33,903 33,460 33,170 Net Generation, Purchases and Sales (thousands of kilowatt-hours) Net Generation: Steam 59,252 91,361 81,583 71,649 Hydro 176,832 106,571 112,953 100,158 Diesel (186) 2,664 1,933 572 Purchases: Nuclear Generated 253,321 369,315 266,851 215,006 Fossil Fuel Generated 289,177 217,166 299,838 327,016 Inadvertent Received (Delivered) (151) 1,611 (677) (432) Total 778,245 788,688 762,481 713,969 Losses, Unaccounted for and Unbilled 40,613 42,474 44,883 43,377 Company Use 1,559 1,723 1,555 1,472 Electricity Sold 736,073 744,491 716,043 669,120 Sales: Residential 178,011 178,668 176,680 173,580 Commercial and Industrial -Small 146,881 145,364 139,220 131,535 Commercial and Industrial -Large 155,782 145,307 148,220 133,405 Municipal Street Lighting 2,697 2,722 2,695 2,744 Area Lighting 1,643 1,580 1,585 1,626 Other Municipal and Other Public Authorities 57,034 59,190 59,268 56,180 Other Electric Utilities 194,025 211,660 188,375 170,050 Total Sales 736,073 744,491 716,043 669,120 Average Use and Revenue Per Residential Customer Kilowatt-hours 6,361 6,442 6,458 6,411 Revenue $ 650.01 $ 668.35 $ 650.18 $ 589.06 Revenue per Kilowatt-hour 10.22c 10.38c 10.07c 9.19c (Page 34) Independent Accountants' Report MAINE PUBLIC SERVICE COMPANY: We have audited the accompanying consolidated balance sheets and statements of capitalization of Maine Public Service Company and its Subsidiary, Maine and New Brunswick Electrical Power Company, Limited, as of December 31, 1997 and 1996, and the related consolidated statements of operations, common shareholders' equity, and cash flows for the years then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. The consolidated financial statements of Maine Public Service Company and its Subsidiary for the year ended December 31, 1995 were audited by other auditors, whose report dated February 14, 1996, expressed an unqualified opinion on those statements. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the 1997 and 1996 consolidated financial statements present fairly, in all material respects, the consolidated financial position of Maine Public Service Company and its Subsidiary as of December 31, 1997 and 1996 and the results of their operations and their cash flows for the years then ended in conformity with generally accepted accounting principles. Coopers & Lybrand, L.L.P. Portland, Maine February 13, 1998 (Page 35) Board of Directors Maine Public Service Company's ten-member Board of Directors is composed of nine outside directors and one inside director, Paul R. Cariani. Their diverse business, educational, professional, and civic backgrounds are valuable assets that provide a broad perspective to the issues concerning the Company. G. Melvin Hovey Chairman of the Board and Retired President Maine Public Service Company Presque Isle, Maine Pension Investment Committee Budget and Finance Committee Robert E. Anderson President F. A. Peabody Company Houlton, Maine Pension Investment Committee Budget and Finance Committee Paul R. Cariani President and CEO Maine Public Service Company Presque Isle, Maine Nominating Committee Donald F. Collins Director and Retired President S. W. Collins Co. Caribou, Maine Audit Committee Nominating Committee D. James Daigle President D & D Management Co. Orlando, Florida Executive Compensation Committee Richard G. Daigle President and CEO Daigle Oil Company Cold Brook Energy, Inc., President Fort Kent, Maine Audit Committee Executive Compensation Committee J. Gregory Freeman President and CEO Pepsi-Cola Bottling Company of Aroostook, Inc. Presque Isle, Maine Budge and Finance Committee Nominating Committee Deborah L. Gallant President and CEO D. Gallant Management Associates Portland, Maine Executive Compensation Committee Nathan L. Grass President Grassland Equipment, Inc. Presque Isle, Maine Executive Compensation Committee J. Paul Levesque President and CEO J. Paul Levesque & Sons, Inc. (Lumber Mill) and Antonio Levesque & Sons, Inc. (Logging Operation) Ashland, Maine Audit Committee Pension Investment Committee (Page 36) Executive Officers Paul R. Cariani President & Chief Executive Officer Frederick C. Bustard Vice President Power Supply & Environment Larry E. LaPlante Vice President Finance, Administration, & Treasurer Stephen A. Johnson Vice President Customer Service & General Counsel Peter C. Louridas Assistant To The President Michael A. Thibodeau Assistant Vice President Human Resources Kurt A. Tornquist Controller, Assistant Treasurer & Assistant Secretary Walter J. Elish Director of Economic Development Transfer Agent The Bank of New York Shareholder Relations Dept. - 11E P. O. Box 11258, Church Street Station New York, NY 10286 Tel. No. 1-800-524-4458 E-Mail: Shareowner-svcs@bankofny.com Stock Registrar The Bank of New York Annual Meeting Tuesday, May 12, 1998 Form 10-K The Company will provide shareholders with copies of the Form 10-K upon request. Director and Officer Changes Your Company's Board of Directors suffered a great loss with the untimely death of Walter M. Reed, Jr., on August 21, 1997. The vacancy will not be filled immediately, reducing the number to ten on the Board of Directors. His responsibilities on the Pension Investment Committee and Budget and Finance Committee have been reassigned to other Directors. Walter served on the Board for 18 years and was truly an outstanding business and community leader. He was a valuable source of experience, insight, and advice and will be greatly missed. (Graphic) Crown of Maine Maine Public Service Company 209 State Street P. O. Box 1209 Presque Isle, Maine 04769-1209 Tel. No. (207) 768-5811 FAX No. (207) 764-6586 Home Page: http://www.mainerec.com/mpsco.html E-Mail: mainepub@ mfx.net Exhibit 99(l) INDEPENDENT AUDITORS' REPORT To the Board of Directors and Shareholders of Maine Public Service Company Presque Isle, Maine We have audited the consolidated statements of operations, common shareholders' equity, and cash flows of Maine Public Service Company and its Subsidiary, Maine and New Brunswick Electrical Power Company, Limited, for the year ended December 31, 1995, listed in the Index at Item 14. Our audit also included the financial statement schedule for the year ended December 31, 1995 listed in the Index at Item 14. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audit. We conducted our audit in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion. In our opinion, such consolidated financial statements present fairly, in all material respects, the results of operations and cash flows of Maine Public Service Company and its subsidiary for the year ended December 31, 1995, in conformity with generally accepted accounting principles. Also, in our opinion, such financial statement schedule for the year ended December 31, 1995, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein. /s/ Deloitte & Touche LLP Boston, Massachusetts February 14, 1996 Exhibit 99(m) AMENDMENT NO. 1 to the LETTER OF CREDIT AND REIMBURSEMENT AGREEMENT AMENDMENT NO. 1, dated as of March 28, 1997, to the Letter of Credit and Reimbursement Agreement, dated as of June 1, 1996, among Maine Public Service Company, The Bank of New York, Fleet Bank of Maine, and The Bank of New York, as Agent and Issuing Bank (the "Reimbursement Agreement"). Capitalized terms used herein which are defined in the Reimbursement Agreement shall have the meanings defined therein. The parties hereto wish to amend the Reimbursement Agreement in the manner and with the effect set forth herein. Accordingly, the parties hereto agree as follows: Section 1. Subject to the provisions of Section 2 below, Section 1.01 of the Reimbursement Agreement is amended, effective as of the date of this Amendment, by deleting the definition of "Consolidated Net Income Available for Fixed Charges" in its entirety and substituting therefor the following definition: "Consolidated Net Income Available for Fixed Charges" means, for any specified period, the consolidated income or loss before extraordinary items of the Company and its Subsidiaries for such period, determined in accordance with GAAP, plus (i) Consolidated Interest Expense for such period, plus (ii) the provision for income taxes for such period, minus (iii) the allowance for equity funds used during construction for such period, plus (iv) with respect to any period ending after December 31, 1996, (A) the sum of $598,692 if such period includes the three months ended September 30, 1996, (B) the sum of $553,897 if such period includes the three months ended December 31, 1996, and (C) if such period includes any of the three month periods ended March 31, 1997, June 30, 1997 or September 30, 1997, an amount equal to the incremental cost to the Company of purchased power during each of the relevant three-month periods resulting from the unavailability during such periods of purchased power from the nuclear power plant operated by Maine Yankee Atomic Power Company. Section 2. (a) The continued effectiveness of the amendment provided for in Section 1 of this Amendment shall be subject to the condition subsequent that the Company shall have complied on or before May 15, 1997 (the "Repeal Date") with all of the conditions set forth in Section 2(a) of Amendment No. 4, dated as of March 28, 1997, to the Revolving Credit Agreement (the "Amendment Conditions"). (b) In the event that the Amendment Conditions shall not have been satisfied on or before the Repeal Date, (1) the amendment set forth in Section 1 of this Amendment shall be repealed, effective retroactively to the date of this Amendment and shall be deemed never to have occurred or been effective for any purpose under the Reimbursement Agreement, and (2) any and all certifications delivered by the Company to the Agent and the Banks containing or based on calculations performed in accordance with the Reimbursement Agreement as amended by this Amendment shall be void and of no effect, and the Company promptly shall deliver to the Agent and the Banks revised certifications containing or based on calculations performed in accordance with the Reimbursement Agreement as in effect on the day prior to the date of this Amendment. Section 3. In connection with this Amendment, the Company agrees to pay to the Agent certain fees as set forth in a letter agreement, dated March 26, 1997, between the Company and the Agent. Section 4. Except as amended hereby, the Reimbursement Agreement shall remain in full force and effect. Section 5. This Amendment shall be governed by, and construed in accordance with, the internal laws of the State of New York without regard to principals of conflict of laws. Section 6. By its execution hereof, the Company hereby certifies that the representations and warranties contained in Section 4.01 of the Reimbursement Agreement are true and correct as of the date hereof, except such thereof as specifically refer to an earlier date. Section 7. This Amendment may be executed in any number of counterparts, each of which shall be an original and all of which together shall constitute one amendment. It shall not be necessary in making proof of this Amendment to produce or account for more than one counterpart containing the signature of the party to be charged. IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be duly executed as of the date first above written. MAINE PUBLIC SERVICE COMPANY By: ________________________ Title: _____________________ THE BANK OF NEW YORK, individually and as Agent and Issuing Bank By: _________________________ Title: ______________________ FLEET BANK OF MAINE By: _________________________ Title: ______________________ Exhibit 99(n) AMENDMENT NO. 4 to the REVOLVING CREDIT AGREEMENT AMENDMENT NO. 4, dated as of March 28, 1997, to the Revolving Credit Agreement, dated as of October 8, 1987, by and among Maine Public Service Company, the signatory Banks thereto and The Bank of New York, as Agent, as amended by Amendment No. 1, dated as of October 8, 1989, Amendment No. 2, dated as of May 11, 1992 and Amendment No. 3, dated as of October 8, 1995 (the "Agreement"). Capitalized terms used herein which are defined in the Agreement shall have the meanings defined therein. The parties hereto wish to amend the Agreement in the manner and with the effect set forth herein. Accordingly, the parties hereto agree as follows: Section 1. Subject to the provisions of Section 2 below, paragraph 1 of the Agreement is amended, effective as of the date of this Amendment, by deleting the definition of "Net Income Available for Fixed Charges" in its entirety and substituting therefor the following definition: "Net Income Available for Fixed Charges" shall mean, for any period, net income for such period, adjusted (i) by subtracting any Allowance for Funds Used During Construction and any Deferred Return on Seabrook Investment, (ii) by adding interest charges and federal and state income taxes, and (iii) with respect to any period ending after December 31, 1996, by adding (A) the sum of $598,692 if such period includes the three months ended September 30, 1996, (B) the sum of $553,897 if such period includes the three months ended December 31, 1996, and (C) if such period includes any of the three month periods ended March 31, 1997, June 30, 1997 or September 30, 1997, an amount equal to the incremental cost to the Company of purchased power during each of the relevant three-month periods resulting from the unavailability during such periods of purchased power from the nuclear power plant operated by Maine Yankee. Section 2. (a) The continued effectiveness of the amendment provided for in Section 1 of this Amendment shall be subject to the condition subsequent that the Company shall have delivered all of the following documents and instruments to the Agent (with a copy of items (ii), (iii), (iv) and (v) for each Bank) on or before May 15, 1997 (the "Repeal Date"): (i) a duly executed and authenticated First Mortgage and Collateral Trust Bond, Series due 2005, of the Company in the principal amount of $11,000,000 (the "Bank Mortgage Bond"), registered in the name of the Agent, and issued under and pursuant to the Indenture of Mortgage and Deed of Trust, dated as of October 1, 1945 between the Company and First Trust National Association (successor to Continental Illinois National Bank and Trust Company of Chicago), as Trustee (the "Trustee"), as heretofore supplemented, amended and modified (the "First Mortgage Indenture") and as supplemented by the Supplemental Indenture (as hereinafter defined), and; (ii) an executed copy of a Seventeenth Supplemental Indenture (the "Supplemental Indenture") to the First Mortgage Indenture, providing for the issuance of the Bank Mortgage Bond to secure the obligations of the Company to the Banks and the Agent under the Agreement; and a copy of each document delivered by or to the Company and the Trustee in connection with the issuance, authentication and delivery of the Bank Mortgage Bond; (iii) originals (or copies certified to be true copies by the Secretary or an Assistant Secretary of the Company) of all governmental and regulatory approvals (including, without limitation, approvals or orders of the PUC) necessary for the Company to enter into this Amendment and the Supplemental Indenture and to issue and deliver the Bank Mortgage Bond; (iv) Evidence satisfactory to the Agent that the Supplemental Indenture and any other documents (including, without limitation, financing statements) required to be recorded or filed in order to convey and create in favor of the Trustee for the benefit of the holder of the Bank Mortgage Bond, a perfected lien on and security interest in the property of the Company subject to the lien of the First Mortgage Indenture, as supplemented by the Supplemental Indenture, have been properly recorded and/or filed in each office in each jurisdiction required in order to create a perfected lien on and security interest in such property, and that all necessary recordation and filing fees and all documentary taxes or other expenses related to such filings or recordations have been paid in full; and (v) An opinion of Verrill & Dana, counsel to the Company, dated the date of issuance of the Bank Mortgage Bond, covering the matters set forth in, and otherwise complying with Exhibit A hereto, and covering such other matters as the Agent may reasonably request. (b) In the event that all of the documents set forth in Section 2(a), in form and substance satisfactory to the Agent, shall not have been delivered to the Agent on or before the Repeal Date, (1) the amendment set forth in Section 1 of this Amendment shall be repealed, effective retroactively to the date of this Amendment and shall be deemed never to have occurred or been effective for any purpose under the Agreement, and (2) any and all certifications delivered by the Company to the Agent and the Banks containing or based on calculations performed in accordance with the Agreement as amended by this Amendment shall be void and of no effect, and the Company promptly shall deliver to the Agent and the Banks revised certifications containing or based on calculations performed in accordance with the Agreement as in effect on the day prior to the date of this Amendment. Section 3. In connection with this Amendment, the Company agrees to pay to the Agent certain fees as set forth in a letter agreement, dated March 26, 1997, between the Company and the Agent. Section 4. Notwithstanding the fulfillment or nonfulfillment of the conditions set forth in Section 2(a) of this Amendment, paragraph 11 of the Agreement is amended by deleting the addresses or "the Agent" and "the Banks" and substituting therefor the following: the Agent: The Bank of New York, as Agent One Wall Street New York, New York 10286 Attention: John W. Hall, Vice President the Banks: The Bank of New York One Wall Street New York, New York 10286 Attention: John W. Hall, Vice President Fleet Bank of Maine 80 Exchange Street P.O. Box 923 Bangor, Maine 04402-0923 Attention: Neil C. Buitenhuys, Vice President Section 5. Except as amended hereby, the Agreement shall remain in full force and effect. Section 6. This Amendment shall be governed by, and construed in accordance with, the internal laws of the State of New York without regard to principals of conflict of laws. Section 7. By its execution hereof, the Company hereby certifies that the representations and warranties contained in paragraph 4 of the Agreement are true and correct as of the date hereof, except such thereof as specifically refer to an earlier date. Section 8. This Amendment may be executed in any number of counterparts, each of which shall be an original and all of which together shall constitute one amendment. It shall not be necessary in making proof of this Amendment to produce or account for more than one counterpart containing the signature of the party to be charged. IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be duly executed as of the date first above written. MAINE PUBLIC SERVICE COMPANY By: ________________________ Title: _____________________ THE BANK OF NEW YORK, as Agent and Bank By: _________________________ Title: ______________________ FLEET BANK OF MAINE By: _________________________ Title: ______________________ EXHIBIT A OPINIONS TO BE GIVEN BY COUNSEL TO THE COMPANY This exhibit sets forth the substance of the legal opinions to be included in the opinion letter of Verrill & Dana, counsel to Maine Public Service Company (the "Company"), to be delivered pursuant to Section 2(a)(v) of Amendment No. 4, dated as of March 28, 1997 (the "Amendment") to the Revolving Credit Agreement dated as of October 8, 1987 among the Company, the signatory Banks thereto and The Bank of New York, as Agent, as amended (the "Agreement"). The opinion letter should be in the issuing firm's normal form for opinions given in commercial transactions, subject only to customary qualifications and assumptions. It should be dated the date of issuance of the Bank Mortgage Bond and addressed to (i) The Bank of New York, individually and as Agent, and (ii) Fleet Bank of Maine. Capitalized terms used in this exhibit which are not otherwise defined herein should be understood to have the respective meanings ascribed thereto in the Agreement and the Amendment. Opinions: 1. The Company is a corporation duly organized, validly existing and in good standing under the laws of the State of Maine and has all requisite corporate power and authority to hold and operate its properties and conduct its business as and where now conducted in the State of Maine and to enter into the Amendment and the Supplemental Indenture and to issue the Bank Mortgage Bond as contemplated therein. 2. The First Mortgage Indenture, including the Supplemental Indenture, has been duly executed and delivered by the Company, and the First Mortgage Indenture, as supplemented by the Supplemental Indenture, constitutes a valid and legally binding mortgage of the Company, enforceable against the Company in accordance with its terms. 3. The execution, delivery and performance of the Supplemental Indenture and the creation and issuance of the Bank Mortgage Bond and compliance with the terms thereof have been duly authorized by all necessary corporate action and do not and will not violate any provision of law or, to the best knowledge of such counsel, of any regulation, judgment, order, writ, injunction, determination or award of any court, arbitrator or governmental authority or of the Articles of Incorporation or By- Laws of the Company and will not conflict with or result in a breach of any of the terms, conditions or provisions of, or constitute a default under, or result in the creation or imposition of any mortgage, lien, charge or encumbrance (except as contemplated by the First Mortgage Indenture, as supplemented by the Supplemental Indenture) upon any of the property or assets of the Company pursuant to the terms of, any indenture, mortgage, deed of trust or other agreement or instrument to which the Company or its property is bound. 4. The First Mortgage Indenture, as supplemented by the Supplemental Indenture, creates a valid mortgage lien on the real property, and a valid lien on the personal property, located in the State of Maine described therein as subject to the lien thereof, except as such property may have been released from the lien thereof in accordance with the terms thereof. 5. The First Mortgage Indenture, including the Supplemental Indenture, has been duly recorded as a mortgage on real estate, and financing statements with respect thereto have been filed, in each place in the State of Maine in which such recording or filing is required to be made to perfect and preserve the lien of, or security interest created by, the First Mortgage Indenture; and no other recordation or filing or re- recordation or re-filing thereof is necessary in order to preserve and protect the lien of, or security interest created by, the First Mortgage Indenture, and no taxes are payable to the State of Maine or any subdivision thereof in connection with the execution, authentication, issuance and delivery of the Bank Mortgage Bond, or the mortgaging of property under the First Mortgage Indenture. 6. The Bank Mortgage Bond is in due and proper form, has been duly executed and delivered by the authorized officers of the Company and authenticated by the Trustee, is the valid and legally binding obligation of the Company, is enforceable in accordance with its terms and entitled to the benefits and security of the First Mortgage Indenture and the Supplemental Indenture, and is secured to the same extent as, and on a parity as to all of the trust estate with, all other bonds outstanding under the First Mortgage Indenture. 7. The issuance of the Bank Mortgage Bond pursuant to the First Mortgage Indenture and the Supplemental Indenture has been duly authorized by the Maine Public Utilities Commission, and no other authorization, filing, consent or approval of any public regulatory body of the State of Maine is required in connection with the issuance of the Bank Mortgage Bond or the execution or delivery of the Supplemental Indenture or the Bank Mortgage Bond by the Company. 8. No taxes which have not been paid are payable under the laws of the State of Maine on the original issuance of the Bank Mortgage Bond or the mortgaging of property in connection therewith. Exhibit 99(o) Order Approving Stipulation 1 Docket No. 97-830 STATE OF MAINE PUBLIC UTILITIES COMMISSION Docket No. 97-830 January 30, 1998 MAINE PUBLIC SERVICE COMPANY ORDER APPROVING Annual Increase Under Rate STIPULATION Stabilization Plan WELCH, Chairman; NUGENT and HUNT, Commissioners I. SUMMARY In this Order, we approve a Stipulation that resolves the issues in the Maine Public Service Company (MPS) annual rate change proceeding. By approving the Stipulation, we authorize a 3.9% rate increase to be implemented on February 1, 1998, resolve the ratemaking treatment of some of the 1997 and 1998 Maine Yankee-related costs, and establish a minimum rate increase of 3.1% for February 1, 1999. II. BACKGROUND On November 14, 1997, MPS filed materials in support of its annual rate increase under its previously adopted rate stabilization plan (RSP). See Order Approving Stipulation, Docket No. 95-052 (Nov. 30, 1995). The RSP is a comprehensive multi-year rate plan that contains, among other provisions, specified annual rate changes, a sharing of earnings outside a bandwidth, a sharing of Maine Yankee net replacement costs and Wheelabrator-Sherman (W/S) purchased power savings (1), and customer service and reliability standards. Specifically, the RSP contains a specified February 1, 1998 increase of 2.75% (as well as a 2.75% increase on February 1, 1999) subject to the plan's sharing and customer service penalty provisions. In its November 14 filing, MPS sought a February 1, 1998 (1) The RSP states that any savings from the renegotiation of the W/S Purchase Power Agreement (PPA) will reduce specified deferrals that would be recovered in rates beginning in 2000. In our recent Order that approved the renegotiation of the W/S PPA, we stated that the savings would instead be used to offset rates during the remainder of the rate plan. Order Granting Certificate of Approval, Docket No. 97-727 (Jan. 15, 1998) Order Approving Stipulation 2 Docket No. 97-830 increase of 7.59%, consisting of the 2.75% specified increase, a 2.2% increase for recoverable Maine Yankee replacement power costs, and a 2.62% increase for earnings sharing. The Company also indicated that it would be subject to a penalty of $28,000 for failure to meet one of the customer service standards. As required, the filing included updated marginal costs for pricing flexibility and short-term energy only (STEO) rates for small power producers. Additionally, the Company raised several other items to be resolved in this proceeding: - Maine Yankee refueling outage. During the 1997 outage, Maine Yankee, in anticipation of restarting the plant, incurred refueling outage expenses (approximately $43 million); MPS's share of the expense is approximately $2.1 million. Consistent with prior practice regarding refueling outages, MPS sought to defer and amortize the costs over 18 months (Maine Yankee's previous refueling cycle). MPS began to amortize this amount in August, 1997 so that the unamortized balance on December 31, 1997 was approximately $1,458,000. - Maine Yankee resleeving expenses. The RSP provides for a 5-year amortization of the resleeving expenses incurred in 1995 that would leave approximately $230,000 of these expenses unamortized by the end of the rate plan. Rather than including this amount as stranded costs, the Company proposed a modification so it would amortize the entire amount by the end of the rate plan. - Maine Yankee Sharing. The RSP does not specifically address the sharing of Maine Yankee replacement power costs from October 1, 1998 to January 31, 2000 (the end of the rate plan), because the last rate adjustment is February 1, 1999, using an annual reporting period ending September 30, 1998. The Company requested that the Commission allow it to defer 50% of the net replacement costs for subsequent recovery. - Wheelabrator-Sherman Savings. MPS proposed that it use the savings from the renegotiation of the W/S PPA to partially off-set its 50% share of recoverable Maine Yankee replacement power costs; savings during 1998 would off-set replacement costs during the same period. Order Approving Stipulation 3 Docket No. 97-830 On November 12, 1997, the Commission issued a Notice of Annual Review and Opportunity for Intervention. The Public Advocate filed for and was granted intervention. Both the Public Advocate and the Advisory Staff conducted extensive discovery on the MPS filing. Subsequently, the Company, the Public Advocate, and the Advisory Staff had numerous discussions regarding the resolution of the issues raised by the filing. As a result of these discussions, MPS filed, on January 16, 1998, a Stipulation signed by it and the Public Advocate that resolves the issues in this proceeding. III. DESCRIPTION OF STIPULATION The Stipulation provides for a February 1, 1998 rate increase of 3.9%. This amount represents the 2.75% specified increase plus approximately half of the recoverable Maine Yankee replacement costs during 1997 ($562,000). The remaining $523,000 of the 1997 Maine Yankee costs is deferred and will be recovered in rates as part of the February 1, 1999 rate change regardless of any future prudence determination. The Company agrees to waive any rights under the RSP to recover in rates all amounts associated with its 1997 earnings deficiency ($1,280,000) and to write-off against 1997 earnings all of the unamortized Maine Yankee refueling outage expenses ($1,458,000). As part of the agreement, the parties agreed that the specified February 1, 1999 rate increase of 2.75% shall be reduced to 2.00%, resulting in approximately $380,000 of revenue that MPS will not recover. The February 1, 1999 increase will, as stated above, include the remaining $523,000 of 1997 Maine Yankee replacement costs. As a result, the Stipulation provides for a minimum increase of approximately 3.1% for February 1, 1999 with the Commission's having the discretion to authorize a greater increase. The Stipulation also states that the Company will be able to off-set its recoverable 1998 net Maine Yankee replacement power costs up to the amount of W/S savings, projected to be $2.5 million. This amount of replacement costs will not be subject to disallowance as a result of any future prudence or reasonableness findings regarding Maine Yankee. Additional replacement power cost over those off-set by the W/S savings, estimated to be $900,000, will be deferred but subject to a prudence disallowance. Finally, the Stipulation provides for a suspension of the customer service penalty pending the mid-term review of the RSP. The Stipulation does not contain a provision modifying the Order Approving Stipulation 4 Docket No. 97-830 recovery of 1995 Maine Yankee resleeving expenses. The amortization period will therefore remain unchanged. On January 21, 1998, the Commission held a hearing during which the parties presented the Stipulation and responded to questions. At the hearing, parties agreed that the Commission should approve the updated marginal costs and STEO rates that accompanied the Company's initial November 13, 1997 filing. No party or interested person spoke against the stipulation. Order Approving Stipulation 5 Docket No. 97-830 IV. DISCUSSION MPS's annual rate change filing is designed to be a summary proceeding intended to implement the provisions of the RSP. This year's filing, however, raises a difficult issue because it includes recovery of costs related to the Maine Yankee shutdown. MPS has indicated that virtually all of its requested 7.59% increase above the 2.75% specified amount in the RSP results from Maine Yankee-related costs. The recent permanent shutdown of Maine Yankee has raised issues regarding the reasonableness and prudence of the plant's management over the last several years. Accordingly, the Commission has opened an investigation of the matter, in part based on the findings of a management audit of Maine Yankee (submitted August 29, 1997). Notice of Investigation, Docket No. 97-781 (Oct. 24, 1997). To aid in this Investigation, the Commission ordered a further management audit of Maine Yankee; the results of this audit are expected in the near future. The prudence of Maine Yankee management has also been raised at the FERC (Docket Nos. ER98-570-000, EL98-14-000, EL98-15-000) (2). Because of the nature of the prudence reviews, ultimate findings and ratemaking consequences cannot be expected for at least several months. To the extent that Maine Yankee's past actions were prudent, MPS is entitled under the RSP to recover some of its Maine Yankee-related costs through its February 1, 1998 rate increase. If imprudence is found, MPS may not be entitled to recover some or all of these costs. These circumstances create a dilemma in that, as a practical matter, the Commission can not litigate Maine Yankee prudence in the context of MPS's annual review. The Stipulation in this case presents a creative solution to this dilemma. Essentially, the Stipulation resolves the Maine Yankee costs issue by providing that MPS will not recover certain costs to which it may be entitled, but will recover other costs that, if imprudence is found, may have been disallowed. This is accomplished by an agreement for a write-off of Maine Yankee (2) In an Order issued on December 2, 1997, the Commission stayed its Maine Yankee investigation pending a determination of the issues at FERC; the Order did not stay the ongoing management audit. Order Approving Stipulation 6 Docket No. 97-830 refueling expenses (3), a waiver of recovery of the 1997 earning sharing amount, a reduction in the specified 1999 rate increase, and recovery of a determined amount of 1997 and 1998 net replacement power costs. Amounts of 1998 net replacement power costs beyond the determined amount, as well as Maine Yankee-related costs after 1998 (e.g. continued purchase of replacement power), are subject to disallowance based on imprudence findings. After careful consideration, we conclude that the Stipulation represents an appropriate balance of regulatory litigation risk, the need to moderate rate increases, and the uncertainty involving investigations of Maine Yankee prudence. We note that, even if imprudence is found, MPS is likely to recover some level of Maine Yankee-related costs; only the incremental costs resulting from imprudence generally would be subject to disallowance. Thus, the Stipulation provides a reasonable resolution of this proceeding. Accordingly, we O R D E R 1. That the Stipulation filed on January 20, 1998 is hereby approved and incorporated into this Order; 2. That Maine Public Service Company is authorized to increase its rates by 3.9% effective February 1, 1998; 3. That the updated marginal costs and short-term energy only rates filed on November 14, 1997 are hereby approved. Dated at Augusta, Maine this 30th day of January, 1998. BY ORDER OF THE COMMISSION (3) There is an issue whether MPS was entitled to amortize any costs as a "refueling outage" during 1997. The same issue has been raised in the pending Bangor Hydro-Electric Company rate case (Docket No. 97-116). If the amortization was improper, MPS would recover half of the amortized amount through earning sharing (assuming prudence). Order Approving Stipulation 7 Docket No. 97-830 _______________________________________ Dennis L. Keschl Administrative Director COMMISSIONERS VOTING FOR: Welch Nugent Hunt Order Approving Stipulation 8 Docket No. 97-830 NOTICE OF RIGHTS TO REVIEW OR APPEAL 5 M.R.S.A. s. 9061 requires the Public Utilities Commission to give each party to an adjudicatory proceeding written notice of the party's rights to review or appeal of its decision made at the conclusion of the adjudicatory proceeding. The methods of review or appeal of PUC decisions at the conclusion of an adjudicatory proceeding are as follows: 1. Reconsideration of the Commission's Order may be requested under Section 1004 of the Commission's Rules of Practice and Procedure (65-407 C.M.R.110) within 20 days of the date of the Order by filing a petition with the Commission stating the grounds upon which reconsideration is sought. 2. Appeal of a final decision of the Commission may be taken to the Law Court by filing, within 30 days of the date of the Order, a Notice of Appeal with the Administrative Director of the Commission, pursuant to 35-A M.R.S.A. s. 1320 (1)-(4) and the Maine Rules of Civil Procedure, Rule 73 et seq. 3. Additional court review of constitutional issues or issues involving the justness or reasonableness of rates may be had by the filing of an appeal with the Law Court, pursuant to 35-A M.R.S.A. s. 1320 (5). Note: The attachment of this Notice to a document does not indicate the Commission's view that the particular document may be subject to review or appeal. Similarly, the failure of the Commission to attach a copy of this Notice to a document does not indicate the Commission's view that the document is not subject to review or appeal. Exhibit 99(p) MARKET POWER IN ELECTRICITY a study of market power issues raised by the prospect of retail competition in the electric industry INTERIM REPORT February 2, 1998 presented to the Joint Standing Committee on Utilities and Energy of the Maine Legislature by the Department of the Attorney General and the Public Utilities Commission pursuant to P.L. 1997 ch. 447 Part B ANDREW KETTERER THOMAS L. WELCH Attorney General PUC Chairman STEPHEN L. WESSLER WILLIAM M. NUGENT Director, Public Protection Unit Commissioner FRANCIS ACKERMAN HEATHER F. HUNT Assistant Attorney General Commissioner STATE OF MAINE PUBLIC UTILITIES COMMISSION In Re Market Power Study ) Docket No. 97-877 ) INTERIM REPORT I. INTRODUCTION A. The Statute and the Study Maine's restructuring statute, signed into law May 29, 1997, is designed to promote effective competition in the market for sale and generation of electricity in the State.{1} The statute is grounded on the policy axiom that competitive markets provide higher quality products and services at lower prices. Under the new law, the State's electric power industry, long a bastion of regulation, will embark upon retail competition. As of March 1, 2000, consumers will be able to select among competitive generation providers and marketers. At the same time, recognizing that a proliferation of power delivery systems (including wires, poles etc.) remains impracticable, the statute preserves state regulation of transmission and distribution ("t&d") services. Some economists believe that the introduction of competition to electric markets will result in enormous savings to consumers, as well as benefits to the State's economy as a whole. Others warn that the potential benefits of competition 1. P.L. 1997 ch. 316, much of which is codified at 35-A M.R.S.A. Sections 3201-3217. cannot be realized in wholesale and retail electric power markets in Maine and New England unless these markets are structured at the outset in such a way as to avoid control by a few large competitors. Recognizing that the exercise of market power by a few large companies poses a serious threat to these newly competitive markets, the Legislature immediately followed its enactment of the restructuring statute with passage of a law directing the Department of the Attorney General ("Department") and the Public Utilities Commission ("Commission") jointly to conduct a comprehensive study of market power issues. A final report of the Department's and Commission's findings and recommendations is due December 1, 1998.{2} The purpose of the required market power study is to identify those aspects of the electric power market which may frustrate the statutory goal of introducing effective competition to Maine's electric markets. In conducting the study, therefore, the Department and the Commission must assess the extent to which the restructuring statute has accomplished its objectives, and, wherever necessary, offer recommended corrections or additions.{3} 2. P.L. 1997 ch. 447 Part B. 3. The Legislature directed that the study examine the effects of the transition from cost-based to bid-based dispatch; the potential for horizontal and vertical market power; the effect of imbalances of supply and demand; the significance of transmission constraints and the ownership of transmission ties; the significance of the isolation of portions of the grid from the New England Power Pool grid; geographic market definition issues; and the scope of federal jurisdiction. Id., section B-1. All of these issues receive preliminary consideration in this interim report. In the final report, we plan to review, in addition, approaches taken by other states to address market power issues. -2- The Legislature also directed that the Department and the Commission provide a report of their preliminary findings and recommendations as of February 1, 1998. The purpose of the required preliminary assessment is to identify market power issues which may require immediate legislative attention by the Second Regular Session of the 118th Legislature, and cannot await the final report. This Interim Report responds to the Legislature's directive in this regard. We begin by offering a working definition of market power, and explain briefly why antitrust law has only limited ability to remedy the problem. Then, in the sections following, we turn first to a detailed assessment of vertical market power issues affecting the retail market, then to a review of horizontal market power issues in two wholesale markets: those for energy generally, and for renewables (as defined in the statute). We conclude that there is no area or issue which requires legislative attention on an emergency basis. However, we identify a number of issues which raise significant competitive concerns and therefore merit further analysis and study. Additionally, this preliminary report identifies competitive issues which the Department and the Commission may address in the context of regulatory or court proceedings. While no legislative recommendations are offered at this time, we nevertheless discuss options available to address the problems identified. We are confident that further analysis will permit us to offer specific recommendations in the context of our final report, due December 1, 1998. -3- B. Market Power and the Limits to Antitrust Market power comes in two forms, horizontal and vertical. Horizontal market power may be defined as the ability of a single dominant firm or a group of dominant firms to profit by deviating upward from competitive, marginal cost pricing (i.e., by charging higher, or supracompetitive prices). The higher the market shares of the individual firms, and the smaller the number of firms competing in a market, the more that market will be subject to the exercise of market power, and the less consumers will receive the benefits of higher quality and lower price. An illustration of this phenomenon is the British experience of electric power deregulation. In Britain, a state-owned industry was privatized, and split between only two firms. This extraordinarily high concentration of market power led to higher prices, and ultimately to the reimposition of regulation in the form of price ceilings. Vertical market power, in contrast, derives from a single firm's integrated presence at more than one level of commerce. For example, a firm which combines generation or retail marketing of electric power with provision of t&d services is vertically integrated. Vertical integration in itself is not necessarily anticompetitive. Indeed, it is often efficient and beneficial to consumers. However, where a vertically integrated firm is a regulated monopolist at one level of commerce, it may possess the ability to project its monopoly power to another level. For example, an electric t&d company with a regulated monopoly in a given service area might possess the ability to cross-subsidize -4- a retail marketing affiliate at ratepayers' expense by providing services to the affiliate free of charge, or at subsidized prices. This would enable the affiliate to compete unfairly in retail markets. Such an exercise of vertical market power could deter other would-be competitors from entering the market, and permit the vertically integrated company to gain market power in the retail market. The options available to antitrust enforcement agencies to remedy vertical or horizontal market power in newly restructured markets are limited and often inadequate. In essence, there are only three opportunities for antitrust intervention. First, a proposed merger or acquisition which significantly increases horizontal concentration (and reduces competition) is subject to effective challenge under state or federal antitrust laws.{4} Second, collusive agreements or combinations among competitors (e.g. price fixing) are illegal under antitrust law, and subject to both criminal and civil enforcement.{5} Finally, exclusionary conduct by a monopolist can be attacked as a monopolization offense, though such cases are notoriously lengthy, cumbersome and difficult to prove.{6} It remains that preexisting market power, short of monopoly, which is entrenched in the structure of the industry and exercised unilaterally, is beyond the reach of antitrust. In view of the limitations of antitrust enforcement, it is essential that 4. See 10 M.R.S.A. section 1102-A; 15 U.S.C. section 18. Vertical mergers are also subject to challenge in certain circumstances. 5. See 10 M.R.S.A. section 1101; 15 U.S.C. section 1. 6. See 10 M.R.S.A. section 1102; 15 U.S.C. section 2. -5- Maine ensure, as far as the reach of its jurisdiction will allow, that newly opened electric power markets are competitively structured on day one. If the wholesale generation market or the retail market embark on competition with highly concentrated structures, or structures otherwise susceptible to the exercise of market power, antitrust enforcers will have relatively limited remedial options, and consumers may well pay supracompetitive prices. II. EXECUTIVE SUMMARY A. Introduction Maine's restructuring statute is designed to promote competition in electricity markets. Potential benefits to consumers in lower prices, however, may not be achieved unless these markets are structured from the outset in such a way as to avoid control by a few large competitors. Existing antitrust remedies possess only limited effectiveness to address the problem of market power. The purpose of this study, mandated by the Legislature, is to assess the extent to which electricity markets of which Maine forms a part are subject to market power, and to make recommendations as to whether the restructuring statute should be adjusted in light of that assessment. In this interim report of our findings, we offer no specific legislative recommendations, but do discuss the nature and extent of the problem of market power in relevant markets, and review the available remedies, legislative and otherwise. -6- B. Vertical Market Power Vertical integration of a regulated t&d monopoly with a marketer of electricity results in market power which can find expression through unfair cross-subsidization and favoritism. If allowed to proceed unchecked, these practices could deter entry and result in market dominance by the monopoly affiliate. This could harm Maine consumers in two ways: they would pay for the regulated monopoly's cross-subsidization; and receive higher retail prices in a concentrated market. Two remedies are available: divestiture combined with a marketing ban; and regulation. Maine's restructuring statute, while mandating divestiture of generation, permits affiliate marketing subject to a code of conduct and, in the case of CMP and BHE, a market share limitation. While acknowledging the comprehensiveness of the statutory code of conduct, and the radical nature of the market share limitation, we intend to analyse further the question whether the regulatory solution adopted by the Legislature holds any benefit for ratepayers which would justify preferring it over an outright ban on affiliate marketing. A recommendation in this regard will be forthcoming in the final report. C. Horizontal Market Power: Wholesale Energy Horizontal market power, defined as the ability of one or more dominant firms to profit by deviating upward from competitive, marginal cost pricing, can be gauged in terms of individual market shares and overall market concentration, as measured by the Herfindahl-Hirschman Index. The relevant product markets are wholesale energy and renewables as defined in the restructuring statute. There are two primary relevant geographic markets: New -7- England (including southern and central Maine) and Aroostook County (which is isolated from the New England grid). In addition, there may be a load pocket indicating a separate geographic market in southern and central Maine in a limited number of peak usage hours. Finally, the possibility that more localised load pockets could develop merits analysis. New England market. The New England market is highly concentrated, indicating a significant degree of market power. The primary repositories of market power are two southern New England utilities, NU and USGen. Computer model simulations show that NU and USGen possess sufficient market share to engage in strategic behavior which would enable them to drive up spot market prices by withholding capacity. Accordingly, horizontal market power represents a serious threat in this market. Remedial options are limited. The Department may have the ability to advocate for divestiture in the context of antitrust merger proceedings or regulatory proceedings before FERC. However, state legislative influence is confined to the margin, since wholesale electric rates, and the operation of wholesale markets, are squarely within the exclusive jurisdiction of FERC. To the extent that a load pocket exists in southern and central Maine, the Commission already possesses statutory authority to remedy market power within the load pocket, if necessary, by imposing appropriate conditions on its approval of CMP's proposed divestiture of generation assets. The advisability of statutory adjustments relating to demand side management and transmission enhancements will be analysed in the final report; in addition, -8- possible amendments to laws governing profiteering in necessities and unfair trade practices will be considered. Aroostook County market. The Aroostook County market is also highly concentrated. Again, the Commission already possesses the statutory authority to bring about some limited reduction in this level of concentration by imposing conditions on its approval of MPS' divestiture of generation assets. The Department stands ready to review any proposed acquisition for antitrust compliance. The final report will review, in light of intervening developments, how best to prepare the Aroostook County market for retail choice. The advisability of other legislative adjustments, again including demand side management and transmission enhancements, will also be considered. D. Horizontal Market Power: Renewables Maine's portfolio requirement that competitive electricity providers demonstrate that 30% of their electricity supply derives from renewable sources as defined in the statute effectively creates a separate renewables product market. With respect to southern and central Maine, the relevant geographic market is New England; Aroostook County may also become a part of the New England market if the Commission creates, by rule, a market in tradeable renewable credits. The New England renewables market is highly concentrated, indicating a high degree of market power. The problem is especially serious in this market in that competitors with high market shares in renewables may possess the ability to deny other players entry to Maine's energy markets generally. Existing remedies are limited. -9- The Commission possesses authority to address market power in renewables by imposing appropriate conditions, if necessary, on its approval of CMP's and MPS' proposed divestiture of generation assets. The Department possesses antitrust authority to review mergers. Finally, this interim report suggests that the ability of competitors with high renewables market shares to exclude others from Maine energy markets generally could be addressed by regulatory or legislative provision of a safety valve. For example, a competitor could be accorded permission to make good a renewable deficit by paying it back in a subsequent year, or by contributing to a fund for promotion of renewables. III. VERTICAL MARKET POWER ISSUES A. Vertical Market Power Vertical integration of a regulated t&d monopoly with an affiliate which is a marketer of electricity (or a competitive provider of generation) results in market power. In the absence of a legislative or regulatory solution, this vertical market power exhibits itself through unfair cross-subsidization of, and favoritism in its dealings with, the affiliate. Linked by common ownership and driven by the profit motive and their duty to stockholders, the monopoly and its affiliate can be expected to seek and exploit every lawful opportunity to collaborate for their common advantage. Through unfair cross-subsidization and favoritism, a vertically integrated company can deter would-be competitors from entering the market, and seize a dominant market share. -10- This phenomenon can occur in various forms, of which the direct provision of free or subsidized services by the monopoly to its affiliate is only the most obvious. The regulated t&d monopoly can also afford the affiliate access to strategic information unavailable to competitors. Information regarding customer loads, for example, would give the affiliate a distinct competitive advantage.{7} Further, where the regulated monopoly is also the incumbent utility, the affiliate may have the opportunity to reap significant competitive advantage through the use of the monopoly's name, which carries with it a reputation for reliable service. The regulated monopoly can also provide its affiliate with other valuable marketplace advantages -- for example, the assurance that repairs will be performed first for the affiliate's customers; that the t&d will steer new customers to the affiliate rather than to competitors; or that other subtle preferences will be accorded. In the aggregate, these manifestations of vertical market power represent a significant threat to the success of restructured electric power markets. Simply put, the danger is that if such market power is given free rein, it will deter new competitors from entering the market, and unfairly disadvantage those which do enter. This is an especially serious risk in Maine which, as a small, largely rural market, may not offer potential entrants the returns available elsewhere.{8} If power 7. Information regarding loads would enable the affiliate to target its pricing to the circumstances of the particular customer. The restructuring statute provides that "[u]pon request from a competitive electricity provider, the commission shall provide load data on a class basis that is in the possession of a transmission and distribution utility..." 35-A M.R.S.A. section 3203 (16). 8. Maine's advertising markets, generally speaking, are separate from those of southern New England. -11- marketers conclude that incumbent utility affiliates can exert vertical market power to seize the lion's share of the Maine market, they may well conclude that the game is not worth playing. In that situation, Maine consumers would pay twice: once as ratepayers to finance the regulated monopoly's cross-subsidization practices; and a second time in the higher prices that could be expected in a concentrated market with a low level of competition. B. Remedies Two remedies are available to combat vertical market power: divestiture and regulation. In its original proposal for Maine's restructuring statute, the Commission recommended divestiture. Ultimately, however, while requiring divestiture of generation assets, the Legislature chose to permit limited retail marketing by an affiliate of the t&d monopoly, subject to regulation. Vertical divestiture which legally separates the regulated t&d monopoly from generation and marketing functions eliminates the problem of vertical market power. Deprived of retail presence, the regulated t&d company would have no ability to reap any retail advantage from its monopoly position. Divestiture combined with a ban on marketing by the regulated monopoly thus represents a complete and totally effective prophylactic solution to the problem of vertical market power. The regulatory alternative selected by the Legislature, while requiring divestiture of generation assets, permits the regulated monopoly to maintain a retail marketing presence through an affiliate. The statute attempts to deal with the -12- problem of vertical market power in two ways: (1) by limiting the largest vertically integrated marketers in the State (Central Maine Power and Bangor Hydro-Electric Co.){9} to a one-third market share in the regulated monopoly's service territory; and (2) by subjecting CMP, BHE and the remaining vertically integrated marketer, Maine Public Service Co.,{10} to a statutory or regulatory code of conduct to be enforced by the Commission.{11} The legislative choice of this regulatory response to vertical market power raises three questions: (1) Can enforcement of the statutory and regulatory codes of conduct effectively prevent market power from being exercised? (2) Will the one-third market share limitation applicable to CMP and BHE sufficiently reduce the risk of deterring retail entry into (or encouraging exit from) their service territories? (3) What is the likely cost of the required regulatory effort, and who should pay for it?{12} 9. Hereinafter "CMP" and "BHE" respectively. 10. Hereinafter "MPS". 11. 35-A M.R.S.A. sections 3205-3206. 12. The restructuring statute does require the Commission to report to the Legislature annually (on December 31st of each calendar year) regarding its "actual and estimated future costs of enforcing and implementing the provisions of this chapter governing the relationship between a [t&d] utility and an affiliated competitive electricity provider and the costs incurred by [t&d] utilities in complying with those provisions." 35-A M.R.S.A. section 3217(1). At the outset, the Commission's costs are chargeable to its general budget funded by utility assessments, and ultimately to ratepayers. -13- In our view, each of these questions requires further analysis prior to implementation of the legislation. We are preparing to conduct such analysis, and make any needed recommendations for legislation addressing this issue, in our final report. In the present context, we offer the following comments, which will shed some light on the nature of the questions we propose to examine. C. Codes of Conduct The code of conduct enacted by the Legislature for application to CMP and BHE appears to be a fairly comprehensive effort to police the vertical relationship between a t&d company and its affiliated retail marketer.{13} Particularly noteworthy is the ban on joint advertising. While there may well be areas in which improvements are possible, the larger issue deserving of attention in the final report is whether any code of conduct can effectively prevent the exercise of vertical market power. The problem is not a new one. Vertical market power and cross-subsidization were the crux of the historic monopolization case brought by the U.S. Department of Justice against AT&T. The government, in seeking divestiture in that case rather than a court-ordered code of conduct, clearly subscribed to the belief that a code of conduct ultimately would be ineffective to achieve its purpose. In approving the 1982 settlement, the court agreed: AT&T's pattern during the last thirty years has been to shift from one anticompetitive 13. The statutory code of conduct applies only to CMP and BHE, but could form the basis for a regulatory code to be applied to MPS. -14- action to another, as various alternatives were foreclosed through the action of regulators or the courts or as a result of technological development. In view of this background, it is unlikely that, realistically, any injunction [in essence a code of conduct] could be crafted that would be both sufficiently detailed to ban specific anticompetitive conduct yet sufficiently broad to prevent the various conceivable kinds of anticompetitive conduct that AT&T might employ in the future. United States v. AT&T, 552 F. Supp. 131, 167 (D.D.C. 1982). Thus, the Court preferred the "surer, cleaner remedy of divestiture". Id., 168 fn. 155. AT&T did not have a monopoly on corporate ingenuity. It is only to be expected that incumbent electric utilities, too, will explore every lawful avenue to devise new ways to derive market advantage from vertical integration. There inevitably will be a difference in perspective between utilities and regulators as to what costs are properly chargeable to ratepayers. A recent audit performed for the California Public Utilities Commission Office of Ratepayer Advocates, for example, found that over a two-year period, Pacific Gas & Electric Company ("PG&E"), an incumbent utility with a regulated t&d monopoly, applied $33.7 million of ratepayers' money to subsidize competitive affiliates. In a 1000-page report, the auditors found a catalog of vertical abuses, including overbilling of the regulated monopoly by an affiliate, underbilling by the monopoly to another affiliate, and -15- provision of free services by the monopoly or its affiliates.{14} Like the AT&T court, we have greater confidence in the profit-driven ingenuity of a corporation answerable to its stockholders than we do in the ability of legislators or regulators to bar by regulation every conceivable avenue for the exercise of vertical market power, and then effectively police the boundaries thus established. For this reason, our tendency will be to review the efficiency of the proposed regulatory solution with a skeptical eye. D. The Market Share Limitation Turning to the second question, it is clear that the statutory provision limiting CMP and BHE to a one-third market share in their service territories is a radical measure which to some extent will mitigate the exercise of vertical market power.{15} Potential entrants which are skeptical (as we are) concerning the efficiency of codes of conduct can therefore derive some amount of reassurance from the market share limitation. On the other hand, the concession of a third of the market as fair game for the incumbent utility may still dampen the enthusiasm with which potential and actual entrants regard Maine. In sum, the market share provision limits the potential deterrent to competition of allowing affiliate marketing -- but that may not be enough. 14. San Jose Mercury News, Dec. 4, 1997. 15. The market share limitation does not apply to MPS. Whether it should so apply is a question we defer to the final report. -16- We question whether Maine, a small, largely rural state, can afford to dampen the enthusiasm of potential entrants to any degree. It is not clear to us that the regulatory solution adopted by the Legislature holds any benefit for ratepayers, or for the Maine economy as a whole, which would justify preferring it over the "surer, cleaner remedy" of a ban on affiliate marketing. We will continue to study this issue and will offer recommendations in our final report. E. The Cost of Regulation It appears, indeed, that under the present legislative scheme, the costs of the regulatory effort required to police the vertical boundary will add to the burden borne by ratepayers. It is unclear how important these costs are likely to be. Again, however, the justification for imposing any such costs on Maine's ratepayers is far from self-evident. It is the affiliate marketer and its stockholders which stand to gain from its participation in retail marketing, not ratepayers. Our tendency, therefore, is to inquire why these costs should not be borne by marketing affiliates and their stockholders, rather than by ratepayers, from the outset. F. Recommendation No legislative correction or addition is recommended at this time. However, further analysis will focus on questions regarding (a) the efficacy of codes of conduct; (b) the impact of the market share limitation; and (c) the importance of the regulatory costs which will be incurred in policing the vertical boundary under the restructuring statute as written, and how such costs should be defrayed. In particular, we plan to conduct a thorough survey of the approaches adopted by other states in -17- addressing these problems; and to canvas legal and academic literature more comprehensively than has been possible to date. We also plan to solicit and take account of the views of stakeholders concerning these matters. On the basis of such further analysis, we expect to offer a recommendation in our final report as to whether the Legislature should reconsider the regulatory approach to vertical market power reflected in the statute. IV. HORIZONTAL MARKET POWER: WHOLESALE ENERGY We have defined horizontal market power as the ability of a single dominant firm or group of dominant firms to profit by deviating upward from competitive, marginal cost pricing. The larger a single firm's market share, and the fewer the number of firms competing in the market, the greater will be the ability of the dominant single firm or group to exercise market power. Accordingly, the extent to which a market is subject to horizontal market power can be gauged in terms of the market shares of individual firms, or in terms of overall market concentration. The first step in assessing levels of market concentration is to define the wholesale electric market in terms of products and geography. A. Market Definition For purposes of the evaluation of horizontal market power offered here, the most important relevant product markets are wholesale energy, including -18- renewables (the focus of this section) and renewables separately (to which we turn in the following section).{16} Defining relevant geographic markets is more problematic. In the electric power industry, the perimeter of the geographic market depends upon the extent to which transmission ties permit imports into a region, or to which transmission constraints or bottlenecks limit sales of power within a region. There appears to be general agreement that the wholesale generation market of which southern and central Maine forms a part is, broadly speaking, defined by the New England Power Pool ("NEPOOL") grid, which covers most of the six-state region (with the sole exception of Maine's Aroostook County).{17} However, rather than simply accepting this hypothesis as fact, we are examining the contrary possibility that southern and central Maine may be geographically isolated as a result of constraints which limit imports of power into the State from southern New England and from New Brunswick. If Maine's peak load exceeds the transmission capacity of ties to out-of-state generation sources, the result will be that some in-state generation facilities would be required to run in 16. In fact, there are numerous relevant product markets. In addition to energy, installed capability, Ten Minute Spinning Reserve, Ten Minute Nonspinning Reserve, 30-minute Operating Reserve, Automatic Generation Control and Operable Capability will all be the subject of transactions on the New England power exchange. While energy is clearly the most important of these for purposes of this analysis, we will assess whether there may be market power problems peculiar to any other electric power product market in the final report. 17. See generally New England Power Pool, Market Power Study, FERC Docket Nos. OA-237-000 and ER 97-1079-000, Prepared Direct Testimony of William H. Hieronymus, e.g. at 19; New England Power Co., FERC Docket Nos. ER-98-6-000 and EC-98-1-000, Market Power Analysis: Affidavit and Workpapers of Dr. Joe D. Pace, e.g. at paragraph 34. We do not necessarily agree that the relevant geographic market is as broad as NEPOOL for all purposes. -19- some hours in order to meet demand. The owners of such "must-run" facilities within the State might then possess horizontal market power in peak hours when their facilities were the only source of energy available. In this scenario, southern and central Maine would become a "load pocket", and would constitute the relevant geographic market in which to assess market power in affected hours.{18} There is no question that Aroostook County, isolated from the NEPOOL grid, represents a geographic market separate and apart from southern and central Maine, and from New England.{19} While power emanating from southern Maine and other New England states can reach Aroostook County by using the MEPCO transmission line running through New Brunswick, firm energy transactions over this line are not possible due to minimum tie flow requirements from New Brunswick to New England. Accordingly, New England power generators cannot be treated as a source of supply for Aroostook County. In the sections below, therefore, we examine concentration in the New England market, and available remedies, before returning to address the possibility that market power may also require remediation in the context of a southern and central 18. Similarly, there may be other load pockets, affecting varying numbers of hours, elsewhere in New England. For example, Boston appears to be a load pocket. 19. To the extent it is definable solely in terms of the flow of electricity, the geographic market of which Aroostook County forms a part should be viewed as including New Brunswick, Nova Scotia and perhaps other sections of eastern Canada as well. However, Canadian utilities are not subject to the restructuring initiatives undertaken by FERC or this State. Accordingly, Aroostook County (at least initially) will be the only section of this eastern Canadian grid which is open to wholesale and retail competition. For this reason, it seems appropriate to analyse Aroostook County as a separate geographic market. -20- Maine load pocket. Finally, we assess concentration in the Aroostook County market, and remedial options there. B. Herfindahl-Hirschman Index Federal and state antitrust agencies (including the Department) employ the Herfindahl-Hirschman Index (HHI) to measure market concentration.{20} The HHI is arrived at by squaring the market shares of all the competitors in a given market. This simple mathematical device expresses the insight that market power increases exponentially in proportion to market share. Federal antitrust guidelines used by the Department in merger enforcement indicate that a market with an HHI of 1000 or less should be viewed as unconcentrated (and therefore likely to function competitively).{21} A market with an HHI between 1000 and 1800 is described as moderately concentrated; while any HHI over 1800 is termed highly concentrated.{22} A market in the highly concentrated category is subject to a high degree of market power. D. Concentration in the New England Market Even if a south-central Maine load pocket exists in some small number of hours, New England remains, for most purposes, the relevant geographic market in which to assess horizontal market power in the wholesale generation market. Here again, 20. Horizontal Merger Guidelines, 57 Fed. Reg. 41552 (1992). 21. For example, ten firms with market shares of 10% each would yield an HHI of 1000 (10 squared x 10). 22. For example, a market comprising five firms with market shares of 20% each would yield an HHI of 2000 (20 squared x 5). -21- there is no significant disagreement that the market is highly concentrated, with an HHI in the 1800- 2000 range.{23} A rough approximation of an HHI calculation for the New England generation market follows (using installed generation capacity): Market share HHI Northeast Utilities ("NU") -- 35% 1225 USGen New England ("USGen") -- 20% 400 Sithe Energies, Inc. ("Sithe") -- 13% 169 CMP{24} -- 7% 49 United Illuminating -- 5% 25 Others {25} -- 20% 32 100% 1900 23. In the context of its application to FERC for authorization to charge market-based rates, NEPOOL presented a market power analysis conducted by Dr. William Hieronymus which shows that, when it is assumed that market participants have no load responsibilities, HHIs for relevant products range from approximately 1700 to approximately 2000. When it is assumed that market participants have load responsibilities under a state regulatory regime, the HHI results are significantly lower. New England Power Pool Market Power Study, FERC Docket Nos. OA97-237-000 & ER97-1079-000, Feb. 28, 1997, Prepared Direct Testimony of William H. Hieronymus, see e.g. Exhibits WHH-12 - WHH-13. Similar results were obtained in the market power analysis conducted by Dr. Joe Pace on behalf of USGen for purposes of that company's separate application to FERC for market-based rate authority. New England Power Company, FERC Docket Nos. EC98- 1-000 & ER98-6-000, 2 Affidavit of Dr. Joe D. Pace, Attachment 2. While some incumbent utilities with elevated market shares, such as NU, continue to have load responsibilities which may mitigate market power to some extent in the short term, our task in this report is to assess the structural readiness of electric power markets for competition across the board. Accordingly, the short-term mitigating effect of load responsibilities is discounted. 24. The percentage shown reflects CMP's market share prior to its proposed asset sale. 25. The remaining 20% is split between numerous market participants. There is some disagreement as to the level of importance which should be accorded to imports from New York and New Brunswick. -22- These figures suggest that the New England market will be subject to some significant degree of market power, and that the primary repositories of that market power will be two southern New England utilities, namely, NU and USGen.{26} However, the calculation of an HHI is the starting-point, rather than the conclusion of the analysis. Under federal merger guidelines, antitrust enforcement agencies look beyond HHI numbers to consider a number of other factors in assessing the impact of a proposed merger or acquisition. Primary among these other factors is ease of entry. The holders of market power in a concentrated market will find themselves unable to wield that power to raise price above competitive levels if new entry into the market is relatively easy. However, federal guidelines consider entry sufficiently easy to constrain the exercise of market power only if entry could be accomplished within two years. In spite of changes in available technology, we doubt that entry into the New England wholesale generation market can be effected on a two-year schedule.{27} This suggests 26. USGen is a subsidiary of PG&E. 27. See Wisconsin Electric Power Company, 79 FERC paragraph 61158 at 61695-61696 (recorded in merger case established that need for lengthy regulatory approvals and length of time between planning and completion of new generation would prevent new entrants from mitigating acquirer's market power in timely fashion; noting "significant barriers to timely market entry"); Electric Power Research Institute, Technical Assessment Guide Vol. 1: Electricity Supply - 1993 (Revision 7), June 1993, Exhibit 23 (preconstruction, license and design time for new generation is two years; construction time is a further two years). -23- that the market power of NU and USGen may not be adequately constrained by the prospect of new entry, at least in the short-term.{28} E. Modelling the New England Market In addition to applying a standard merger analysis, we rely for purposes of this interim report on the only simulation modelling of the New England market of which we are aware. The model to which we refer was developed by Synapse Energy Economics, Inc.{29} Using detailed data input regarding hourly customer loads, capacity and operating costs for generating units and transmission tie capacity into New England, the Synapse model simulates "strategic behavior" by market participants. Specifically, the model tests the theory that players with significant market share will be in a position to "game" the New England spot market by withholding capacity, thereby increasing the market-clearing price received by all participants. The New England spot market, to be operated by an "independent system operator" ("ISO") recently established by the Federal Energy Regulatory Commission ("FERC"), will function as the principal price-setting mechanism for energy in New England. Participants will bid power into the spot market 24 hours in advance, with 28. We are aware that a significant level of merchant plant development activity has been announced in New England. Also noteworthy, however, is the fact that a significant share of this new development is being undertaken by USGen. See e.g. New England Power Company, FERC Docket Nos. EC98-1-000 & ER98- 6-000, 1 Affidavit of Dr. Joe D. Pace, paragraphs 23, 28, 30; 4 Pace Affid. 209- 210, 214, 218-219. New capacity which is disproportionately in the hands of market leaders could serve to exacerbate market power problems. 29. Bruce Biewald of Synapse has been retained by the Department and the Commission as their consultant for purposes of this study. -24- a separate bid for each generation facility for each hour. The market will clear each hour at the price bid for the last generation facility required to meet demand in that hour. In peak hours, and indeed in a significant portion of nonpeak hours as well, market participants with multiple facilities will have the ability to drive up the market-clearing price by bidding so high on a particular facility as to effectively withhold that facility's capacity from the market. The results obtained by Synapse show that in fact, NU and USGen could both profit handsomely from such strategic behavior at the expense of New England consumers. Specifically, Synapse concludes that through economic withholding of capacity, NU could increase prices to New England consumers by $823 million, or approximately 30% over a one-year period; while USGen could similarly raise prices by $77 million or 6.4%. If all four leading participants in the market engaged in such behavior, the additional cost to consumers would be $891 million, representing an increase of 32.1%.{30} These results demonstrate that horizontal market power poses a serious threat to competition in the wholesale New England electric power market. However, the ability of the Maine Legislature to take remedial action to protect competition in this sphere is limited to the margin. This is because wholesale 30. B. Biewald, D. White & W. Steinhurst, Horizontal Market Power in New England Electricity Markets: Simulation Results and a Review of NEPOOL's Analysis. While these results have been criticized in the context of the pending NEPOOL market-based rate application at FERC, Mr. Biewald stands by them in a recent affidavit, adding some new modelling runs which underscore the fact that the New England wholesale market is susceptible to market power abuses in a high percentage of nonpeak, as well as peak hours. New England Power Pool, FERC Docket Nos. OA-97-237-000 and ER-97-1079-000, Testimony of Bruce Edward Biewald on behalf of the Maine Attorney General, Jan. 23, 1998. -25- electric power rates, and the operation of wholesale electric power markets, are squarely within the exclusive jurisdiction of federal authorities, viz., FERC.{31} With this in mind, we review available remedial options below. F. Remedies: Divestiture The most obvious solution to the problem of market power in New England would be to require divestiture of some substantial portion of the generation facilities held by market leaders NU and USGen.{32} Maine's ability to achieve this outcome, however, is limited. Maine cannot require divestiture of NU generation facilities by state legislation. Indeed, absent new federal legislation, even FERC lacks authority to order divestiture directly.{33} However, it is possible that at some future time, perhaps as part of restructuring undertaken by Connecticut authorities, NU will voluntarily divest generation facilities. FERC will have approval authority over proposed transactions (and related market-based rate applications) in this regard. The Department and other state Attorneys General and Public Advocates will have 31. See e.g. Maine Yankee Atomic Power Company v. Public Utilities Commission, 581 A. 2d 799, 804 (Me. 1990) (Commission had no authority to require reduction in generator's wholesale rate, set exclusively by FERC; attempt to do so was preempted). 32. Requiring the fracturing of Sithe and CMP market shares might also be beneficial, but would be less important in proportion to their smaller market shares, unless these entities possess market power within a load pocket in a significant number of hours. 33. FERC does, however, possess the ability to require divestiture as a condition of a grant of market-based rate authority, as we discuss below. -26- the ability to intervene before FERC to advocate that NU's block of generation facilities be divested piecemeal, rather than in a unitary sale to a single buyer. In addition, the Department could, in an appropriate case, file litigation under federal merger law to impose divestiture conditions on any proposed transaction. Such litigation would be more likely to succeed, however, if the proposed acquirer had a preacquisition presence in the New England market. Consequently, if NU were to sell to a single out-of-market acquiring party, an antitrust merger enforcement action would be less likely to prevail. In the case of USGen and Sithe, a different situation obtains. USGen recently acquired most of its New England generation facilities from the New England Electric System ("NEES"); Sithe has announced its intention to acquire most of the generation capacity of Boston Edison Company. Both companies are currently seeking approval of these acquisitions in pending proceedings at FERC. The Department has intervened in the pending USGen FERC proceeding, and is considering intervention in the Sithe proceeding. In addition, the Department is currently evaluating enforcement options under federal merger law. G. Remedies: Mitigation and Market-Based Rates As we have indicated, divestiture is clearly the most effective remedy to horizontal market power in the New England market, to the extent divestiture can be brought to bear. However, there is another remedy which is available and is being pursued. -27- In the context of federal restructuring of wholesale electric power markets, FERC possesses authority to grant or deny market participants' applications to charge market-based (as opposed to regulated, cost-based) rates. In order to obtain such authorization, market participants must show that they do not possess market power in the relevant market, or that market power has been mitigated.{34} NEPOOL, of which NU, USGen, Sithe and CMP are all members, has applied to FERC for market-based rate authority. The application is currently pending. The Department is an intervenor in this proceeding; an umbrella organization of which the Commission is a member, the New England Conference of Public Utilities Commissions ("NECPUC") has also intervened.{35} NEPOOL, having initially argued that none of its participants possessed market power except to a limited extent in transmission-constrained conditions, has now proposed a comprehensive market power mitigation plan supposedly designed to remedy precisely the type of strategic behavior modelled by Synapse. The NEPOOL mitigation plan, if approved by FERC, would empower the ISO to respond to economic withholding tactics by various means, including imposition of default pricing or limitations on a participant's bid flexibility. While the Commission, as a member of NECPUC, has indicated conditional approval of NEPOOL's mitigation plan, the Department takes the position that the plan is inadequate. In a recent filing, the Department contends that adequate mitigation must include a 34. See e.g., New York State Gas & Electric Corporation, 78 FERC paragraph 61309 at 62326 (1997). 35. Maine's Office of the Public Advocate is also an intervenor in this docket. -28- structural remedy, namely, appropriate divestitures by NU, USGen and perhaps Sithe as well, as a condition of full market-based rate authority.{36} H. Remedies: The Load Pocket Issue Our analysis of the possibility that southern and central Maine may constitute a "load pocket" is not yet complete. The information gathered to date is insufficient to eliminate the possibility that the aggregate capacity of transmission ties linking Maine to southern New England and New Brunswick may be marginally insufficient to meet Maine's peak load power needs in a relatively small number of peak hours. At this juncture, therefore, we cannot exclude the possibility that Maine may be a "load pocket" in these peak hours. We plan to continue gathering information on this question. If there is a Maine load pocket, southern and central Maine would become a relevant market in which to assess market power during affected hours. Currently, a very high proportion of the generating assets in this area are owned by CMP, making this a very highly concentrated market, subject to a high degree of market power. However, the Legislature has already required that CMP divest virtually all its generation assets, and CMP has recently announced a sale of the bulk of those assets to FPL Group ("FPL"). Under the restructuring statute, CMP must seek Commission approval of the sale. Ultimately, we believe that the Commission possesses authority 36. New England Power Pool, Docket Nos. OA-97-237-000 and ER-97-1079-000, Comments of the Maine Attorney General on the NEPOOL Market Monitoring, Reporting and Market Power Mitigation Proposal Dated December 19, 1997, filed January 23, 1998. -29- to disapprove, or place conditions upon the proposed transaction on market power grounds. In addition, the mitigation plan proposed by NEPOOL, to be administered by the ISO, to some extent may address market power in the load pocket context. Specifically, the mechanisms used to address an episode of economic withholding in a load pocket result in "nonlocational" or "socialised" mitigation pricing. This means, in essence, that the price increase caused by an exercise of market power which might otherwise have resulted only within the load pocket (in this instance Maine) would be averaged out and absorbed across the entire New England region. These mechanisms thus provide a partial cushion against the impact which an exercise of market power might otherwise have on consumers within the Maine load pocket.{37} However, NEPOOL's nonlocational pricing scheme is controversial, and may not remain in place for very long. Moreover, there are another scenarios which we have not yet fully analysed: the possibility that the purported Maine load pocket could become more significant (encompassing more hours) over time, or that other, more localised load pockets could develop. In our final report, we will consider whether, in order to provide to the extent possible for these eventualities, limited legislative adjustments might be appropriate. In particular, we plan to analyse the advisability of adjustments relating to demand side management, and transmission 37. At the same time, nonlocational pricing means that Maine consumers pay a share of price increases which flow from load pockets elsewhere in the region, e.g. Boston. Even if Maine is a load pocket, therefore, locational pricing is probably, on balance, in the interest of Maine consumers. -30- enhancements. In addition, we will consider whether any amendment to laws governing profiteering and unfair trade practices may be in order.{38} I. Concentration in the Aroostook County Market Approximately half of the generating capacity which is locally available to serve Aroostook County load is currently owned by or contracted to Maine Public Service Company ("MPS"). The balance is divided between two wood-fired generators, currently owned by CMP and Alternative Energy, Inc. ("AEI").{39} The restructuring statute requires both MPS and CMP to divest generation assets; again, the required asset sales are subject to Commission approval. It is noteworthy that MPS is not required to divest its Tinker Generating Station and associated assets located across the international frontier in Aroostook Junction, New Brunswick.{40} These hydroelectric facilities comprise more than half of MPS' generating assets. Although not required to divest the Tinker assets, MPS has included them as part of its auction package. The sale of the Tinker assets is subject to Commission approval under 35-A M.R.S.A. section 3508. In addition to local generating capacity, Canadian power will be available to serve Aroostook County load. Indeed, under normal circumstances, the 38. See 5 M.R.S.A. section 207; 10 M.R.S.A. section 1105. 39. Locally available generating capacity includes MPS' hydro (primarily Tinker Station), 35.8 MW; MPS' operable diesel capacity, 12.2 MW; Wheelabrator Sherman wood cogeneration (contracted to MPS), 18.1 MW; and the FPL and AEI wood-fired generators, 32 and 37 MW respectively. 40. The statute does, however, require MPS to divest its rights to the Tinker capacity and energy. 35-A M.R.S.A. section 3204 (1) & (4). -31- capacity of transmission ties to New Brunswick would permit the entire Aroostook County load to be served from Canada. It would appear that there are three potential sources of Canadian power to compete with local generators: New Brunswick Power ("NBPC"), Hydro Quebec ("HQ") and Nova Scotia Power ("NSP").{41} However, in order to obtain access to the small Aroostook County market, HQ and NSP must wheel their power across the service territory of NBPC. For this privilege, they must pay a significant wheeling fee to NBPC. NBPC apparently possesses the unilateral ability to increase the wheeling fee.{42} Accordingly, NBPC can determine the price at which not only its own power, but also that emanating from HQ and NSP, is available to consumers in Aroostook County. NBPC may also have the ability to prevent HQ and NSP power from reaching the Aroostook County market at all.{43} In these circumstances, HQ and NSP cannot be viewed as effective competitors in their own right. Following the MPS and CMP divestiture auctions which are currently in progress, therefore, it appears that the competing suppliers of wholesale power to Aroostook County will be few: NBPC and two or three acquiring parties. If 41. HQ holds an existing contract to supply MPS, and is active as a marketer in the United States generally; NSP, on the other hand, hitherto has shown little interest in selling power outside its own system. 42. NBPC house counsel indicates that wheeling fees are the subject of an informational filing with New Brunswick authorities, but do not require their approval; and that there is no Canadian federal approval process. 43. An outright denial of wheeling services might be subject to challenge on a monopolization theory. -32- it comprises only three or four competitors, such a market would fall into the highly concentrated category under federal guidelines, and would be subject to a high degree of market power. The Legislature has provided a corrective mechanism: as noted above, the proposed MPS asset sale is subject to Commission approval. By imposing conditions designed to alleviate market concentration, the Commission can positively influence (albeit to a limited extent){44} the level of competition in the Aroostook County market. The availability of other remedies bears further analysis. For example, in the event of a proposal by an in-market acquirer to purchase any part of the MPS assets, the Department would subject the transaction to a careful review for compliance with federal and state merger law. In addition, for purposes of the final report, we plan to evaluate several possible legislative adjustments. Again, these would include demand side management and transmission enhancements.{45} We also plan to consider all aspects of the question how best to prepare Aroostook County for retail choice. Our current assessment is that retail choice could subject Aroostook County consumers to a high degree of market power dominance by NBPC. 44. Our analysis suggests that by imposing appropriate conditions, the Commission may have the ability to reduce an extremely concentrated market, in the range of a 3400 HHI, by approximately 300 points. Thus, even with such conditions, the market would remain extremely concentrated. 45. The Commission is conducting a separate study of the feasibility of connecting Aroostook County to the New England grid. 35-A M.R.S.A. section 3206(3). -33- J. Recommendations No legislative correction or addition is recommended at this time. The Department will pursue various regulatory enforcement options, as described above, including interventions at FERC and in other regulatory forums. The Department will also continue to offer advice to the Commission on market power matters, in the context of pending divestiture proceedings and in upcoming rulemakings. The Commission is in any event cognizant of its responsibility under the restructuring statute to employ its approval power over divestiture proposals to ensure a reasonably competitive market structure. In addition, the Department will continue to evaluate proposed acquisitions and mergers in the New England region for antitrust compliance. Finally, the Department and the Commission will continue to study the limited further remedial options which may be legislatively available to protect or enhance competition. Such options could include, for example, initiatives in the area of demand side management and transmission enhancement, or adjustments to the law governing unfair trade practices and profiteering. Special circumstances in Aroostook County indicate that it may be subject to a high degree of market power. Accordingly, the question how best to prepare this market for retail choice merits further consideration in the final report in light of intervening developments. -34- V. HORIZONTAL MARKET POWER: RENEWABLES Maine's restructuring statute requires that, as a condition of licensing, competitive electricity providers demonstrate that no less than 30% of their portfolio of supply sources for retail electricity sales in the State are accounted for by renewable resources as defined in the statute.{46} This requirement results in the statutory creation of a separate product market which, in its turn, must be analysed separately for the presence of market power. A. Market Definition In addition to addressing allowable fuel or energy types used to produce renewable power, the statutory definition specifies that in order to qualify, the power produced must be capable of physical delivery "to the control region in which [NEPOOL], or its successor as approved by the [FERC] has authority over transmission". Accordingly, with respect to southern and central Maine, the relevant geographic market in which to analyse market power in renewables is the NEPOOL grid, i.e., New England exclusive of Aroostook County.{47} 46. The statute defines renewable resource as "a source of electrical generation that generates power that can physically be delivered to the control region in which [NEPOOL], or its successor as approved by [FERC] has authority and that .. [q]ualifies as a small power production facility under [FERC] rules ... whose total power production capacity does not exceed 100 megawatts and that relies on one or more of the following: ... [f]uel cells; ... [t]idal power; ... [s]olar arrays and installation; ... [w]ind power installations; ... [g]eothermal installations; ... [h]ydroelectric generators; ... [b]iomass generators; ...[g]enerators fueled by municipal solid waste in conjunction with recycling." 35-A M.R.S.A. section 3210. 47. Because the statutory definition makes clear that renewable electrons need only be delivered to the NEPOOL grid in order to qualify, and need not be physically deliverable to Maine, it is irrelevant whether or not there is a load pocket, for purposes of this portion of the analysis. In any event, as we note above, it appears that if a load pocket exists in southern and central Maine at all, it does so only in a relatively few hours. -35- The configuration of transmission ties, all other things being equal, makes Aroostook County a separate market for renewables, as for energy.{48} In the sections following, we evaluate levels of concentration in both the New England and Aroostook County renewables markets, before turning to a consideration of remedial options. B. Concentration in New England and Aroostook Renewables Markets Our preliminary analysis indicates that the New England market for renewables as defined in the statute is in the upper range of moderate concentration. In the wake of CMP's proposed divestiture, four participants hold approximately 75% of renewable capacity, resulting in an HHI in the area of 1750. Mkt share HHI HQ -- 28% 784 NU -- 24% 576 CMP -- 9% 81 USGen -- 13% 169 FPL -- 10% 100 Others -- 16% 45 100% 1756 In the Aroostook County market, qualifying renewable capacity is currently divided, in large part, among only four competitors, HQ, MPS, FPL and AEI, resulting in a highly concentrated market. These figures are symptomatic of a relatively high degree of market power. In the renewables market, the need for remedial action is greater, however, than these market share numbers might 48. As we note below, however, if, as expected, the Commission acts by rule to create a market in tradeable renewable credits, Aroostook County effectively becomes a part of the New England geographic market. -36- otherwise suggest. This is because compliance with the portfolio requirement is a prerequisite to entry into the Maine retail market for electrical power generally. In short, players with high renewables market shares may have the ability to deny their marketing competitors entry into the Maine retail market simply by refusing to make sufficient renewable power available at wholesale. Such exclusionary tactics could dramatically decrease competition for energy sales to Maine consumers, driving prices up. Of course, it can be argued that until a portfolio requirement is adopted regionwide, relatively low demand for renewable energy as such may reduce the ability of any player to capitalize on market power in this product market. However, it appears likely that variants of Maine's portfolio requirement will be adopted by other New England states in due course.{49} Moreover, it seems certain that numerous market participants will seek to attract retail customer interest in green power across the region. Demand for renewable power could therefore increase sharply, regardless of portfolio requirements.{50} 49. Massachusetts has recently enacted a renewables standard which defines "renewable" somewhat differently, and is designed to promote the development of new sources of renewable power by requiring that retail sellers increase their sales from new renewable sources each year by set percentages (from half to one percent per year). 50. At the same time, the level of concentration shown in the table above does not reflect that fact that the shares of at least two players, CMP and NU, will diminish as their contracts with nonutility generators expire over the next several years. The extent of the mitigating effect of this factor remains to be analysed. -37- C. Remedial Options The most obvious solution to the problem of market power in the renewables market, as elsewhere, is divestiture. Again, however, Maine cannot legislatively require divestiture of renewable generation sources by either NU or USGen. On the other hand, the restructuring statute does require divestiture by CMP and MPS. CMP will be presenting its proposed sale to FPL to the Commission for approval in the near future; an MPS auction is currently under way. As we have noted above, the Commission clearly has the power, under the statute, to refuse to approve, or place conditions upon a proposed acquisition on market power grounds.{51} There is a further remedial option available to the Commission under the statute as written which would serve to reduce concentration in both geographic markets, and especially in Aroostook County, by effectively joining them together. The Commission could act by rule to create a market in "tradeable credits."{52} Generators with facilities which met the statutory definition could apply to the Commission for credits (e.g. one credit per renewable kilowatt hour generated annually). At year-end, retailers would be required to turn over to the Commission credits totalling 30% of their sales. The rule would explicitly envisage the development of a market for the renewable credits along the same lines as markets for sulphur dioxide emission 51. However, in view of the fact that CMP's proposed sale effectively splits its renewable capacity in two, reducing the HHI for this market below the 1800-mark, it is not clear that the imposition of additional conditions on this transaction could achieve any significant further reduction in concentration. 52. The Commission has expressed its interest in this remedial option as a matter of record. -38- credits under Title IV of the federal Clean Air Act amendments. The market in tradeable renewable credits could function as an adjunct to energy markets, without regard to the geographic separation of Aroostook County from the New England energy markets. Other, more general remedial options are also available, and merit consideration in the context of the final report. Specifically, it may be advisable, in view of the ability of players with high renewable market shares to exclude competitors from the Maine retail energy market altogether, to provide some sort of legislative "safety valve" designed to prevent an adverse impact on consumers. We have identified two such options. First, provision could be made by rule or statute to the effect that if a prospective entrant to the Maine market could not obtain the required level of renewables for inclusion in its energy mix, it could nevertheless enter on the strength of a promise to make good the renewable "deficit", with "interest", at a later time. This would give the entrant the opportunity to acquire or construct its own renewable energy source. Second, prospective entrants could be given the option, instead of fulfilling the portfolio requirement, of making a contribution to a fund to be used to promote renewables. These two measures could, of course, be adopted in tandem. D. Recommendations No legislative correction or addition is recommended at this time. However, market power considerations should reinforce the Commission's interest in the -39- creation of a market in tradeable renewable credits. The final report will give consideration to amending the restructuring statute to build in a safety valve designed to prevent players with high renewable market shares from excluding competitors from the Maine retail energy market, unless this has already been accomplished by rule. VI. CONCLUSION In this Interim Report, we offer a preliminary assessment of the market power problems which appear likely to affect restructured electric markets in Maine or of which Maine forms a part. We conclude that there is no current need for emergency legislation in this legislative session to address market power issues. However, we plan to carefully review legislative options, and to offer specific legislative recommendations in the final report, due December 1, 1998. Under the restructuring statute, Maine's retail electric markets will be vulnerable, to some degree, to vertical market power arising from the ability of t&d companies to participate in the retail market through affiliated power marketers. In the final report, we plan to reassess the efficacy of the regulatory restrictions imposed by the restructuring statute as a solution to the problem of vertical market power, and to offer a recommendation as to whether the Legislature should reconsider an outright ban on affiliate marketing. The New England and Aroostook County wholesale electric markets are highly concentrated, and accordingly, subject to horizontal market power to a significant degree. Because wholesale rates are within the exclusive jurisdiction of federal -40- authorities, however, legislative options are limited. The final report will consider the advisability of legislative adjustments to the restructuring statute in the area of demand side management, transmission enhancements, and possible amendments to unfair trade practices or profiteering in necessities laws. In the meantime, the Department will continue to pursue other remedial options, including advocacy before FERC and antitrust merger enforcement. With respect to Aroostook County, or in the event that a load pocket is found to exist in southern and central Maine, the Commission possesses the ability to impose conditions in the context of pending divestiture proceedings to reduce levels of concentration. Finally, the final report will consider whether, in the light of intervening developments, how best to prepare the Aroostook County market for retail choice. The New England wholesale market for renewable energy as defined in the restructuring statute is moderately concentrated. Its Aroostook County counterpart is highly concentrated. There is special reason for concern, here, in that competitors with high market shares may possess the ability to deny others entry to Maine's energy markets generally. Even so, legislation may not be necessary in this area. CMP's proposed sale to FPL (if approved) will have reduced levels of concentration somewhat; the Commission retains the ability to impose conditions on MPS' proposed divestiture, if necessary. More importantly, by acting to create by rule a market in tradeable renewable credits, the Commission can effectively annex Aroostook County to the less concentrated New England market. In addition, the Commission can act by rule to -41- ensure access to Maine energy markets by permitting competitors to run a renewable deficit, or to pay into a fund in lieu of strict compliance with the portfolio requirement. The final report will review the need for legislation in light of intervening developments. -42- Exhibit 99(q) STATE OF MAINE PUBLIC UTILITIES COMMISSION Docket No. 97-727 January 15, 1998 MAINE PUBLIC SERVICE COMPANY ORDER GRANTING Application for Approval of an Electric CERTIFICATE OF Rate Stabilization Agreement with APPROVAL Wheelabrator-Sherman WELCH, Chairman; NUGENT and HUNT, Commissioners _________________________________________________________________ I. SUMMARY In this Order, we issue a certificate of approval for an electric rate stabilization agreement (Agreement) submitted by Maine Public Service Company (MPS). (1) The Agreement restructures an existing power purchase agreement (PPA) between MPS and Wheelabrator-Sherman (W/S) consistent with statutory requirements. II. BACKGROUND On September 19, 1997, MPS filed, pursuant to 35-A M.R.S.A. S. 3156, for approval of an electric rate stabilization agreement that amends its current W/S PPA. Under the existing PPA, MPS must purchase up to 126,582 MWh per year from W/S's 17.6 MW biomass plant in Sherman Station; the W/S plant is a qualifying facility (QF) pursuant to 35-A M.R.S.A. S. 3303. The existing PPA specifies power purchase rates for an initial 15-year term (through the year 2000), and allows either party to extend the PPA for an additional 15 years at negotiated or Commission-set rates. The proposed Agreement includes three elements. First, MPS would pay W/S $8.6 million at closing; this amount would be financed by the Finance Authority of Maine (FAME) pursuant to 10-M.R.S.A. S. 963(7-A). MPS would also pay W/S an additional $2,350 per day (up to a maximum of $105,750) for each day closing is delayed past November 1, 1997. Second, W/S would provide monthly credits to MPS for the remainder of the PPA initial term. These credits total $10 million (nominal) and have a present value of approximately $8 to $9 million. The rates in the initial term of the PPA (1986-2000) do not change. Third, the Agreement would reduce the PPA extension period from 15 to 6 years, increase the purchase obligation in each of the extension 1. Commissioner Hunt voted against this decision. See attached Dissenting Opinion. Order Granting . . . -2- Docket No. 97-727 term years by 10,000 MWh to 136,582 MWh, and establish purchase prices for power beginning at $.0854 per kWh in 2001 and escalating at 2% per year. In addition to its request for approval of the Agreement, MPS filed a motion to modify its current rate plan (2) so that savings in the near term from the Agreement can be used to offset rate increases during the remaining term of the rate plan. Under MPS's current rate plan, savings from any restructuring of the W/S PPA would reduce specified deferrals that would be recovered in rates beginning in 2000. MPS has also filed two other motions, both designed to obtain Commission assurance that all costs of the Agreement will be recovered in rates. During a prehearing conference held on October 10, 1997, the Hearing Examiner granted the petitions to intervene of the Public Advocate and Houlton Water Company. W/S did not petition to intervene, but participated throughout the proceeding by presenting its views of the benefits of the Agreement. The Commission held a hearing on this matter on November 4, 1997. On November 14, 1997, the Commission issued an Order Denying Certificate of Approval, without prejudice, stating that it was unable to find, at that time, that the potential future costs of the Agreement were not likely to be disproportionate to near-term savings. The Commission encouraged MPS to re-file its petition for approval to allow more time to develop an informed judgment as to the long-term economics of the Agreement. (3) MPS filed a letter resubmitting its petition on November 6, 1997. (4) III. POSITIONS REGARDING THE AGREEMENT A. Maine Public Service Company In its initial filing, MPS requests approval of the Agreement as satisfying the requirements of section 3156. MPS states that the Agreement will produce near-term savings that will be reflected in rates and estimates the overall net present value (NPV) savings of the Agreement to be $362,000. This 2. MPS is currently operating under a multi-year rate plan approved by the Commission on November 30, 1995 (Docket No. 95-052). 3. Under section 3156, the Commission must issue or deny a certificate within 60 days of an application. 4. MPS filed this letter in reaction to the Commission deliberations of this matter that occurred on November 4, 1997. Order Granting . . . -3- Docket No. 97-727 estimated overall savings is based on MPS's view of the likely range of outcomes if the renewal term rates were litigated before the Commission. (5) MPS argues that the Agreement provides certain near-term benefits ($10 million reduction in PPA costs over 3 years) and that possible future rate impacts are not likely to be disproportionate; some amount of future uncertainty should be tolerated to obtain near-term savings. MPS notes that W/S has advanced some positions that appear credible and supportable, and that full litigation of the renewal term rates could result in an outcome that would be very expensive relative to the Agreement. Finally, MPS states that the outcome of renewal term rate litigation cannot be conclusively determined and that there are reasonable analyses showing a positive NPV; as such, the Commission should approve the Agreement to obtain the near-term savings and avoid a substantial litigation risk regarding future contract rates. B. Public Advocate The Public Advocate also supports approval of the Agreement, but does so cautiously. The Public Advocate states that the Agreement's savings, if any, cannot be calculated, that the Company's calculation relies on speculation as to the renewal term rates, and that the economics could range from substantial costs to substantial savings. The Public Advocate is concerned that the Agreement could provide near-term benefits at the cost of raising rates after 2000. However, the Public Advocate supports the Agreement because of the significant reduction in risk it represents to MPS and its ratepayers by shortening the exposure to the W/S PPA; even if there are no net savings, there is a large benefit in the PPA terminating as soon as possible. In the Public Advocate's view, because no one can predict the outcome of litigation, the reduction of risk exposure of this magnitude subsumes other costs, benefits and analyses presented by the PPA restructuring proposal. 5. As we discuss below, the economics of the Agreement are extremely sensitive to assumptions of what the renewal term rates would be in the absence of the Agreement. MPS provided its position on the appropriate outcome (as opposed to the likely outcome) of litigation on the renewal term rate; if MPS prevailed in its position, the Agreement would have a NPV cost of approximately $10 million. Order Granting . . . -4- Docket No. 97-727 C. Wheelabrator-Sherman W/S disagrees that the Agreement could result in any substantial losses to ratepayers in comparison to the unamended PPA. On the contrary, W/S argues that the Agreement, based on its view of the proper approach for establishing the renewal term rates, will save ratepayers millions of dollars. For these reasons, W/S urges the Commission to approve the Agreement. IV. DISCUSSION OF AGREEMENT Electric rate stabilization agreements are governed by section 3156. The section allows the Commission to issue a certificate of approval only if it makes five explicit findings. Before discussing the individual required findings, we present our general views regarding of the Agreement and why its approval is in the public interest. In the near-term, the Agreement will undoubtedly provide savings in the range of $3.5 million NPV through 2000. However, the overall economics of the Agreement depend on inherently speculative assumptions of what the renewal term rates would be in the absence of the Agreement. Renewal term rates would be determined based on the following language contained in the existing PPA: the rates shall be based on avoided capacity costs of the same plant on which avoided capacity rates were based at the outset of this contract and on avoided energy costs. The parties agree to negotiate in good faith to set the avoided energy and capacity costs upon which rates shall be based. In the event the Buyer and Seller are unable to agree to the rate, the Buyer and Seller agree to submit the dispute to the Maine Public Utilities Commission. The record contains three conceptual approaches to calculating the renewal term rates that lead to widely divergent results: - Estimates of Seabrook I (6) fixed costs and MPS system energy costs during 2001-2005; - Estimates of Seabrook I fixed and variable costs during 2001-2005; 6. Seabrook I is the plant on which the Commission initially based avoided capacity rates. Order Granting . . . -5- Docket No. 97-727 - Estimates of the market value of Seabrook I during 2001 through 2015. Depending on the approach used, the net present value of the Agreement could range from approximately $35 million in savings if Seabrook fixed costs and system energy are used, to approximately a $21 million NPV cost if market value were to be employed. Estimates using Seabrook fixed and variable costs range from approximately a $10 million cost to a $5 million savings. Assessing the value of the Agreement is further complicated by the non-specific nature of the renewal term language and the purpose for which the provision was initially included in the PPA. The provision was included at the urging of MPS so it would not lose the benefit of what it believed to be relatively low cost Seabrook power in the out-years compared to what it believed to be relatively higher cost alternatives. However, the situation turned out to be the opposite whereby Seabrook power is relatively more costly than currently existing alternatives. These circumstances present the Commission with an extremely difficult task of attempting to project the renewal term rates it would establish if the matter was disputed and brought to it for resolution, as well as considering the outcome of a court challenge. We must consider the analytical task presented by this case in light of the statutory language contained in section 3156. Section 3156 appears to contain a bias in favor of near-term savings even at the expense of some increased level of long-term cost. Under the statute, we must find an agreement "will provide near-term benefits." We must then find that "[p]otential future adverse rate impacts . . . are not likely to be disproportionate to near-term gains." We read this language to mean that, if there are reasonably certain near-term savings, a rate stabilization agreement can be approved even if it results in overall increased costs, as long as those increased costs are not "disproportionate" to the near-term gains. In this case, there are clear near-term benefits. Although there are reasonable scenarios upon which future adverse rate impacts would overwhelm those near-term benefits, there are also plausible (albeit not likely) (7) futures by which a rejection 7. Although W/S argues strenuously that use of Seabrook I fixed costs and system energy was the intent of the renewal term provision, such an approach is a conceptually incorrect method of calculating avoided costs that would result in a windfall to W/S at the expense of MPS ratepayers. Order Granting . . . -6- Docket No. 97-727 of the Agreement would not only result in the loss of the near-term gains, but cause ratepayers substantial adverse rate impacts throughout the next 15 years. Many of the likely scenarios, however, fall within an overall NPV range of approximately a $5 million cost to a $5 million benefit. On balance, we believe it is important to eliminate the risk of a substantial adverse outcome to ratepayers from litigation of the renewal term rates; it is also preferable to risk making a 6-year mistake rather than a 15-year mistake. By approving the Agreement, we ensure the near-term benefits for ratepayers as well as providing certainty that a power contract that has created a severe financial burden on MPS and its ratepayers over many years will conclude in 2006. It is on the basis of these considerations, that we view the Agreement to be in the public interest. We now address specifically the five statutory findings required by section 3156. 1. The Agreement and any assistance in FAME financing will provide near-term benefits to ratepayers that will be reflected in rates. As mentioned above, the Agreement will result in near-term benefits in the range of $3.5 million NPV through 2000. As discussed below, we will modify the terms of MPS's current rate plan to allow a near-term flowthrough of the Agreement's benefits over the remaining years of the plan. Because we will proceed in this matter, the near-term benefits will be reflected in rates. 2. Potential future adverse rate impacts are not likely to be disproportionate to near-term gains. This required finding relates to the overall net benefits or costs that the Agreement is likely to produce over its term. As discussed above, this issue depends on the inherently speculative question of what the renewal term rates would be in the absence of the Agreement. Based on the record in this case, and taking into account the great amount of uncertainty of any long-term analysis of this Agreement, we find that the potential for future adverse rate impacts is not likely to be disproportionate to the near-term gains. Order Granting . . . -7- Docket No. 97-727 3. The Agreement does not have as a necessary or probably consequence the permanent cessation of a QF of more than 50 MW. Because the W/S facility is less than 50 MW, we make this third finding. 4. The Agreement is consistent with the Maine Energy Policy Act. The Maine Energy Policy Act, 35-A M.R.S.A. s. 3191, requires utilities to pursue a least cost energy plan, taking into account many factors including costs, risk and diversity of supply. For many of the reasons discussed above, we find that the Agreement is consistent with section 3191. Although we cannot say with certainty whether the long-term impacts of the Agreement will be positive or negative, the Agreement does reduce near-term costs as well as long-term risks without, as discussed below, adversely effecting the diversity supply. In this way, the Agreement is consistent with sound least cost planning. 5. The Agreement will not adversely impact the availability of a diverse and reliable mix of energy resources and will not significantly reduce the availability of long-term resources to meet electric demand. The approval of the Agreement ensures that the W/S facility will be part of the energy mix until the year 2006. In the absence of the Agreement, it is possible that the facility would cease to operate after 2000 or continue to operate pursuant to the MPS PPA until 2015. It is also be possible that the facility would continue to operate in the competitive generation market after 2006 when the Agreement expires. Even if the plant ceases to operate after 2006, Maine continues to have a relatively diverse energy mix. For these reasons, we find that the Agreement will not have an adverse impact on the diversity and reliability of the energy mix or significantly reduce the available of long-term resources. V. MPS MOTIONS As mentioned above, MPS filed a series of motions, seeking specified Commission findings. The motions are: (1) Motion to Alter or Amend the Commission's November 30, 1995 Order in Docket No. 95-052 (Order that approved MPS's rate plan); (2) Motion to Amend the Commission's February 10, 1984 and June 4, 1984 Orders in Docket Nos. 81-276, 83-264, and 83-303; and (3) Motion for Investigation into Recovery of Stranded Costs created by the Order Granting . . . -8- Docket No. 97-727 Agreement (this third motion seeks to serve the same purpose as the second motion). In the first motion, MPS asks the Commission to modify the provisions of its rate plan to allow the Agreement's near-term savings to offset the increases it would otherwise seek in upcoming annual reviews. Under the terms of MPS's rate plan, any reductions to the cost of the W/S PPA must be used to reduce specified deferrals that would otherwise be included in rates beginning in 2000. MPS states that the requested modification will reduce necessary immediate rate increases and allow for near-term benefits to flow to ratepayers, which is a prerequisite of section 3156. The purpose of the second and third motions is to obtain the Commission determination that the Agreement is consistent with the original orders approving the W/S PPA and to ensure that any stranded costs created by the Agreement (as opposed to the original PPA) will be recovered in rates. During the hearing on this matter, MPS clarified that it would be satisfactory for the Commission to make a general finding that it would modify the rate plan to allow for the near-term flowthrough of benefits during the term of the rate plan, without any specific indication of the manner by which this would be accomplished. MPS also indicated that it would be sufficient for the Commission to interpret the provisions of section 3156 and section 3208 (the stranded cost section of the restructuring legislation) to mean that the Company will recover in rates the Agreement's financing costs and costs of the PPA extension. We find that it is reasonable to amend the MPS rate plan to allow a near-term flowthrough of the benefits of the Agreement during the Company's rate plan. No party has opposed this change in concept and it is certainty consistent with the Legislature's intent that the ratepayers realize the near-term benefits from FAME financed QF contract renegotiations in their rates. The specific timing of the flowthrough of the benefits will be considered as part of MPS's pending rate plan annual review, Docket No. 97-830. We also find that under the provisions of sections 3156 and 3208, MPS should recover from its ratepayers the financing costs and costs of the PPA extension associated with the Agreement. Section 3156 states that the Commission may not disallow or prevent the recovery of electric utility costs, including costs to be paid to the QF, under the terms of a rate stabilization agreement based solely on the execution of the certified agreement. Section 3208 provides that utilities may recover legitimate, verifiable and unmitigatable stranded costs. These provisions evidence a legislative intent that MPS recover the Order Granting . . . -9- Docket No. 97-727 costs associated with the Agreement. These include the costs involved with the $8.6 million payment to W/S and the payments for the extension term power purchases (2001-2006). (8) Accordingly, we O R D E R A certificate of approval for the electric rate stabilization agreement filed by Maine Public Service Company on September 18, 1997, is hereby issued. Dated at Augusta, Maine this 15th day of January, 1998. BY ORDER OF THE COMMISSION ______________________________ Dennis L. Keschl Administrative Director COMMISSIONERS VOTING FOR: Welch Nugent COMMISSIONER VOTING AGAINST: Hunt: See attached Dissenting Opinion 8. Consistent with the treatment of stranded costs, MPS would recover only the cost of the power purchases net of the power's market value. Order Granting . . . -10- Docket No. 97-727 Dissenting Opinion of Commissioner Hunt I would not approve Maine Public Service's proposed amendment to its Purchased Power Agreement with Wheelabrator Sherman. I do not believe the record supports one prong of Section 3156, which requires us to find that the potential for future adverse rate impacts are not likely to be disproportionate to the near-term gains. Staff's analysis suggests that the 1997 amendment could result in a substantial loss to ratepayers in comparison to the unamended PPA over the longer term. Pursuant to that analysis, the Agreement is more likely than not to result in a significant NPV cost in an amount disproportionate to the near term savings. I do not express an opinion about what the conclusion would be if the matter were litigated before the Commission. As the OPA observed, one cannot "calculate with any degree of accuracy how much, if anything, the Company and its ratepayers will save by virtue of this agreement." I believe, however, that the Commission has reasonable and sound options regarding the methods to establishing renewal term rates that would withstand judicial scrutiny and that, if adopted, would result in lower long term costs for MPS ratepayers. I agree with the majority that removing the risks inherent in litigation has some value. However, as the contract provision which governs the renewal term rates provides that a dispute over rates would be submitted to the Commission, and as the renewal provision is vague, a reviewing court would likely give the Commission discretion, provided our decision had record support and was theoretically sound. Over the long term, it is likely that ratepayers may be better positioned if the Commission rejected the Amendment as proposed. Order Granting . . . -11- Docket No. 97-727 NOTICE OF RIGHTS TO REVIEW OR APPEAL 5 M.R.S.A. S. 9061 requires the Public Utilities Commission to give each party to an adjudicatory proceeding written notice of the party's rights to review or appeal of its decision made at the conclusion of the adjudicatory proceeding. The methods of adjudicatory proceedings are as follows: 1. Reconsideration of the Commission's Order may be requested under Section 6(N) of the Commission's Rules of Practice and Procedure (65-407 C.M.R.11) within 20 days of the date of the Order by filing a petition with the Commission stating the grounds upon which consideration is sought. 2. Appeal of a final decision of the Commission may be taken to the Law Court by filing, within 30 days of the date of the Order, a Notice of Appeal with the Administrative Director of the Commission, pursuant to 35-A M.R.S.A. S. 1320 (1)-(4) and the Maine Rules of Civil Procedure, Rule 73 et seq. 3. Additional court review of constitutional issues or issues involving the justness or reasonableness of rates may be had by the filing of an appeal with the Law Court, pursuant to 35-A M.R.S.A. S. 1320 (5). Note: The attachment of this Notice to a document does not indicate the Commission's view that the particular document may be subject to review or appeal. Similarly, the failure of the Commission to attach a copy of this Notice to a document does not indicate the Commission's view that the document is not subject to review or appeal. [ARTICLE] UT [MULTIPLIER] 1,000 [PERIOD-TYPE] 12-MOS [FISCAL-YEAR-END] DEC-31-1997 [PERIOD-END] DEC-31-1997 [BOOK-VALUE] PER-BOOK [TOTAL-NET-UTILITY-PLANT] 49865 [OTHER-PROPERTY-AND-INVEST] 4129 [TOTAL-CURRENT-ASSETS] 15526 [TOTAL-DEFERRED-CHARGES] 94032 [OTHER-ASSETS] 0 [TOTAL-ASSETS] 163552 [COMMON] 7357 [CAPITAL-SURPLUS-PAID-IN] 38 [RETAINED-EARNINGS] 26903 [TOTAL-COMMON-STOCKHOLDERS-EQ] 34298 [PREFERRED-MANDATORY] 0 [PREFERRED] 0 [LONG-TERM-DEBT-NET] 35650 [SHORT-TERM-NOTES] 7200 [LONG-TERM-NOTES-PAYABLE] 0 [COMMERCIAL-PAPER-OBLIGATIONS] 0 [LONG-TERM-DEBT-CURRENT-PORT] 4155 [PREFERRED-STOCK-CURRENT] 0 [CAPITAL-LEASE-OBLIGATIONS] 0 [LEASES-CURRENT] 0 [OTHER-ITEMS-CAPITAL-AND-LIAB] 82249 [TOT-CAPITALIZATION-AND-LIAB] 163552 [GROSS-OPERATING-REVENUE] 55072 [INCOME-TAX-EXPENSE] (975) [OTHER-OPERATING-EXPENSES] 55136 [TOTAL-OPERATING-EXPENSES] 54161 [OPERATING-INCOME-LOSS] 911 [OTHER-INCOME-NET] 495 [INCOME-BEFORE-INTEREST-EXPEN] 1406 [TOTAL-INTEREST-EXPENSE] 3583 [NET-INCOME] (2177) [PREFERRED-STOCK-DIVIDENDS] 0 [EARNINGS-AVAILABLE-FOR-COMM] (2177) [COMMON-STOCK-DIVIDENDS] 1617 [TOTAL-INTEREST-ON-BONDS] 3092 [CASH-FLOW-OPERATIONS] (1719) [EPS-PRIMARY] (1.346) (1.346)
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