-----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, GkPrEabdShhu3uZNbbHpmtQai9yuJ7gC+UpLCJUFjFCowsnR3A3MmtF19wMQHZvr 1IARz9soJrRUkfk0hfMI7Q== 0000061611-97-000011.txt : 19970320 0000061611-97-000011.hdr.sgml : 19970320 ACCESSION NUMBER: 0000061611-97-000011 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 1 CONFORMED PERIOD OF REPORT: 19961231 FILED AS OF DATE: 19970319 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: 1934 Act SEC FILE NUMBER: 001-03429 FILM NUMBER: 97559137 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, 1996. 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. [X] Aggregate market value of the voting stock held by non-affiliates at March 19, 1997: $23,450,125 The number of shares outstanding of each of the issuer's classes of common stock as of March 19, 1997. Common Stock, $7.00 par value - 1,617,250 shares DOCUMENTS INCORPORATED BY REFERENCE 1. The Company's 1996 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, 1996, which is the end of the fiscal year covered by this report, is incorporated by reference into Part III. (Page 1 of 45 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 1996, sales to the Company amounted to 137,615 MWH out of the 163,043 MWH generated for sale at Tinker. The Company and the Subsidiary's net energy production, including generated and purchased power, required to serve all customers, was 800,775 MWH for the twelve months ended December 31, 1996. The following table sets forth the sources from which the Company and the Subsidiary obtained their power requirements in 1996. 1996 Megawatt-hours Generated Sources of Power or Purchased Net Generation: Hydro 168,993 Steam 10,201 Diesel (674) Total 178,520 Purchases: Nuclear Generated 249,083 Fossil Fuel Generated 243,720 Biomass Generated 128,711 Total 621,514 Inadvertent Received 741 Total System 800,775 -2- PART I Form 10-K Item 1. Business - Continued As of June 4, 1984, the Company entered into a Power Purchase Agreement with Sherman Power Company, which assigned its interest in the Agreement to Wheelabrator-Sherman Energy Company, formerly Signal- Sherman Energy Company, (a cogenerator), for approximately 18 MW of capacity which began July, 1986. The contract expires in 2001. Financial Information about Foreign and Domestic Operations Financial Information Relating To Foreign and Domestic Operations (In Thousands of U.S. Dollars) 1996 1995 1994 Revenues from Unaffiliated Customers: Company-United States 56,521 54,585 57,662 Subsidiary-Canada 743 694 706 Intercompany Revenues: Company-United States 683 719 646 Subsidiary-Canada 2,424 1,877 1,824 Operating Income: Company-United States 4,585 3,997 7,932 Subsidiary-Canada 703 367 387 Income before Extraordinary Items Company-United States 1,366 503 4,469 Subsidiary-Canada 745 418 377 Extraordinary Items, Net of Tax Company-United States - (6,236) - Net Income (Loss) Company-United States 1,366 (5,733) 4,469 Subsidiary-Canada 745 418 377 Identifiable Assets: Company-United States 109,891 107,138 115,912 Subsidiary-Canada 6,823 6,936 6,463 The identifiable assets, by company, are those assets used in each company's operations, excluding intercompany receivables and investments. -3- PART I Form 10-K Item 1. Business - Continued Source of Revenues In 1996, consolidated operating revenues totaled $57,264,165. The percentages of revenues derived from customer classes are as follows: % Residential 34.9 Small Commercial and Industrial 28.7 Large Commercial and Industrial 17.6 Public Authorities 1.2 Sales to Wholesale Customers for Resale 3.7 Other Sales and Other Revenues 13.9 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 a 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 3.5% of consolidated MWH sales and 2.4% of consolidated operating revenues for the year ended December 31, 1996. The closing of Loring Air Force Base (Loring) was completed in September, 1994, and accounts for the small percentage of total revenues from Public Authorities. In 1993, when the Base was operating for the entire year, Loring accounted for 7.3% of consolidated MWH sales and 5.7% of consolidated operating revenues. A civilian authority is now the caretaker of the facility charged with finding tenants. The Department of Defense has established a Defense Finance and Accounting Service Center, which will employ approximately 600 people when fully implemented. In addition, Loring was chosen as a Jobs Corp Center, which opened in early 1997. In February 1997, a hardwood floor -4- PART 1 Form 10-K Item 1. Business - Continued manufacturer announced they would locate at Loring, which will create approximately 30 new jobs. The Company has offered load retention rates to several major industrial customers. These customers have the option to self-generate; however, the Company believes it can compete with self-generation. During 1996, the Company entered long-term power contracts with two of its largest customers. The prices under these contracts are lower than permitted under the Company's standard rates, but obligates them to purchase all of their electrical requirements through the year 2000. One additional customer has signed a similar agreement that must be approved by the MPUC, while two others have verbally accepted the Company's offers. Any load retention rates must be approved by the Maine Public Utilities Commission. On November 13, 1995, the Maine Public Utilities Commission approved a Stipulation signed by Maine Public Service Company, the 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(b) of the "Legal Proceedings" section of this Form 10- K. For additional discussion on revenues, see the 1996 Annual Report to Stockholders, pages 3 and 4, "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 -5- PART I Form 10-K Item 1. Business - Continued 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. See the 1996 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 possible 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 1996 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 -6- PART I Form 10-K Item 1. Business - Continued 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 Parent Company owns 5% of the Common Stock of the Maine Yankee Atomic Power Company (Maine Yankee). Maine Yankee owns and operates an 860,000 kilowatt nuclear generating plant in Wiscasset, Maine. The Company is entitled to purchase approximately 4.9% of the energy produced by the plant. During 1996, 1995 and 1994, purchases from Maine Yankee were $10,185,000, $7,972,000 and $9,645,000, respectively. In 1996, Maine Yankee provided approximately 31.1% of the Company's energy requirements. In early February of 1995, during a scheduled refueling-and-maintenance shutdown, Maine Yankee detected an increased rate of degradation of the Plant's 17,000 steam generator tubes in excess of the number expected and started evaluating several courses of action. Maine Yankee could not resume operations until the necessary repairs had been made. Maine Yankee repaired the tubes by inserting and welding short reinforcing sleeves of an improved material in almost all of the steam generator tubes. The sleeving of the steam generator tubes was not completed until mid-December of 1995, at a cost of approximately $27 million, with the Company's share being approximately $1.3 million. During 1995, while Maine Yankee was out of service, the Company incurred additional replacement power costs of approximately $5.7 million. As more fully explained in the "Regulatory Proceeding - Four-Year Rate Plan Approved" section of the Company's 1996 Annual Report, incorporated herein by reference, and Item 3(b) of the "Legal Proceedings" section of this Form 10-K, in late 1995 the Maine Public Utilities Commission (MPUC) approved a multi-year rate plan for the Company. As an element of the rate plan, the Company eliminated the fuel adjustment clause except for the cost of power purchased from the Wheelabrator-Sherman Energy Company, an independent power producer. As part of the rate plan, $2.1 million, net of income taxes, of the replacement power costs associated with the Maine Yankee outage was written off in 1995, $300,000, net of income taxes, will be collected in rates and amortized over the four-year rate plan period, and an estimated $1.3 million, net of income taxes, will be deferred until 2000, when rate recovery will be provided. The rate plan also includes a mechanism to handle similar unexpected Maine Yankee outages during the rate plan period. In addition, the rate plan allows for the five-year amortization of the actual sleeving expenses. On December 4, 1995, when the sleeving project was substantially complete, Maine Yankee obtained a copy of a letter from an organization -7- PART I Form 10-K Item 1. Business - Continued with a history of opposing nuclear power development to a State of Maine nuclear safety official based on documentation from an anonymous employee or former employee of Yankee Atomic Electric Company (Yankee), an affiliate of Maine Yankee that has regularly performed nuclear engineering and related services for Maine Yankee and other nuclear plant operators. The letter contained allegations that Yankee knowingly performed inadequate analyses to support two license amendments to increase the rated thermal power at which the Maine Yankee Plant could operate. It was further alleged in the letter that Maine Yankee deliberately misrepresented the analyses to the Nuclear Regulatory Commission (NRC) in seeking the license amendments. The allegedly inadequate analyses related to the operation of the Plant's emergency core cooling system (ECCS) and the calculation of the Plant containment's peak postulated accident pressure, both under certain assumed accident conditions. The analyses were used in support of license amendments that authorized Plant power uprates from 2,440 megawatts thermal, a level equal to approximately 90 percent of the maximum electrical capability of the Plant, to its current 100-percent rated level. The NRC's office of the Inspector General ("OIG") and its Office of Investigation ("OI") initiated separate investigations of the allegations made in the letter. On May 9, 1996, the OIG, which was responsible for investigating only the actions of the NRC staff and not those of Maine Yankee and Yankee Atomic, reported on its investigation, finding deficiencies in the NRC staff's review, documentation, and communications practices in connection with the license amendments, as well as "significant indications of possible licensee violations of NRC requirements and regulations." Any such violations by Maine Yankee would be within the purview of the OI investigation, which, with related issues, is being reviewed by the United States Department of Justice. A separate internal investigation authorized by the boards of directors of Maine Yankee and Yankee Atomic and conducted by an independent law firm noted several areas for improvement, including regulatory communications, definition of responsibilities between Maine Yankee and Yankee Atomic, and tracking and documentation of regulatory compliance, but found no wrongdoing by Maine Yankee or Yankee Atomic or any of their employees. The Company cannot predict the results of the investigations by the OI and Department of Justice. On January 3, 1996, the NRC issued a "Confirmatory Order Suspending Authority For And Limiting Power Operation And Containment Pressure (Effective Immediately) and Demand For Information" (the Order), after reviewing the safety analyses performed by Yankee relating to Maine Yankee's license amendment applications for the power uprates. The Order limited the power output of Maine Yankee to approximately 90% of -8- PART I Form 10-K Item 1. Business - Continued its rated maximum until the NRC reviewed and approved Plant-specific analyses meeting the NRC's criteria for operation of the ECCS under certain postulated accident conditions, in lieu of the analyses based on the questioned computer code. The Order also required an integrated containment analysis demonstrating that the maximum calculated containment pressure under certain postulated accident conditions does not exceed the design pressure of the Plant's containment. On January 10, 1996, Maine Yankee filed with the NRC information specified in the Order that it believes supports operation of the Plant at up to 90% of the Plant's capability. Maine Yankee attained the 90% level of the Plant's capability on January 24, 1996. On June 7, 1996, the NRC formally notified Maine Yankee that it planned to conduct an "Independent Safety Assessment" (ISA) of the Maine Yankee plant in conjunction with the State of Maine to provide an independent evaluation of the safety performance of Maine Yankee and as a "follow-up" to the NRC's OIG report. The NRC stated that the overall goals and objectives of the ISA were: "(a) provide an independent assessment of conformance to the design and licensing basis; (b) provide an independent assessment of operational safety performance; (c) evaluate the effectiveness of license self-assessments, corrective actions and improvement plans and; (d) determine root cause(s) of safety significant findings and conclusions." The NRC further informed Maine Yankee that the ISA would be carried out by a team of NRC personnel and contractors who were "independent of any recent or significant involvement with the licensing, regulation, or inspection of Maine Yankee." On July 20, 1996, Maine Yankee went off-line to add pressure relief valves to the primary component cooling system, as determined during a comprehensive internal review by Maine Yankee of plant systems and equipment. On September 2, 1996, the plant returned to service, attaining the 90% capacity limit. On October 7, 1996, the NRC released the results of the ISA at Maine Yankee that concluded that although Maine Yankee was in general conformance with its licensing basis, several items of deficient or weak performance existed. The ISA report further concluded that the overall performance at Maine Yankee was "adequate" for operation of the Plant. The ISA report further concluded that the two principal causes for these deficiencies were (1) that economic pressures to be a low-cost power producer had limited resources to address corrective actions and some improvements; and (2) that a questioning culture was lacking, which had resulted in a failure to identify or properly correct significant problems in areas perceived by Maine Yankee to be of low safety -9- PART I Form 10-K Item 1. Business - Continued significance. In a letter to Maine Yankee accompanying the ISA report, Chairman of the NRC Shirley Ann Jackson noted that although overall performance at Maine Yankee was considered adequate for operation, a number of significant weaknesses and deficiencies identified in the report would result in NRC violations. The letter also directed Maine Yankee to provide to the NRC its plans for addressing the root causes of the deficiencies noted in the ISA and identified the NRC offices that would be responsible for overseeing corrective actions and taking any appropriate enforcement actions against Maine Yankee, including as-yet- determined monetary penalties. The plant went off-line again on December 6, 1996 to review and resolve several cable separation and cable routing issues. Maine Yankee will complete a root cause analysis of the cable issues and will present the analysis to the NRC regional office prior to startup. Having detected indications of minor leakage in a small number of the plant's fuel rods, Maine Yankee has used this out-of-service time to inspect the plant's 217 fuel assemblies and has determined that 68 of the fuel assemblies should be replaced. In addition, 24 fuel assemblies will be replaced as part of a refueling. On December 10, 1996, Maine Yankee filed its formal response to the ISA report. In this report, Maine Yankee promised to substantially increase expenditures to address the source of the deficiencies noted in the ISA report, and that the improvements would include physical and operating changes to the Plant, as well as increased staffing, primarily in the engineering and maintenance areas, and other changes. Consequently, Maine Yankee's 1997 Operating Budget has been increased by approximately $46.3 million for additional employees, training and equipment in order to address the root causes of the deficiencies identified in the ISA. The Company's share of this additional amount is approximately $2.3 million. Maine Yankee announced the resignation of President Charles D. Frizzle on December 20, 1996. The Board of Directors of Maine Yankee unanimously decided that new leadership was required to deal with deep- rooted cultural issues, a changing regulatory environment, and unprecedented financial pressures. On February 13, 1997, Maine Yankee and Entergy Nuclear, Inc. ("Entergy"), which is a subsidiary of Entergy Corporation, a Louisiana-based utility holding company and leading nuclear plant operator, entered into a contract under which Entergy will provide management services to Maine Yankee. At the same time, Michael Sellman of Entergy assumed the office of President of Maine Yankee, and -10- PART I Form 10-K Item 1. Business - Continued the contract contemplates that Entergy will provide other management personnel to Maine Yankee. On January 29, 1997, the NRC announced that it had placed the plant on its "watch list", in "Category 2", which includes plants that display "weaknesses that warrant increased NRC attention," but do not warrant a shut-down order. The plant is one of 14 nuclear units in the United States on the January 29 "watch list" and one of six listed there for the first time. The Company expects the plant to remain off-line until the fuel assembly replacement and thorough inspections of the plant's electrical cabling and steam generators are completed, and restarting is approved by the NRC. The Company cannot predict how long the plant will remain off-line, and will make replacement power plans for an outage that could last through the summer of 1997. The Company has been incurring replacement power costs of approximately $170,000 per week while the plant has been out of service. In addition, the Company is responsible for the previously mentioned additional operating costs of $2.3 million associated with the ISA inspection. Further costs are expected when Entergy Corporation begins providing management services to Maine Yankee. Additional costs may also be expected if the complexity of the cable-separation and associated issues require an extended period for their resolution. These additional costs can be expected to adversely impact the Company's 1997 financial results. Under the Company's multi-year rate plan, as described in the "Regulatory Proceedings - Four-Year Rate Plan Approved" section of the Company's 1996 Annual Report, incorporated herein by reference, and Item 3(b) of the "Legal Proceedings" section of this form 10-K, the Company has the right to receive specified retail rate increases through 1999. This plan also includes provisions for additional cost recovery in certain extraordinary situations such as very low earnings or in the event of a Maine Yankee plant outage exceeding six consecutive months. The Company will continue to assess whatever options it may have to recover any additional costs and, in addition, is making every effort to reduce its 1997 cash expenditures. These efforts will include a review of the level of dividends on the Company's Common Stock. Moreover, the Company's short-term revolving credit agreement, as well as a letter of credit supporting its 1996 Series of tax-exempt bonds, contain interest coverage tests that the Company must satisfy to avoid default. The Company now believes, based on the projected additional Maine Yankee expenses and replacement power costs during the -11- PART I Form 10-K Item 1. Business - Continued plant outage, that it will likely be in violation of these interest coverage tests for the twelve months ended March 31, 1997. The Company will seek a waiver of these requirements from the necessary parties. The Company anticipates that the waiver will be granted, but cannot predict the terms of any such waiver. In a related matter, a Maine-based group that originally announced its intention to start gathering signatures toward a new referendum to force a permanent closure of the plant by 2000, has now indicated its intent to modify the referendum to prevent any renewal or extension of Maine Yankee's operating license, currently due to expire in June 2008. The group stated that it hoped to put the issues before the Maine electorate in November, 1998. The Company cannot predict whether such a referendum will be held or its outcome. As an owner of Maine Yankee, the Company is responsible for its proportional share of Maine Yankee operating expenses, including fuel and decommissioning expenses. Furthermore, under a Capital Funds Agreement, the Company, along with the other sponsoring utilities, has agreed to provide Maine Yankee's capital requirements which cannot be obtained from other sources. This obligation is limited to each owner's interest in Maine Yankee, subject to obtaining necessary regulatory approvals. In 1994, pursuant to FERC authorization, Maine Yankee increased its annual collection for decommissioning to $14.9 million, approximately $735,000 a year for the Company. This increase was based on a new decommissioning estimate, assuming dismantlement and removal, of $317 million (in 1993 dollars), as a result of an external engineering study. As of December 31, 1996, Maine Yankee's decommissioning funds are valued at $163.5 million. The decommissioning of nuclear power plants is subject to changes in legal and regulatory requirements as well as technological changes. 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 Maine Yankee and 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. -12- PART I Form 10-K 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 56 6/1/94 Executive Officer Frederick C. Bustard Vice President, 59 6/1/90 Power Supply & Environment Larry E. LaPlante Vice President, 45 6/1/94 Finance, Administration and Treasurer Stephen A. Johnson Vice President, 49 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. -13- PART I Form 10-K 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 13, 1997. There are no family relationships among the executive officers. 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. 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 expects that they will 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. -14- Form 10-K PART I Item 2. Properties - Continued Placing Steam Units 1 and 2 on inactive status will save the Company approximately $3.5 million over the five-year period. These savings result primarily from a savings in operation and maintenance expense. The Company eliminated 12 positions at the Plant and offered a Company-wide voluntary early retirement program that was successful in avoiding involuntary termination of some of the employees whose positions at the units had been eliminated. 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, 1996, the Company and Subsidiary had approximately 443 pole miles of transmission lines and the Company owned approximately 1,603 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. -15- Form 10-K PART I Item 3. Legal Proceedings (a) Maine Public Utilities Commission, Re: Electric Utility Industry Restructuring Study, Docket No. 95-462. In 1995, the Maine Legislature passed Resolve 89 "To Require a Study of Retail Competition in the Electric Utility Industry" (the "Resolve"), to begin a process for developing recommendations on the future structure of the electric utility industry in Maine. The process included the appointment of a Work Group on Electric Utility Restructuring to develop a plan for the orderly transition to a competitive market for retail purchases and sales of electricity. The Company participated in this Work Group, which was unable to reach a consensus on a recommended plan by its reporting deadline. The Resolve also directed the MPUC to conduct a study to develop at least two plans for the orderly transition to retail competition in the electric utility industry in Maine and to submit a report of its findings by January 1, 1997. One plan would be designed to achieve "... full retail market competition for purchases and sales of electric energy by the year 2000" and the other to achieve a more limited form of competition. The Resolve also stated that the MPUC's findings would have no legal effect, but would "... provide the Legislature with information in order to allow the Legislature to make informal decisions when it evaluates these plans." On December 12, 1995, the MPUC issued a Notice of Inquiry (the "Notice") initiating its study. In the Notice, the MPUC solicited detailed proposals and plans for achieving retail competition in Maine by the year 2000 and requested the proposals include specific plans for an orderly transition to a more competitive market. The Notice required that plans and proposals be filed with the MPUC by interested parties no later than January 31, 1996, and outlined a schedule calling for submittal of a final report to the Legislature in December, 1996. On January 30, 1996, the Company filed its restructuring proposal with the MPUC. The major elements of this proposal were: (a) The separation of the Company's generation assets (including contracts and entitlements) from its transmission and distribution assets. The Company suggested this separation could be accomplished by either -16- Form 10-K PART I Item 3. Legal Proceedings - Continued a functional separation of generation from distribution and transmission within the Company's existing corporate structure or by separating generation, on the one hand, and distribution and transmission, on the other, into two wholly-owned subsidiaries. The Company strongly opposes any recommendation that it be required to divest itself of its generation assets. (b) The economic and resource planning regulation of generation would cease. The FERC would continue to regulate transmission, and distribution would remain a franchised monopoly subject to continued regulation by the MPUC. The owner of the distribution system would be obligated to connect all willing customers. (c) If certain necessary changes in the operation and management of the regional transmission grid are in place, all retail customers in Maine would, by the year 2000, be entitled to purchase electric energy directly from any entity that wished to supply it to them. (d) The Company would be entitled to full recovery of all its stranded costs. This recovery would be accomplished by a charge on the distribution system that would apply to all retail customers. In its filing, the Company estimates that its stranded costs could be as high as $68 million. This amount consists primarily of the above-market costs of the Company's contract with Wheelabrator-Sherman, a non-utility generator, estimated at $44 million and deferred regulatory assets, such as its Seabrook investment of $24 million. On December 31, 1996, the MPUC issued its Recommended Plan on how to restructure Maine's electric utility industry. The Plan recommends the following: * As of January, 2000, all Maine consumers would have the option to choose an electric power supplier. * As of January, 2000, Maine would not regulate, as public utilities, companies producing or selling electric power. * Regulated public utilities would continue to provide electric transmission and distribution (T&D) services. -17- Form 10-K PART I Item 3. Legal Proceedings - Continued * As of January, 2000, the Company, Central Maine Power Company (CMP) and Bangor Hydro-Electric Company (BHE), the State's three largest electric utilities, would be required to structurally separate their generation assets and functions from transmission and distribution functions. CMP and BHE would be required to fully divest themselves of their generation assets by 2006. * The Plan does not recommend generation divestiture for the Company, but instead proposed to allow the Company to retain its generation assets in a separate, but wholly-owned, subsidiary. In making this recommendation, the MPUC relied upon MPS's relatively small size, its isolation from the rest of New England and concerns about the Company's Canadian Subsidiary. The Plan further stated that the MPUC would "periodically review whether divestiture [of the Company's generation assets] would be required". * The T&D utilities would retain their ownership interests in Maine Yankee, but would be required to transfer the rights to the output to an affiliated generation company. After 2005, BHE and CMP, but not the Company, would be required to sell the rights to the output to the highest bidder. * All contracts between the utilities and any qualifying facilities under PURPA will remain with the T&D companies. * The utilities should be provided a reasonable opportunity to fully recover its generation-related stranded costs. All of the Company's anticipated stranded costs are generation-related. -18- Form 10-K PART I Item 3. Legal Proceedings - Continued Because the MPUC's Recommended Plan does not have any binding legal effect, this issue must ultimately be resolved by the Maine Legislature. Many parties to this proceeding have taken positions that vary substantially from those set forth in this Plan and those parties can be expected to advocate their positions before the Legislature. The Company cannot, therefore, predict what form the restructuring of Maine's electric utility industry will ultimately take or what effect that restructuring will have on the Company's business operations or financial results. (b) Multi-year Rate Plan is Approved for the Company by the MPUC in Maine Public Service Company Re: Proposed Increase in Retail Rates, MPUC Docket No. 95-052 On May 1, 1995, Maine Public Service Company filed with the Maine Public Utilities Commission a proposed increase in the rates it charges its retail customers. The Company at the same time filed a five-year rate plan requesting new rates beginning in January, 1996 as detailed below. Reference is made to the Company's Form 10-Q for the quarter ended June 30, 1995 for a complete description of the Company's filed rate plan. After extensive negotiations, the Company, the MPUC Staff and the Public Advocate filed a Stipulation with the Commission on November 6, 1995, which established a four- year rate plan for the Company. The one remaining party to this proceeding, McCain Foods, Inc., opposed this Stipulation. After a hearing on November 13, 1995, the MPUC approved this Stipulation over the objection of McCain Foods, Inc. Under the terms of the Stipulation, the Company has the right to receive the following increases: January 1, 1996 4.4% $2.1 million February 1, 1997 2.9% 1.4 million February 1, 1998 2.75% 1.4 million February 1, 1999 2.75% 1.4 million -19- Form 10-K PART I Item 3. Legal Proceedings - Continued These increases will be subject to increases or decreases resulting from the operation of the profit-sharing mechanism, as well as the mandated costs and plant outage provisions described below. The Company agreed that it will seek no other increases, for either base or fuel rates, except as provided under the terms of the rate plan. There will be no fuel clause adjustments during the term of the plan. The first two increases of 4.4% and 2.9% became effective, as scheduled, on January 1, 1996 and February 1, 1997, respectively. In 1995, the Company wrote off and will not collect in retail rates the following amounts: (a) $4,845,812, net of income taxes, of its investment in Seabrook previously allocated to wholesale sales. (b) $1,390,000, net of income taxes, in other plant investment, i.e. rate base, except transmission plant, previously associated with the wholesale customers. (c) $3,500,000 ($2,104,000, net of income taxes) in deferred fuel. The total amount of the write-offs, net of income taxes, in 1995 were approximately $8,340,000, or approximately $5.16 per share of common stock. As a condition of the Stipulation, the Company requested waivers for interest coverage tests under its revolving credit arrangement and the Letter of Credit supporting the public utility revenue bonds, 1991 series. Unless these write-offs were considered extraordinary for purposes of the interest coverage tests, the Company would have been in violation of these interest coverage tests. The waivers were received from the various lenders prior to the MPUC's issuance of its order in this proceeding. -20- Form 10-K PART I Item 3. Legal Proceedings - Continued The Company will also be permitted to defer an amount of $1.5 million annually of the costs of the Wheelabrator- Sherman (WS) purchases over the term of the rate plan. The approved rate plan provides that the Company can seek recovery of this deferred amount (up to a total of $6 million) in rates beginning in the year 2001, after the current term of the WS contract has expired. The Company will further collect in rates and amortize over the four years of the rate plan, $300,000, net of income taxes, in deferred fuel with the remainder, approximately $1.3 million, net of income taxes, being deferred until the year 2000, when rate recovery will be determined. The approved rate plan further provides for the following treatment of the Maine Yankee steam generator sleeving costs: the Company will amortize its share of these costs in equal amounts over a five-year period beginning on January 1, 1996. At the expiration of the rate plan, the remaining one-fifth of the costs will be amortized in 2000 subject to rate treatment at that time. The approved rate plan contains a profit-sharing mechanism based upon a target return of equity (ROE) of 11%, calculated according to retail ratemaking mechanisms. This profit-sharing mechanism will apply only to the last two rate increases scheduled to occur on February 1, 1998 and February 1, 1999. As part of this review process, the target ROE will be subject to adjustment based on an index by averaging over a twelve- month period the dividend yields on Moody's group of 24 electric utilities and Moody's utility bond yields. The profit-sharing mechanism works as follows: If the Company's ROE exceeds the target ROE by less than 300 basis points, this gain accrues entirely to shareholders. Similarly, any deficiency of up to 300 basis points below the target ROE is borne entirely by the shareholders. All deficiencies of 300 or more basis points below the target ROE will be shared equally by shareholders and customers. All earnings of 300 or more basis points above the target ROE must first be applied to reduce any of deferred WS costs described above. Any remaining excess earnings will be shared equally by customers and shareholders. -21- Form 10-K PART I Item 3. Legal Proceedings - Continued The plan also allows the Company to terminate the rate plan and file for rate increases under traditional rate application procedures if its earnings fall 500 or more basis points below the target ROE during any twelve-month period during the term of the plan. The method agreed to by the parties for measuring earned ROE for the purpose of the profit-sharing mechanism and rate termination provision described above, allocates various revenues and expenses between the wholesale and retail jurisdictions using allocators that, in part, reflect the Company's 1994 allocations. With the loss of sales to Houlton Water Company in 1996, the Company estimates that the use of the agreed-upon allocators will produce a calculation of earnings for the profit-sharing and termination mechanisms that could be as much as 400 basis points above the Company's actual financial ROE. Because of this disparity, the Stipulation provides that the agreed-upon allocation methodology will not apply if the use of those allocators will require the Company to write off any additional assets in accordance with Generally Accepted Accounting Principles (GAAP). In that event, the parties have agreed to develop a different method for calculating profit-sharing and termination that will not require the Company to write off any additional assets. The plan also provides that if either Maine Yankee or WS cease operation for more than six months, the Company shall be allowed to adjust its allowed rate increases by 50% of the net costs or net savings resulting from the outage, together with any carrying costs on the balance deferred. Any net costs or net savings during the first six months of the outage would accrue entirely to shareholders. The plan further contains a mechanism for allocating the savings resulting from any restructuring of the WS contract during the term of the plan. Any savings would be allocated first to the WS deferred costs accumulating at $1.5 million annually, then to the deferred fuel balance as of December 31, 1995 being deferred until 2000, next to eliminate any on-going WS deferrals and finally, any savings that remain will be allocated 95% to customers and 5% to shareholders. -22- Form 10-K PART I Item 3. Legal Proceedings - Continued The plan provides that the Company can flow through to customers at the time of the scheduled rate increases, increases or decreases resulting from certain mandated costs, such as tax or accounting changes, but not costs resulting from natural disasters. To qualify, a mandated cost must receive MPUC approval, must be beyond the control of the Company's management, must effect the Company specifically or the electric utility generally and must exceed $300,000 in annual revenue requirements. The Stipulation also provides for a number of accounting orders. Among these are orders: permitting the Company to amortize deferred post-retirement benefits other than pension (SFAS 106) expenses in equal amounts over a ten- year period beginning January 1, 1996, along with the recovery of current year SFAS 106 costs; permitting the Company to continue rate base treatment for unrecovered plant costs and depreciation on the Caribou Steam Units as well as the deferral and amortization over five years of the reduction in force expenses (including pension expenses under SFAS 88) resulting from the closing of those units; and continued deferral and amortization of replacement power and capacity costs associated with Maine Yankee scheduled outages. Finally, the Stipulation clarifies that the rate plan is not deregulation for accounting purposes and provides for the continuing recovery in rates of certain "regulatory assets", such as the retail portion of the Company's Seabrook investment, previously allowed by the MPUC. On January 2, 1996, McCain Foods, Inc., which had objected to the Stipulation, appealed the MPUC's approval of the rate plan to the Maine Supreme Judicial Court. This action was docketed as PUC 96-13. On March 20, 1996, the Company and McCain Foods filed with the Commission a Power Purchase Agreement under which McCain agreed to purchase all its electrical requirements from the Company through 2000. On April 29, 1996, the MPUC approved the Agreement and McCain dismissed its appeal shortly thereafter. In addition to the four-year rate plan, the MPUC, under this docket, also approved the Company's proposal to develop flexible rates to retain or attract new customers. On October 23, 1995, the Company implemented a reduced Rate AH for existing residential electric space -23- Form 10-K PART I Item 3. Legal Proceedings - Continued heat. Customers who have a permanent electric space heat system that supplies at least 50% of their heating requirements have been offered a discount up to 40% from October to April. On November 27, 1995, the MPUC approved two new rates that became effective December 1, 1995. The first, Rate F, provides farmers with a discounted price for electricity used in storage facilities, reducing their winter electric rate ten percent from November through March. The second, Rate EDR, an economic development rate, provides a multi-year discount in the cost of electric service for large commercial and industrial customers who create new electrical load. This reduced rate should encourage development in our electrical service territory by providing an incentive rate while a new business gets established or an existing business, meeting certain criteria, completes expansion. Depending on eligibility, the discount offered will range from 20% the first year to 5% in the fourth year. After the four- year period, EDR customers will be billed under the Company's standard electric rates. On January 21, 1997, the Company filed with the MPUC a proposed reduced electric heat rate for new electric space heating installations and a rebate program for customers who purchase and use electric water heaters. Both filings are pending before the MPUC. (c) Peoples Heritage Bank v. Maine Public Service Company U.S. District Court (D. ME) Civil Action No. 95-0180-B On September 18, 1995, Peoples Heritage Bank filed against the Company a civil action for declaratory and monetary relief seeking recovery for response costs, damages and attorneys fees incurred because of the release of hazardous substance at a site in Presque Isle, Maine. In 1992, Peoples Heritage purchased the property and shortly thereafter discovered that the soil at the site was contaminated with polychlorinated biphenyls (PCBs) which it now alleges originated with two electrical transformers placed on the site by the Company. Peoples Heritage claims to have spent in excess of $250,000 to remove the PCB contaminated soil and seeks reimbursement of this amount. -24- Form 10-K PART I Item 3. Legal Proceedings - Continued The suit was brought pursuant to the Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA), the Federal Declaratory Judgment Act and under common law grounds of strict liability for abnormally dangerous activities, negligence and trespass. On December 2, 1996, the Court issued its judgment in this proceeding for the Company and against Peoples Heritage. The Court concluded that Peoples Heritage failed to prove the Company had caused a release of a hazardous substance at the site and credible expert testimony pointed to other causes of contamination. (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 1997. The Company cannot predict the FERC's ultimate decision in this matter. (e) Maine Public Service Company, Proposed Increase in Rates (Rate Design), MPUC Docket No. 95-052. On June 15, 1995, the MPUC issued an order bifurcating the Company's request for rate design from the revenue requirement portion of this docket (see item (b) above). Based upon marginal cost of service principles, the Company had proposed a substantial redesign of its current rates. For example, under the Company's proposed rates for large industrial customers would have decreased from their current level by nearly 8%, while rates for -25- Form 10-K PART I Item 3. Legal Proceedings - Continued residential customers would have increased by over 8%. The Company's proposals were vigorously contested by the MPUC Staff and the Public Advocate, who proposed only a small decline for large industrial customers and a very minor increase for residential. Hearings were held on this matter before the MPUC on March 14 and 15, 1996. On June 26, 1996, the MPUC issued its Order in this matter. The MPUC found that, despite some infirmities in the Company's supporting data, the Company was entitled to a more substantial reallocation of its rates than advocated by the MPUC Staff and Public Advocate. As a result, rates for large industrial customers will decrease by approximately 4.5%, while rates for residential and commercial customers will increase by approximately 1% and 3%, respectively. These changes became effective June 29, 1996. -26- 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 14, 1996, the only matter voted upon was the uncontested election of the following directors to serve until the 1999 Annual Meeting of Stockholders, each of whom received the votes shown: Non-votes and Nominee For Against Abstentions D. James Daigle 1,380,715 22,433 214,102 Deborah L. Gallant 1,374,834 28,314 214,102 G. Melvin Hovey 1,379,191 23,957 214,102 Walter M. Reed, Jr. 1,374,834 24,219 218,197 -27- 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, 1996, there were 1,619 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 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 1995 First Quarter $23-7/8 $20-5/8 $ .46 $ .46 Second Quarter $22-3/4 $19-7/8 .46 .46 Third Quarter $23-1/4 $21 .46 .46 Fourth Quarter $23-1/2 $20-5/8 .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 (1992-1996) is included on page 12 of the Company's 1996 Annual Report to Stockholders, which summary is incorporated herein by reference. -28- 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 3-11, Exhibit 13, 1996 Annual Report to Shareholders, which pages are hereby incorporated herein by reference. Information regarding "Construction" is also furnished in Note 10, "Commitments and Contingencies", of the Notes to the Consolidated Financial Statements, pages 25 to 27 of the 1996 Annual Report to Shareholders, which pages are hereby incorporated herein by reference. -29- 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 1996 Annual Report to Stockholders on pages 13 through 27 and are incorporated herein by reference: Independent Auditors' Report. Statements of Consolidated Operations for the years ended December 31, 1996, 1995 and 1994. Statements of Consolidated Cash Flows for the years ended December 31, 1996, 1995 and 1994. Consolidated Balance Sheets as of December 31, 1996 and 1995. Statements of Consolidated Common Shareholders' Equity for the years ended December 31, 1996, 1995 and 1994. Consolidated Statements of Capitalization as of December 31, 1996 and 1995. Notes to Consolidated Financial Statements. 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, LLP, (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 -30- Form 10-K Item 9. Changes In And Disagreements With Accountants On Accounting and Financial Disclosure - Continued 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 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 either fiscal years 1995 or 1994 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 or any time thereafter has there been any disagreement between the Company and the firm of Deloitte & Touche 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 or any time thereafter did any event occur between the Company and Deloitte & Touche that would require further reporting in this Form 10-K. At no time during the Company's two most recent fiscal years 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. -31- 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 1997 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 1997 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 1997 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 1997 Annual Meeting of Stockholders, which information is incorporated herein by reference. Item 13. Certain Relationships and Related Transactions Not applicable. -32- Form 10-K PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K (a) (1) Financial Statements Independent Auditors' Report appears on page 44 of this Form 10-K. Incorporated by reference into Part II of this report from pages 13 through 27 of the 1996 Annual Report to Stockholders: Independent Auditors' Report. Statements of Consolidated Operations for years ended December 31, 1996, 1995 and 1994. Statements of Consolidated Cash Flows for the years ended December 31, 1996, 1995 and 1994. Consolidated Balance Sheets as of December 31, 1996 and 1995. Statements of Consolidated Common Shareholders' Equity for the years ended December 31, 1996, 1995 and 1994. Consolidated Statements of Capitalization as of December 31, 1996 and 1995. Notes to Consolidated Financial Statements. (2) Financial Statement Schedules Included in Part IV of this report: -33- Form 10-K PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K - Continued Page Report of Independent Public Accountants 44 Schedule II - Valuation of Qualifying Accounts 45 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) -34- Form 10-K PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K - Continued 4(g) Sixth Supplemental Indenture. (Exhibit A to Form 8-K dated April 10, 1973) 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. -35- Form 10-K PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K - Continued 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 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) -36- Form 10-K PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K - Continued 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 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) -37- Form 10-K PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K - Continued 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 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 -38- Form 10-K PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K - Continued 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 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, -39- Form 10-K PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K - Continued Fleet Bank of Maine, and The Bank of New York, an agent for the participating Banks. 11 Not applicable. 12 Not applicable. *13 1996 Annual Report to Shareholders. *16 March 8, 1996 Letter regarding change in certifying accountant from Deloitte & Touche LLP 18 Not applicable. 19 Not applicable. 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). -40- Form 10-K PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K - Continued 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). 99(i) Order (corrected) of the Maine Public Utilities Commission dated December 5, 1990 in Docket No. 87-167 (with attached Stipulation). (Exhibit 28(l) to 1990 Form 10-K). 99(j) Order of the Federal Energy Regulatory Commission Dated September 30, 1992 in Docket No. ER92-774-000 and EL91-56-000. (Exhibit 28(k) to 1992 Form 10-K) 99(k) Order of the Federal Energy Regulatory Commission dated December 11, 1992 in Docket ER93-17-000. (Exhibit 28(l) to 1992 Form 10- K) 99(l) 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(m) 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). -41- Form 10-K PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K - Continued *99(n) Order of Maine Public Utilities Commission dated June 26, 1996 in Docket 95-052 (Rate Design) *99(o) December 31, 1996 Report and Recommended Plan of Maine Public Utilities Commission Regarding Electric Utility Restructuring, Docket No. 95- 462. *99(p) Judgment of U.S. District Court (D. Me.) dated December 2, 1996 in Peoples Heritage Bank v. Maine Public Service Company, Civil Action No. 95-0180-B. *99(q) Deloitte & Touche LLP's Report of Independent Auditors dated February 14, 1996 regarding previous years' audit opinions. (b) A Form 8-K was filed on: July 25, 1996 under item 5, Other Events; December 18, 1996, under item 5, Other Events; December 23, 1996, under item 5, Other Events; January 31, 1997, under item 5, Other Events; and February 14, 1997, under item 5, Other Events. A form 8-K/A was filed on March 14, 1996 under item 4, Change in the Company's Certifying Accountant. 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 19th of March, 1997. MAINE PUBLIC SERVICE COMPANY By: /s/ Larry E. LaPlante Larry E. LaPlante Vice President, Finance, Administration, and Treasurer -42- 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. Melvin Hovey and Director 3/11/97 (G. Melvin Hovey) /s/ Paul R. Cariani President and Director 3/8/97 (Paul R. Cariani) /s/Robert E. Anderson Director 3/8/97 (Robert E. Anderson) /s/ Donald F. Collins Director 3/7/97 (Donald F. Collins) /s/ D. James Daigle Director 3/8/97 (D. James Daigle) /s/ Richard G. Daigle Director 3/10/97 (Richard G. Daigle) /s/ J. Gregory Freeman Director 3/13/97 (J. Gregory Freeman) /s/ Deborah L. Gallant Director 3/10/97 (Deborah L. Gallant) Director (Nathan L. Grass) /s/ J. Paul Levesque Director 3/10/97 (J. Paul Levesque) /s/ Walter M. Reed, Jr Director 3/13/97 (Walter M. Reed, Jr.) -43- 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, 1996, and for the year then ended, which financial statements are included on pages 13 through 27 of the 1996 Annual Report to Shareholders of Maine Public Service Company and incorporated by reference herein. We have also audited the financial statement schedule listed in the index on page 34 of this Form 10-K. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these 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, 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, 1996, and the consolidated results of their operations and their cash flows for the year then ended in conformity with generally accepted accounting principles. In addition, in our opinion, the financial statement schedule 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. Portland, Maine February 11, 1997 -44- Maine Public Service Company & Subsidiary Valuation of Qualifying Accounts & Reserves For the Years Ended December 31, 1996, 1995, & 1994 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: 1996 214,130 182,000 102,627 291,728 207,029 1995 214,215 150,800 109,390 260,275 214,130 1994 214,329 119,000 164,999 284,113 214,215 -45- Exhibit 10(t) THIS INSTRUMENT GRANTS A SECURITY INTEREST BY A TRANSMITTING UTILITY THIS INSTRUMENT CONTAINS AFTER-ACQUIRED PROPERTY PROVISIONS MAINE PUBLIC SERVICE COMPANY TO IBJ SCHRODER BANK & TRUST COMPANY Trustee THIRD SUPPLEMENTAL INDENTURE Dated as of June 1, 1996 Supplementing Indenture of Second Mortgage and Deed of Trust dated as of October 1, 1985 and Relating to an Issue of Second Mortgage and Collateral Trust Bonds, Series Due 2002 This is a Security Agreement granting a Security Interest in Personal Property, Including Personal Property affixed to Realty as well as a Mortgage upon Real Estate and other Property. THIS THIRD SUPPLEMENTAL INDENTURE (hereinafter called the "Third Supplemental Indenture"), dated as of June 1, 1996, made by MAINE PUBLIC SERVICE COMPANY, a Maine corporation (hereinafter called the "Company"), party of the first part, and IBJ SCHRODER BANK & TRUST COMPANY (as successor to J. Henry Schroder Bank & Trust Company), a banking corporation duly organized and existing under the laws of the State of New York, and having its principal place of business in the City of New York, State of New York (hereinafter called the "Trustee"), party of the second part. WHEREAS, the Company has heretofore executed and delivered to the Trustee an Indenture of Second Mortgage and Deed of Trust, dated as of October 1, 1985 (hereinafter called the "Original Indenture"), to secure the payment of principal and interest on, as provided therein, its bonds (in the Original Indenture and herein called the "Bonds") to be designated generally as its "Second Mortgage and Collateral Trust Bonds", and to be issued in one or more series as provided in the Original Indenture, pursuant to which the Company provided for the creation of the Bonds of the initial series, known as Second Mortgage and Collateral Trust Bonds, Floating Rate Series A due 1987 (herein sometimes called "Bonds of the 1987 Series"), Second Mortgage and Collateral Trust Bonds, 14% Series due 1990 (herein sometimes called "Bond of the 1990 Series") and Second Mortgage and Collateral Trust Bonds, 9 7/8% Series due 1995 (herein sometimes called "Bonds of the 1995 Series" and together with the Bonds of the 1987 Series and the Bonds of the 1990 Series, called collectively the "Bonds of the Initial Series"); and WHEREAS, the Company has heretofore executed and delivered to the Trustee a First Supplemental Indenture, dated as of March 1, 1991, pursuant to which the Company supplemented and modified the Original Indenture and provided for the creation of a fourth series of Bonds designated as "Second Mortgage and Collateral Trust Bonds, Series due 1996" (herein sometimes called "Bonds of the 1996 Series"); and WHEREAS, the Company has heretofore executed and delivered to the Trustee a Second Supplemental Indenture, dated as of September 1, 1991, pursuant to which the Company supplemented the Original Indenture, as supplemented and modified, and provided for the creation of a fifth series of Bonds designated as "Second Mortgage and Collateral Trust Bonds, 9.60% Series due 2001" (herein sometimes called "Bonds of the 2001 Series"); and WHEREAS, pursuant to the Original Indenture, as so supplemented and modified, there have been executed, authenticated and delivered and there are now outstanding Second Mortgage and Collateral Trust Bonds of Series and in principal amounts as follows: Issued Outstanding Bonds of the 2001 Series $7,500,000 $7,500,000 which constitute the only Bonds outstanding under the Original Indenture, as so supplemented and modified; and WHEREAS, the Company now desires to create a new series of Bonds to be designated Second Mortgage and Collateral Trust Bonds, Series due 2002 (herein sometimes called the "Bonds of the 2002 Series"), and the Original Indenture provides that each series of Bonds (except the Bonds of the Initial Series) shall be created by an indenture supplemental to the Original Indenture; and WHEREAS, the Original Indenture further provides that all property of the character specifically described in the Original Indenture, and all improvements, extensions, betterments or additions to the property specifically described in the Original Indenture, constructed or acquired after the date of the execution and delivery of the Original Indenture, shall be and become subject to the lien of the Original Indenture, and that the Company shall from time to time execute, acknowledge and deliver any and all such further assurances, conveyances, mortgages or assignments of such property as may be required by the terms and provisions of the Original Indenture, or as the Trustee under the Original Indenture may require, and the Company now desires to subject to the lien of the Original Indenture certain additional properties which it has constructed or acquired since the date of execution and delivery of the Second Supplemental Indenture; and WHEREAS, all acts and proceedings required by law and by the charter and by-laws of the Company necessary to make the Bonds of the 2002 Series to be initially issued when executed by the Company, authenticated and delivered by the Trustee and duly issued, the valid, binding and legal obligations of the Company, and to constitute the Original Indenture, as heretofore supplemented and modified and as supplemented and modified by this Third Supplemental Indenture, a valid and binding mortgage and deed of trust, subject to permitted encumbrances including the lien of the Indenture of First Mortgage (each as defined in the Original Indenture), for the security of the Bonds, in accordance with the terms of the Original Indenture, as so supplemented and modified, and the terms of the Bonds, have been done and taken; and the execution and delivery of this Third Supplemental Indenture and the issue of the Bonds of the 2002 Series to be initially issued have been in all respects duly authorized; NOW, THEREFORE, for the purposes aforesaid and in pursuance of the terms and provisions of the Original Indenture, the Company has executed and delivered this Third Supplemental Indenture (the Original Indenture, as supplemented and modified by the First Supplemental Indenture, and supplemented by the Second Supplemental Indenture and as supplemented and modified by this Third Supplemental Indenture and any and all supplemental indentures hereafter entered into between the Company and the Trustee in accordance with the provisions of the Original Indenture, as supplemented and modified, being herein sometimes called the "Indenture"), and in consideration of the sum of One Dollar ($1.00) to the Company duly paid by the Trustee at or before the ensealing and delivery hereof, and for other good and valuable considerations, the receipt whereof is hereby acknowledged, the Company hereby covenants to and with the Trustee and its successors in the trusts under the Original Indenture, as supplemented and modified, as follows: ARTICLE ONE Schedule of Mortgaged Property. SECTION 1.01. In order further to secure the payment of the principal of, premium, of any, and interest on, all Bonds at any time issued and outstanding under the Indenture, according to their tenor, purport and effect, and further to secure the performance and observance of all the covenants and conditions in said Bonds and in the Original Indenture, as supplemented and modified, and in this Third Supplemental Indenture contained, for the considerations above expressed, and for and in consideration of the mutual covenants herein contained and of the purchase and acceptance of the Bonds by holders thereof, the Company has executed and delivered this Third Supplemental Indenture and by these presents does grant, bargain, sell, alien, remise, release, convey, assign, transfer, mortgage, pledge, set over and confirm unto IBJ Schroder Bank & Trust Company, as Trustee under the Indenture, and to its assigns forever, all property, real, personal or mixed, acquired since the execution and delivery of the Second Supplemental Indenture which by the terms of the Original Indenture, as supplemented and modified, is subject or is intended to be subject to the lien of the Indenture, including without limiting the generality of the foregoing, the following described property: CLAUSE I PART I AROOSTOOK COUNTY, MAINE (1) A certain piece or parcel of real estate in said Ashland, bounded and described as follows, to wit: Beginning at the Northeast corner of a plot of land owned by George Allen adjacent to the Sheridan Road, so called, thence along the northerly property line N71 degrees-28'W distant 165 feet more or less to the northwest corner of the said plot of land; thence along the westerly property line approximately S18 degrees-32'W distant 100 feet more or less; thence S71 degrees-28'E distant 165 feet more or less to the westerly boundary of the Sheridan Road, so called; thence approximately N18 degrees- 32'E along the easterly boundary of the said plot of land distant 100 feet more or less to the point of beginning. Recorded in the Southern District of the Aroostook Registry of Deeds in Volume 2534, page 56 on January 21, 1993. (2) A certain piece or parcel of land situated in the Town of Ashland, in the County of Aroostook and State of Maine, being a one hundred (100) foot wide strip of land easterly of and contiguous to an existing right-of-way now or formerly owned by Maine Public Service Company as recorded in the Southern District of the Aroostook Registry of Deeds in Vol. 1126, Page 264, said one hundred (100) foot wide strip of land extends from the northerly line of a parcel of land now or formerly owned by Maine Public Service Company as recorded in said Registry in Vol. 1124, Page 17, to the northerly line of Lot 14, said strip being a part of Lot No. 14, also being part of the land now or formerly owned by Carlton L. and Catherine E. Jimmo, as recorded in Vol. 1036, Page 374, in said Registry, bounded and described more particularly as follows, to wit: Beginning at a 1/2" diameter metal pipe found at the northeasterly corner of a parcel of land now or formerly owned by Maine Public Service Company as recorded in Vol. 1124, Page 17; thence along the northerly line of Vol. 1124, Page 17 a magnetic bearing of North seventy-one degrees thirty- five minutes zero zero seconds west (N 71 degrees 35' 00" W) a distance of fifty-eight and fifty-two hundredths (58.52) feet to the southeasterly corner of a parcel of land now or formerly owned by Maine Public Service Company as recorded in said Registry in Vol. 1126, Page 264; thence along the easterly line of Vol. 1126, Page 264 north eighteen degrees zero five minutes fifteen seconds east (N 18 degrees 05' 15" E) a distance of one thousand seventy-eight and eight-one hundredths (1078.81) feet to the northerly line of Lot 14; thence along the northerly line of Lot 14 and remains of a cedar rail fence south seventy-one degrees fifty-four minutes forty-five seconds east (S 71 degrees 54' 45"E) a distance of one hundred (100) feet to a rebar set in a cedar rail; thence parallel with the easterly line of Vol. 1126, Page 264 south eighteen degrees zero five minutes fifteen seconds west (S 18 degrees 05' 15" W) a distance of one thousand seventy-nine and thirty-eight hundredths (1079.38) feet to a rebar set; thence north seventy-one degrees thirty-five minutes zero zero seconds west (N 71 degrees 35' 00" W) a distance of forty- one and forty-eight hundredths (41.48) feet to the point of beginning, the last two courses being across the source parcel, the above described parcel of land containing two and forty-eight hundredths acres (2.48). The above described piece of land is based on a field survey conducted under the supervision of Daniel O. Bridgeham, P.L.S. #1027, and shown on a Plat dated March 31, 1992. All bearings are magnetic as of March, 1992. All monuments set were 5/8" metal rebar with yellow plastic caps affixed to them, with Daniel O. Bridgham, P.L.S. #1027: imprinted on the caps. Recorded in the Southern District of the Aroostook Registry of Deeds in Volume 2476, page 152 on June 30, 1992. (3) The following described piece or parcel of real estate being a part of Section 11, Lot Number Four (4) in the City of Presque Isle, formerly Maysville, County of Aroostook and State of Maine, and being more particularly bounded and described as follows, to wit: Commencing at a point on the easterly right-of-way of the Parkhurst Siding Road, so-called, at the northwest corner of a parcel of land conveyed to Maine Public Service Company by Warranty Deed recorded at the Southern Aroostook Registry of Deeds in Volume 630, Page 286; thence along the easterly right-of-way of said Parkhurst Siding road, along a 1,000 foot radius curve to the right with a delta of 20-36-48, an arc distance of three hundred fifty-nine and seventy-seven thousandths (359.77) feet to a point; thence north seventeen degrees thirty-three minutes ten seconds east (N 17 degrees 33' 10" E) a distance of one hundred fifty-four and sixty-two thousandths (154.62) feet to a 5/8" rebar set which rebar marks the point of beginning of the real estate conveyed herein; thence south sixty-eight degrees thirty minutes eighteen seconds east (S 68 degrees 30' 18" E) a distance of one hundred thirteen and nine tenths (113.9) feet to a 5/8" iron rebar set; thence north twenty-one degrees twenty-nine minutes twenty-two seconds east (N 21 degrees 29' 22" E) a distance of two hundred (200) feet to a 5/8" iron rebar set; thence north sixty-eight degrees thirty minutes thirty-eight seconds west (N 68 degrees 30' 38" W) a distance of one hundred fifteen and fifty-five thousandths (115.55) feet to a 5/8" iron rebar set on the easterly line of the right-of-way of said Parkhurst Siding Road; thence in a parallel southerly direction along the easterly margin of said Parkhurst Siding Road a distance of two hundred (200) feet, more or less, to the iron rebar set marking the point of beginning of the real estate conveyed herein. Recorded in the Southern District of the Aroostook Registry of Deeds in Volume 2412, Page 144 on November 20, 1991. PENOBSCOT COUNTY, MAINE (1) Beginning on the westerly Right of Way limit of State Highway "320" (Rte. 11) Federal Aid Project No. S-0320 (2), Patten, Penobscot County, Maine, at a monument located at Station 130 + 00; thence N28 degrees 13'E along said westerly Right of Way limit to the Eastern Maine Electric property line distant 89.2 feet; thence N61 degrees 47'W distant 172'; thence, N28 degrees 13'E distant 100 feet; thence, S61 degrees 47'E distant 160 feet; thence N28 degrees 13'E distant 10 feet; thence N61 degrees 47'W distant 170 feet; thence S28 degrees 13'W distant 120'; thence S61 degrees 47'E distant 10 feet; thence, S28 degrees 13'W distant 115 feet; thence S61 degrees 47'E distant 172 feet; thence N 28 degrees 13'E distant 35.8 feet and point of beginning. All bearings are magnetic 1963. Being a portion of Lot #37 according to the original plan of the Town of Patten, Maine, recorded in Plan Book 2, Page 6 of the Penobscot County Registry of Deeds. Recorded in the Penobscot Registry of Deeds in Volume 4920, Page 5 on September 13, 1991. PART II TRANSMISSION LINES RIGHT-OF-WAY, THE HOULTON TO ISLAND FALLS LINE, SO CALLED A 44,000 volt transmission line in Aroostook County, Maine owned and operated by Maine Public Service Company from Houlton to Island Falls, a distance of approximately 27.85 miles, said Maine Public Service Company line being constructed for the most part on rights-of-way conveyed to Maine Public Service Company by the following deeds: Recorded Grantor Date Vol. Page Registry at: Emery W & Norma Nightingale 3/11/94 2662 47 Houlton Katahdin Forest Products 7/18/94 2704 294 Houlton Katahdin Development Corp 12/5/94 2746 346 Houlton Daniel E. Russell 3/14/94 2662 338 Houlton Est. of Chester A. Shorey 3/31/94 2667 282 Houlton Rodney V. Anderson 4/01/94 2668 80 Houlton Herbert C. Haynes, Inc. 3/24/94 2665 162 Houlton RIGHT-OF-WAY, AEI TRANSMISSION LINE, SO CALLED A 69,000 volt transmission line in Aroostook County, Maine owned and operated by Maine Public Service Company from AEI generating plant in Ashland to Maine Public Service substation in Ashland, a distance of approximately 2.69 miles, said Maine Public Service Company line being constructed for the most part on rights-of-way conveyed to Maine Public Service Company by the following deeds: Recorded Grantor Date Vol. Page Registry at: Myron Turner 8/04/92 2487 25-27 Houlton Francis Jimmo, Jr. & Gail Jimmo 8/04/92 2487 22-24 Houlton T. Robert Graham 8/04/92 2487 19-21 Houlton Roger Hews & Shirley M. Hews 8/17/92 2490 15-17 Houlton Ashland Water & Sewer Dist. 8/20/92 2490 318-320 Houlton RIGHT-OF-WAY, GNP CHIPPER, SO CALLED A 34,500 volt transmission line in Aroostook County, Maine owned and operated by Maine Public Service Company from GNP Plant in Portage to Maine Public Service substation in Portage, a distance of approximately .744 miles, said Maine Public Service Company line being constructed for the most part on rights-of-way conveyed to Maine Public Service Company by the following deeds: Recorded Grantor Date Vol. Page Registry at: Great Norther Paper Company 5/25/94 2686 302 Houlton RIGHT-OF-WAY, PRESQUE ISLE MALL, SO CALLED A 69,000 volt transmission line in Aroostook County, Maine owned and operated by Maine Public Service Company from Maysville Ave, Presque Isle to corner of Carmichael Street and Maysville Ave., a distance of approximately .289 miles, said Maine Public Service Company line being constructed for the most part on rights-of-way conveyed to Maine Public Service Company by the following deeds: Recorded Grantor Date Vol. Page Registry at: Maine Potato Growers 7/29/91 2381 108 Houlton New England Telephone Co. 3/05/92 2434 166 Houlton Widewater Aroostook Centre 3/16/94 2669 20-24 Houlton The foregoing rights-of-way are conveyed subject to reservations, conditions, restrictions, limitations and exceptions referred to or mentioned in the deeds above listed. CLAUSE II All and singular the lands, real estate, chattels real, interests in land, leaseholds, ways, rights-of-way, easements, servitudes, permits and licenses, lands under water, riparian rights, franchises, privileges, rights and interests, electric generating plants, power houses, dams, stations, electric transmission and distribution systems, substations, conduits, poles, wires, cables, office buildings, warehouses, garages, machine shops, and other buildings and structures, implements, meters, tools, and other apparatus, appurtenances and facilities materials and supplies and all other property of any nature appertaining to any of the plants, systems, business or operations of the Company, whether or not affixed to the realty, used in the operation of any of the premises or plants or systems or otherwise, which are now owned, or which may hereafter be owned or acquired by the Company, other than excepted property as hereinafter defined. CLAUSE III All corporate Federal, State, municipal and other permits, consents, licenses, bridge licenses, bridge rights, river permits, franchises, grants, privileges and immunities of every kind and description, now belonging to or which may hereafter be owned, held, possessed or enjoyed by the Company (other than excepted property as hereinafter defined) and all renewals, extensions, enlargements and modifications of any of them. CLAUSE IV Also all other property, real, personal or mixed, tangible or intangible (other than excepted property as hereinafter defined) of every kind, character and description and wheresoever situated, whether or not useful in the generation, manufacture, production, transportation, distribution, sale or supplying electricity now owned or which may hereafter be acquired by the Company, it being the intention hereof that all property, rights and franchises acquired by the Company after the date of the execution and delivery hereof (other than excepted property as hereinafter defined) shall be as fully embraced within and subjected to the lien of the Indenture as if such property were now owned by the Company and were specifically described herein and conveyed hereby. CLAUSE V Together with (other than excepted property as hereinafter defined) all and singular the plants, buildings, improvements, additions, tenements, hereditaments, easements, rights, privileges, licenses and franchises and all other appurtenances whatsoever belonging or in any wise appertaining to any of the property hereby mortgaged or pledged, or intended so to be, or any part thereof, and the reversion and reversion, remainder and remainders, and the rents, revenues, issues, earnings, income, products and profits thereof, and every part and parcel thereof, and all the estate, rights, title, interest, property, claim and demand of every nature whatsoever of the Company at law, in equity or otherwise howsoever, in, of and to such property and every part and parcel thereof. CLAUSE VI Also any and all property, real, personal or mixed, including excepted property, that may, from time to time hereafter, by delivery or by writing of any kind, for the purposes of the Indenture be in any wise subjected to the lien of the Indenture or be expressly conveyed, mortgaged, assigned, transferred, deposited and/or pledged by the Company, or by anyone in its behalf or with its consent, to and with the Trustee, which is hereby authorized to receive the same at any and all times as and for additional security and also, when and as provided in the Indenture, to the extent permitted by law. Such conveyance, mortgage, assignment, transfer, deposit and/or pledge or other creation of lien by the Company, or by anyone in its behalf, or with its consent, of or upon any property as and for additional security may be made subject to any reservations, limitations, conditions and provisions which shall be set forth in an instrument or agreement in writing executed by the Company or the person or corporation conveying, assigning, mortgaging, transferring, depositing and/or pledging the same and/or by the Trustee, respecting the use, management and disposition of the property so conveyed, assigned, mortgaged, transferred, deposited and/or pledged, or the proceeds thereof. CLAUSE VII There is however, expressly excepted and excluded from the lien and operation of the Indenture the following described property of the Company, herein sometimes referred to as "excepted property": (a) Any and all property expressly excepted and excluded from the Original Indenture and from the lien and operation thereof by Paragraph A of Clause XI of the Granting Clauses thereof and all property of the character expressly excepted or intended to be excepted and excluded by Paragraphs B through I of said Clause XI; and (b) All property which prior to the execution and delivery of this Third Supplemental Indenture has been released by the Trustee or otherwise disposed of by the Company free from the lien of the Indenture, in accordance with the provisions thereof. The Company may, however, pursuant to the provisions of Granting Clause VI above, subject to the lien and operation of the Indenture all or any part of the excepted property. TO HAVE AND TO HOLD the trust estate and all and singular the lands, properties, estates, rights, franchises, privileges and appurtenances hereby mortgaged, conveyed, pledged or assigned, or intended so to be, together with all the appurtenances thereto appertaining and the rents, issues and profits thereof, unto the Trustee and its successors in trust and to its assigns, forever: SUBJECT, HOWEVER, to the exceptions, reservations, restrictions, conditions, limitations, covenants and matters recited in Schedule A to the Original Indenture or otherwise recited in the Original Indenture, as modified and supplemented, and contained in all deeds and other instruments whereunder the Company has acquired any of the property now owned by it, and to permitted encumbrances as defined in Subsection B of Section 1.11 of the Original Indenture, and, with respect to any property which the Company may hereafter acquire, to all terms, conditions, agreements, covenants, exceptions and reservations expressed or provided in the deeds or other instruments, respectively, under any by virtue of which the Company shall hereafter acquire the same and to any liens thereon existing, and to any liens for unpaid portions of the purchase money placed thereon, at the time of acquisition; BUT IN TRUST, NEVERTHELESS, for the equal and proportionate use, benefit, security and protection of those who from time to time shall hold the Bonds authenticated and delivered under the Indenture and duly issued by the Company, without any discrimination, preference or priority of any one Bond over any other by reason of priority in the time of issue, sale or negotiation thereof or otherwise, except as provided in Section 12.28 of the Original Indenture, so that, subject to said Section 12.28, each and all of said Bonds shall have the same right, lien and privilege under the Indenture, and shall be equally secured hereby (except in so far as any sinking fund, replacement fund or other fund established in accordance with the provisions of the Indenture may afford additional security for the Bonds of any specific series) and shall have the same proportionate interest and share in the trust estate, with the same effect as if all of the Bonds had been issued, sold and negotiated simultaneously on the date of the delivery hereof; AND UPON THE TRUSTS, USES AND PURPOSES and subject to the covenants, agreements and conditions in the Indenture set forth and declared. ARTICLE TWO Bonds of the 2002 Series and Certain Provisions Relating Thereto Section 2.01. Terms of the Bonds of the 2002 Series. There shall be a series of Bonds, known as and entitled "Second Mortgage and Collateral Trust Bonds, Series Due 2002" (herein referred to as the "Bonds of the 2002 Series"), and the form thereof shall be substantially as hereinafter set forth in Section 2.02. The Bonds of the 2002 Series shall be issued to The Bank of New York, as Agent, to secure the obligations of the Company under a Letter of Credit and Reimbursement Agreement, dated as of June 1, 1996, among the Company, The Bank of New York ("BNY") and Fleet Bank of Maine ("Fleet") and The Bank of New York, as Agent (in such capacity, "BNY Agent"), and as Issuing Bank (in such capacity, "BNY Issuing Bank") (the "Reimbursement Agreement"), pursuant to which BNY Issuing Bank has issued its irrevocable, transferrable, direct- pay letter of credit (the "Letter of Credit") to support certain Maine Public Utility Financing Bank Public Utility Refunding Revenue Bonds, Series 1996 (Maine Public Service Company Project) (the "Revenue Bonds"). The aggregate principal amount of the Bonds of the 2002 Series which may be authenticated and delivered and outstanding under this Third Supplemental Indenture shall be limited to $15,875,000 except for duplicate Bonds, authenticated and delivered pursuant to Section 2.12 of the Original Indenture. The definitive Bonds of the 2002 Series shall be issued only as registered Bonds without coupons of the denomination of $1.00 and of any multiple thereof and shall be registered in the name of BNY Agent. The date of authentication on the original issuance of the Bonds of the 2002 Series shall be the date of commencement of the first interest period for such Bonds. All Bonds of the 2002 Series shall mature June 19, 2002, and shall bear interest at the Default Rate set forth in, and in accordance with, the Reimbursement Agreement until the payment of the principal thereof. Both principal of and interest on the Bonds of the 2002 Series will be paid in any coin or currency of the United States of America which at the time of payment is legal tender for the payment of public and private debts, at the principal office in the City of New York, New York, of the Trustee or, at the office of its successor as Trustee. The definitive Bonds of the 2002 Series may be issued in the form of Bonds engraved, printed or lithographed on steel engraved borders. Bonds of the 2002 Series may also be issued as temporary printed, lithographed or typewritten Bonds, and, so long as the registered holder of such Bonds does not request their exchange for Bonds in definitive form, the Company shall not be deemed to have unreasonably delayed the preparation, execution and delivery of definitive Bonds as called for by Section 2.08 of the Original Indenture. Every Bond of the 2002 Series shall be dated as provided in Section 2.05 of the Original Indenture except that upon original issuance of the Bonds of the 2002 Series, the Bonds of the 2002 Series shall be dated the date of authentication. The Bonds of the 2002 Series shall be nontransferable prior to maturity except upon the prior written consent of the Company or to effect transfer to any successor or assignee of BNY Agent if and to the extent that BNY Agent shall have assigned its rights under the Reimbursement Agreement, any such transfer to be made at the principal corporate trust office of the Trustee in the City of New York, New York, upon surrender and cancellation of such Bonds of the 2002 Series, accompanied by a written instrument of transfer in a form approved by the Company, duly executed by the registered owner of such Bonds of the 2002 Series or by his duly authorized attorney, and thereupon a new Bond of the 2002 Series, for a like principal amount, will be issued to the successor or assignee of BNY Agent, in exchange therefor. The Trustee hereunder shall, by virtue of its office as such Trustee, be the registrar and transfer agent of the Company for the purpose of registering and transferring Bonds of the 2002 Series. Section 2.02. Form of Bonds of the 2002 Series. The text of the Bonds of the 2002 Series and the Trustee's authentication certificate to be executed on the Bonds of said series, shall be in substantially the following forms, respectively. [FORM OF FACE OF BOND OF THE 2002 SERIES] No. R $_____________ MAINE PUBLIC SERVICE COMPANY Second Mortgage and Collateral Trust Bond, Series due 2002 Due June 19, 2002 MAINE PUBLIC SERVICE COMPANY, a Maine corporation (hereinafter sometimes called the "Company"), for value received, hereby promises to pay to ________ ___________________________________ or registered assigns,___________________ ________________ Dollars on June 19, 2002, and to pay to the registered owner hereof interest thereon from the date hereof at the Default Rate set forth in, and in accordance with, the Reimbursement Agreement referred to below until payment of the principal hereof. The Bonds of the 2002 Series, including this bond, are issued to secure the obligations of the Company under a Letter of Credit and Reimbursement Agreement, dated as of June 1, 1996 (the "Reimbursement Agreement") among the Company, The Bank of New York ("BNY") and Fleet Bank of Maine ("Fleet") and The Bank of New York, as Agent (in such capacity, "BNY Agent") and as Issuing Bank (in such capacity, "BNY Issuing Bank"), pursuant to which BNY Issuing Bank has issued its irrevocable, transferrable, direct-pay letter of credit (the "Letter of Credit") to support certain Maine Public Utility Financing Bank Public Utility Refunding Revenue Bonds, Series 1996 (Maine Public Service Company Project) (the "Revenue Bonds"). The obligation of the Company to make any payment of interest on the Bonds of the 2002 Series, when such interest shall be due and payable, shall be deemed to be, and shall be, satisfied and discharged if the Company shall have paid all interest under the Reimbursement Agreement then due and payable. The obligation of the Company to make payments with respect to the principal of Bond of the 2002 Series at any time shall be deemed to be, and shall be, satisfied and discharged if, at any time that such payment of principal shall be due, the Company shall have paid for all amounts then due pursuant to Sections 2.03 and 2.04 of the Reimbursement Agreement. The principal of and interest on this bond will be paid in any coin or currency of the United States of America which at the time of payment is legal tender for the payment of public and private debts at the principal office in the City of New York, New York, of the Trustee under the Indenture mentioned on the reverse hereof. Interest on this bond will be payable at the Corporate Trust office in the City of New York, New York, of the Trustee provided, however, that interest on this bond shall, unless otherwise directed by the registered holder hereof, be paid by check payable to the order of the registered holder entitled thereto and mailed by the Trustee by first class mail, postage prepaid, to such holder at his address as shown on the bond register for the bonds in this series. This bond shall not become or be valid or obligatory for any purpose until the authentication certificate hereon shall have been signed by the Trustee. The provisions of this bond are continued on the reverse hereof and such continued provisions shall for all purposes have the same effect as though fully set forth at this place. IN WITNESS WHEREOF, MAINE PUBLIC SERVICE COMPANY has caused these presents to be executed in its name and behalf of its President or one of its Vice Presidents and its corporate seal or a facsimile thereof to be affixed hereto and attested by its Secretary or one of its Assistant Secretaries, all as of __________, 19__. MAINE PUBLIC SERVICE COMPANY By: ___________________________________ Vice President Attest: __________________________________________ Secretary [FORM OF REVERSE OF BOND OF THE 2002 SERIES] This bond constitutes the entire series designated as Bonds of the 2002 Series, of an authorized issue of bonds of the Company, known as Second Mortgage and Collateral Trust Bonds, issued under and secured by an Indenture of Second Mortgage and Deed of Trust dated as of October 1, 1985, duly executed and delivered by the Company to IBJ Schroder Bank & Trust Company, as Trustee, to which Indenture of Second Mortgage and Deed of Trust as supplemented and modified by indentures supplemental thereto, including a Third Supplemental Indenture dated as of June 1, 1996, duly executed by the Company to said Trustee and all indentures supplemental thereto (herein sometimes collectively called the "Indenture") reference is hereby made for a description of the property mortgaged and pledged as security for said bonds, the nature and extent of the security, and the rights, duties and immunities thereunder of the Trustee, the rights of the holders of said bonds and of the Trustee and of the Company in respect of such security, and the terms upon which said bonds may be issued thereunder. This bond shall be subject to redemption as a whole or in part, at any time, at the option of the Company prior to maturity upon payment of the principal amount thereof in the manner provided for the Indenture. In the event that the Revenue Bonds outstanding under the Indenture of Trust, dated as of June 1, 1996, between the Maine Public Utility Financing Bank and Fleet National Bank (the "Revenue Bond Indenture") shall become immediately due and payable pursuant to Section 9.01(e) or 9.01(f) of the Revenue Bond Indenture, this bond shall be redeemed by the Company, on the date such Revenue Bonds shall have become immediately due and payable, at the principal amount hereof plus unpaid interest accrued to the date of redemption. Any redemption pursuant to the preceding paragraph shall be made upon prior notice given by first class mail, postage prepaid, as provided in the Indenture to the holders of record of each bond affected not less than thirty days nor more than ninety days prior to the redemption date and subject to all other conditions and provisions of the Indenture. If this bond is duly called for redemption and payment duly provided for as specified in the Indenture, this bond shall cease to be entitled to the lien of the Indenture from and after the date payment is so provided for and shall cease to bear interest from and after the redemption date. The Company and the Trustee and any paying agent may deem and treat the person in whose name this bond shall be registered upon the bond register for the bonds of this series as the absolute owner of such bond for the purpose of receiving payment of or on account of the principal of and interest on this bond and for all other purposes, whether or not this bond be overdue; and all such payments so made to such registered holder or upon his order shall be valid and effectual to satisfy and discharge the liability upon this bond to the extent of the sum or sums so paid and neither the Company nor the Trustee nor any paying agent shall be affected by any notice to the contrary. This bond is nontransferable prior to its maturity except upon the prior written consent of the Company or to effect transfer to any successor or assignee of BNY Agent if and to the extent that BNY Agent shall have assigned its rights under the Reimbursement Agreement, any such transfer to be made at the principal corporate trust office of the Trustee in the City of New York, New York, upon surrender and cancellation of this bond, accompanied by a written instrument of transfer in a form approved by the Company, duly executed by the registered owner of this bond or by his duly authorized attorney, and thereupon a new bond of this series, for a like principal amount, will be issued to the successor or assignee of BNY Agent in exchange therefor, as provided in the Indenture. If a default as defined in the Indenture shall occur, the principal of this bond may become or be declared due and payable before maturity in the manner and with the effect provided in the Indenture. The holders, however, of certain specified percentages of the bonds at the time outstanding, including in certain cases specific percentages of bonds of particular series, may in the cases, to the extent and under the conditions provided in the Indenture, waive past defaults thereunder and the consequences of such defaults. No recourse shall be had for the payment of the principal of or the interest on this bond, or for any claim based hereon, or otherwise in respect hereof or of the Indenture, against any incorporator, stockholder, director or officer, past, present or future, as such, of the Company or of any predecessor or successor corporation, either directly or through the Company or such predecessor or successor corporation, under any constitution or statute or rule of law, or by the enforcement of any assessment or penalty, or otherwise, all such liability of incorporators, stockholders, directors and officers, as such, being waived and released by the holder and owner hereof by the acceptance of this bond and as provided in the Indenture. This bond shall not become or be valid or obligatory for any purpose until the authentication certificate hereon shall have been manually signed by the Trustee. [FORM OF TRUSTEE'S AUTHENTICATION CERTIFICATE FOR BONDS OF THE 2002 SERIES] This is the bond, of the series designated therein, described in the within mentioned Indenture. IBJ SCHRODER BANK & TRUST COMPANY As Trustee, By: __________________________________ Authorized Officer Section 2.03. Discharge of Company's Obligation for Payment. The obligation of the Company to make any payment of interest on Bonds of the 2002 Series, when such interest shall be due and payable, shall be deemed to be, and shall be, satisfied and discharged if the Company shall have paid all interest under the Reimbursement Agreement then due and payable. The obligation of the Company to make payments with respect to the principal of Bonds of the 2002 Series at any time shall be deemed to be, and shall be, satisfied and discharged if, at any time that any such payment of principal shall be due, the Company shall have paid BNY Agent for all amounts then due pursuant to Sections 2.03 and 2.04 of the Reimbursement Agreement. The Trustee may conclusively presume that at any particular time, the obligations of the Company to make payments with respect to the principal of and interest on the Bonds of the 2002 Series shall have been satisfied and discharged up until such time unless and until the Trustee shall have received a notice as described in Section 12.01(k) of the Indenture. Whenever all of the obligations of the Company to BNY Agent pursuant to the Reimbursement Agreement shall have been satisfied and the Letter of Credit shall have been terminated, the aggregate principal amount of all of the Bonds of the 2002 Series shall be surrendered by BNY Agent to the Trustee for cancellation, and upon such surrender shall be deemed fully paid. Section 2.04. Redemption Provisions for the Bonds of the 2002 Series. The Bonds of the 2002 Series shall be subject to redemption as a whole or in part, at any time, at the option of the Company prior to maturity upon payment of the principal amount thereof. In the event that the Revenue Bonds outstanding under the Indenture of Trust, dated as of June 1, 1996, between the Maine Public Utility Financing Bank and Fleet National Bank (the "Revenue Bond Indenture") shall become immediately due and payable pursuant to Section 9.01(e) or 9.01(f) of the Revenue Bond Indenture, all Bonds of the 2002 Series then outstanding shall be redeemed by the Company, on the date such Revenue Bonds shall have become immediately due and payable, at the principal amount of the Bonds of the 2002 Series. The Trustee may conclusively presume that no redemption of Bonds of the 2002 Series is required pursuant to this Section 2.04 unless and until the Trustee shall have received a written notice from BNY Agent stating that: (a) BNY Issuing Bank has paid a drawing under the Letter of Credit made by the trustee under the Revenue Bond Indenture to pay interest on or principal of the Revenue Bonds and that the Company has not reimbursed BNY Agent for such drawing; or (b) an "Event of Default" under the Reimbursement Agreement has occurred and is continuing. Said notice shall also contain a waiver of notice of such redemption by BNY Agent as holder of all of the Bonds of the 2002 Series then outstanding. Any redemption pursuant to this Section 2.04 shall be made, together in any case with interest accrued thereon to the redemption date, upon not less than 30 days' nor more than 90 days' notice given by first class mail, postage prepaid, to the holder of record at the date of such notice of each Bond of the 2002 Series at his address as shown on the Bond register for Bonds of the 2002 Series. Such notice shall be sufficiently given if deposited in the United States mail within such period. Neither the failure to mail such notice, nor any defect in any notice so mailed to any such holder, shall affect the sufficiency of such notice with respect to other holders. No notice of redemption need be given if the holders of all Bonds of the 2002 Series called for redemption waive notice thereof in writing and such waiver is filed with the Trustee. Section 2.05 Duration of Effectiveness of Article Two. This Article shall be of force and effect only so long as any Bonds of the 2002 Series are outstanding. ARTICLE THREE Modification of the Indenture Section 3.01. Clause (k) of Section 12.01 of the Indenture is hereby amended and restated in its entirety to read as follows: "(k) so long as any of the Bonds of the 2002 Series are outstanding, upon receipt by the Trustees of a notice from the holder of the Bonds of the 2002 Series that an event of default has occurred under the Reimbursement Agreement and is continuing;" Section 3.02. Duration of Effectiveness of Article Three. This Article shall be of force and effect only so long as any Bonds of the 2002 Series are outstanding. ARTICLE FOUR Authentication and Delivery of Bonds of the 2002 Series Section 4.01. Upon the execution and delivery of this Third Supplemental Indenture, Bonds of the 2002 Series in the aggregate amount of Fifteen Million Eight Hundred Seventy-Five Thousand Dollars ($15,875,000) may forthwith, or from time to time thereafter, and upon compliance by the Company with the provisions of Article Five of the Indenture, be executed by the Company and delivered to the Trustee and shall thereupon be authenticated and delivered by the Trustee to or upon the written order of the Company. ARTICLE FIVE Section 5.01. The Company may enter into an agreement with the holder of any registered Bond without coupons of any series providing for the payment to such holder of the principal of and the premium, if any, and interest on such Bond or any part thereof at a place other than the offices or agencies therein specified, and for the making of notation, if any, as to the principal payments on such Bond by such holder or by an agent of the Company or of the Trustee. The Trustee is authorized to approve any such agreement, and shall not be liable for any act or omission to act on the part of the Company, any such holder or any agent of the Company in connection with any such agreement. Section 5.02. This Third Supplemental Indenture is executed and shall be construed as an indenture supplemental to the Original Indenture, as amended and supplemented, and shall form a part thereof, and, except as hereby supplemented, the Original Indenture, as amended and supplemented, is hereby ratified, approved and confirmed. Section 5.03. The recitals contained in this Third Supplemental Indenture are made by the Company and not by the Trustee and all of the provisions contained in the Original Indenture, as amended and supplemented, in respect of the rights, privileges, immunities, powers and duties of the Trustee shall, except as hereinabove modified, be applicable in respect hereof as fully and with like effect as if set forth herein in full. Section 5.04. Nothing in this Third Supplemental Indenture contained shall be deemed to abrogate, modify or contravene any provisions of the Original Indenture, as amended and supplemented, required to be included therein by any of the provisions of Section 310 to 318, inclusive, of the Trust Indenture Act of 1939, it being the intention hereof that said provisions of the Original Indenture, as amended and supplemented, shall continue in full force and effect. Unless otherwise indicated, the terms used in this Third Supplemental Indenture are intended to have the meanings given to such terms in the Original Indenture, as amended and supplemented. Section 5.05. Nothing in this Third Supplemental Indenture expressed or implied is intended or shall be construed to give to any person other than the Company, the Trustee, and the holders of the Bonds issued and to be issued under the Indenture, any legal or equitable right, remedy or claim under or in respect of the Original Indenture, as amended and supplemented, or this Third Supplemental Indenture, or under any covenant, condition or provisions therein or herein or in the Bonds contained; and all such covenants, conditions and provisions are and shall be held to be for the sole and exclusive benefit of the Company, the Trustee and the holders of the Bonds issued and to be issued under the Indenture. Section 5.06. The titles of Articles and any wording on the cover of this Third Supplemental Indenture are inserted for convenience only. Section 5.07. All the covenants, stipulations, promises and agreements in this Third Supplemental Indenture contained made by or on behalf of the Company or of the Trustee shall inure to and bind their respective successors and assigns. Section 5.08. Although this Third Supplemental Indenture is dated for convenience and for the purpose of reference as of June 1, 1996, the actual date or dates of execution by the Company and by the Trustee are as indicated by their respective acknowledgments hereto annexed. Section 5.09. In order to facilitate the recording or filing of this Third Supplemental Indenture, the same may be simultaneously executed in several counterparts, each of which shall be deemed to be an original, and such counterparts shall together constitute but one and the same instrument. IN WITNESS WHEREOF, MAINE PUBLIC SERVICE COMPANY has caused this Third Supplemental Indenture to be signed in its corporate name and behalf by its President or one of its Vice Presidents and its corporate seal to be hereunto affixed and attested by its Secretary, or one of its Assistant Secretaries; and IBJ SCHRODER BANK & TRUST COMPANY in token of its acceptance of the trust hereby created has caused this Third Supplemental Indenture to be signed in its corporate name and behalf by its President or one of its Vice Presidents or one of its Second Vice Presidents and its corporate seal to be hereunto affixed and attested by its Assistant Secretary or one of its Trust Officers, all as of the day and year first above written. MAINE PUBLIC SERVICE COMPANY /s/ Larry LaPlante Name: Larry LaPlante Title: Vice President CORPORATE SEAL Attest: /s/ Stephen A. Johnson Name: Stephen A. Johnson Title: Secretary Signed, sealed and delivered by MAINE PUBLIC SERVICE COMPANY in the presence of: /s/ Marilyn L. Bouchard Marilyn L. Bouchard /s/ Stephen J. Gallant Stephen J. Gallant IBJ SCHRODER BANK & TRUST COMPANY /s/ Max Volmar Name:Max Volmar Title:Vice President CORPORATE SEAL Attest: /s/ Kerry A. Monaghan Name: Kerry A. Monaghan Title: Assistant Secretary Signed, sealed and delivered by IBJ SCHRODER BANK & TRUST COMPANY in the presence of: /s/ Barbara McCluskey Barbara McCluskey /s/ Susan Lavelle Susan Lavelle STATE OF MAINE ) : ss.: COUNTY OF AROOSTOOK ) June 11, 1996 Then personally appeared the above-named Larry LaPlante Vice President of Maine Public Service Company and acknowledged the foregoing instrument to be his free act and deed in his said capacity and the free act and deed of said corporation. Before me, /s/ Alice E. Shepard Notary Public Alice E. Shepard Notary Public, Maine My Commission Expires October 29, 2000 NOTARIAL SEAL STATE OF NEW YORK ) : ss.: COUNTY OF RICHMOND ) June 14, 1996 Then personally appeared the above-named Max Volmar, a Vice President of IBJ Schroder Bank & Trust Company and acknowledged the foregoing instrument to be his free act and deed in his said capacity and the free act and deed of said corporation. Before me, /s/ Norma Pacifico Notary Public My Commission expires: August 31, 1996 Norma Pacifico Notary Public, State of New York No. 43-5001265 Qualified in Richmond County Certificate filed in Manhattan County Commission Expires August 31st, 1996 NOTARIAL SEAL Exhibit 10(u) AMENDMENT NO. 3 to the REVOLVING CREDIT AGREEMENT AMENDMENT NO. 3, dated as of October 8, 1995, 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, and Amendment No. 2, dated as of May 11, 1992 (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 set forth herein. Accordingly, the parties hereto agree that, on the conditions and subject to the limitations contained herein, the Agreement be and the same hereby is amended as follows: 1. Paragraph 2.9 is amended by deleting said paragraph in its entirety and substituting therefor the following: 2.9 Commitment Fee. The Company agrees to pay to the Banks a fee (the "Commitment Fee") equal to 3/8 of 1% per annum (computed on the basis of a 360 day year for the actual number of days involved) on the average daily unused amount of the Aggregate Commitments (provided, however, that Credit B Loans will not be construed as usage in calculating the Commitment fee) for the period from and including October 8, 1995 until the expiration or termination of the Aggregate Commitments. The Commitment Fee shall be payable quarterly in arrears and prorated on the last day of each March, June, September and December, commencing on the first such day following the Effective Date. Payment of the Commitment Fee shall be made to the Agent and, upon receipt thereof, the Agent shall promptly remit to each Bank its pro rata share thereof according to the Aggregate Commitments. 2. Paragraph 11 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, as Agent One Wall Street New York, New York 10286 Attention: John W. Hall, Vice President Shawmut Bank of Boston One Federal Street Boston, Massachusetts 02211 Attention: John Rafferty, Director Fleet Bank of Maine 80 Exchange Street P.O. Box 923 Bangor, Maine 04402-0923 Attention: Neil C. Buitenhuys, Vice President 3. Except as amended hereby, the Agreement shall remain in full force and effect. 4. 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. 5. 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. 6. 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: /s/ L. E. LaPlante Title: Vice President, Finance and Treasurer THE BANK OF NEW YORK, as Agent By: /s/ John W. Hall Title: Vice President Execution of the foregoing Amendment No. 3 by the Agent is hereby consented to: THE BANK OF NEW YORK By: /s/ John W. Hall Title: Vice President SHAWMUT BANK, N.A. By: /s/ J. P. Rafferty Title: Director FLEET BANK OF MAINE By: /s/ Neil C. Buitenhuys Title: Vice President Exhibit 13 (Front Outside Cover) Maine Public Service Company 1996 Annual Report We put a lot of energy into Northern Maine (Front Inside Cover) Maine Public Service Company (Graphic - Map of Territory Served) 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, nuclear, and oil-fueled facilities, as well as an independent wood-burning cogenerator. 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 Front Inside Cover President's Letter 1-2 Analysis of Financial Condition and Review of Operations - 1996 3-11 Shareholder Information 11 Five-Year Summary of Selected Financial Data 12 Independent Auditors' Report 13 Financial Statements and Notes 14-27 Consolidated Financial Statistics 28-29 Consolidated Operating Statistics 30-31 Directors 32 Executive Officers and Stock Back Cover Transfer Information (Photo) Irwin F. Porter, age 78, died September 4, 1996, after a long illness. His 44-year career was dedicated to banking in Presque Isle, Maine. He served over twenty-one years, from 1973 to 1994, on Maine Public Service Company's Board of Directors. 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@agate.net (Page 1) President's Letter to our Shareholders and Employees The year 1996 was disappointing for your Company with earnings per share of $1.31, compared to a net loss of $3.29 per share in 1995. As you may recall, the Company had non-cash write-offs of $8.3 million in 1995, as part of the four-year rate stabilization plan agreement with the Maine Public Utilities Commission (MPUC). Absent these write-offs, the 1995 earnings would have been $1.87 per share. The lower performance in 1996 can be attributed to the loss of Houlton Water Company as a customer, along with the erratic performance of the Maine Yankee Nuclear Plant. Retail energy sales were the same as last year with our service territory continuing to feel the economic impact of the 1994 closure of Loring Air Force Base, as well as a very mild December. Although the first year of our rate stabilization plan increased rates 4.4% in 1996, the elimination of the fuel adjustment clause caused the Company to absorb replacement power costs for the three months of unscheduled outages at Maine Yankee, along with the scheduled annual 5% increase in our Wheelabrator-Sherman contract (currently 12.7 cents/KWH). Maine Yankee had been operating at 90 percent of capacity since early 1996 pending resolution of issues relating to an investigation initiated by the Nuclear Regulatory Commission. Since December 6, Maine Yankee has been out of service and, as of this writing, it is unlikely that it will return to service until mid-summer or perhaps later. Replacement power costs, along with increased capacity costs, have financially challenged the Company. The Maine Yankee situation and the burdensome Wheelabrator-Sherman contract have, and will continue to have, a negative impact on earnings and cash flows. We therefore have reduced our annual dividend from $1.84 to $1.00, effective April 1, 1997, in order to conserve cash. In addition, the continued shutdown of Maine Yankee is likely to place us in default of coverage tests under our debt instruments with our banks. We are negotiating with our banks to restructure our debt agreements; have requested a contract restructuring with Wheelabrator-Sherman; and may be filing for rate relief with the MPUC. It should be noted that we have been unsuccessful in contract restructuring efforts with Wheelabrator-Sherman over the last three years. The MPUC issued its report and recommended plan for Electric Utility Industry Restructuring on December 31, 1996. Under the MPUC recommendations, retail competition would begin January 1, 2000 and generation would not be subject to economic regulation by the MPUC. Under the proposal, your Company will not be required to sell its generating assets; however, if it decides to retain its generating assets, it must create a separate generating subsidiary. Our transmission and distribution businesses will continue to be regulated, transmission by the Federal Energy Regulatory Commission (FERC) and distribution by the MPUC. Stranded investment is a major element of restructuring. Stranded investment affects your Company with regard to its power contract with Wheelabrator, the excess of the contract price over market price, and the collection of the Seabrook regulatory asset currently scheduled to be amortized and collected through 2016. Other stranded investment issues are associated with the values placed on generating assets such as Wyman, Maine Yankee, and our Tinker Hydro facility located in Canada. These generating (Page 2) facilities could be subject to stranded investment if their market value is different than their book value. We will certainly contest anything other than full recovery of stranded investment for your Company. The MPUC restructuring proposal is awaiting action by the State Legislature whereby they can approve, modify, or reject the proposal. It is difficult to predict the outcome of this proposal. On a more positive note, your Company has been aggressive in the promotion of economic development. We hired a Director of Economic Development in October, 1996 and have committed a budget to promote economic development in our service area. Recently, a hardwood flooring firm located at the Loring Commerce Centre (formerly Loring Air Force Base) and, although not a large employer, it is the first major private sector entity to make a long-term commitment to the former Air Base. We are hopeful that this will be the start of further economic activity at Loring. We also are pleased to announce that five of our largest industrial customers are under contract through the year 2000. Although we had to offer discounts to secure these contracts, we have eliminated the risk of losing these major customers as we prepare for customer choice and competition. As we go forward, the Company continues to position itself for competition. A very critical asset has been Maine Yankee, which has supplied approximately 40% of our requirements over the years at a very low cost. A permanent loss of Maine Yankee would create a serious financial hardship for your Company and may require rate increases that could affect our ability to compete. Another critical issue in preparation for competition is whether your Company will continue to be in the generation business or will only market power and not produce it. We continue to look at investments in non-regulated services to determine which are best suited for your Company. In 1996, we reorganized our corporate structure into three sections: a wholesale sector, retail sector, and administration. We continue to look at our organization and believe that the recent changes have us well positioned as we move forward, especially in the transmission and distribution functions, as well as power supply. I would like to thank you, our shareholders, for the confidence you have placed in us to lead the Company during this transition period to deregulation. Although we are faced with uncertainty as we progress, you have my commitment that we will be responsive to you, our shareholders, our customers, and our employees. I would like to thank our dedicated workforce for their efforts over the year as we continue to accomplish more with fewer employees. Sincerely, /s/ Paul R. Cariani Paul R. Cariani President and CEO (Page 3) Analysis of Financial Condition and Review of Operations - 1996 RESULTS OF OPERATIONS Operating Revenues and Energy Sales Consolidated operating revenues and MWH sales for the years 1996, 1995, and 1994 are as follows: Consolidated Operating Revenues and Megawatt Hours Sold (Dollars in Thousands) 1996 1995 1994 Dollars MWH Dollars MWH Dollars MWH Residential $19,961 169,298 $19,081 168,640 $19,647 175,685 Commercial & Industrial - Large 10,112 134,588 9,437 128,478 9,225 127,327 Commercial & Industrial - Small 16,420 163,804 15,723 165,914 15,614 167,485 Other Retail 1,523 13,166 1,701 14,859 2,895 31,736 Total Retail 48,016 480,856 45,942 477,891 47,381 502,233 Sales for Resale 2,096 55,958 6,955 123,793 6,946 119,450 Total Primary 50,112 536,814 52,897 601,684 54,327 621,683 Secondary Sales 4,797 229,141 619 22,115 1,535 88,241 Total Sales of Electricity 54,909 765,955 53,516 623,799 55,862 709,924 Other 2,355 1,763 2,506 Total Operating Revenue $57,264 $55,279 $58,368 Primary sales for 1996 were 536,814 MWH, approximately 10.8% lower than sales of 601,684 MWH in 1995 and 13.7% lower than sales of 621,683 MWH in 1994. 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 principal reason for the primary sales decrease. In 1995, HWC, the Company's largest customer, represented 11.1% of consolidated MWH sales and 8.4% of consolidated operating revenues. Sales for resale were higher in 1995 than 1994 because of increased sales to HWC. Retail sales were 480,856 MWH in 1996, an increase of 2,965 MWH, (0.6%) over 1995 sales reflecting increased sales to two large industrial customers: J. Paul Levesque & Sons and McCain Foods. Compared to 1994, retail sales decreased 21,377 MWH, (4.3%) in 1996 because of the closure of Loring Air Force Base, which also impacted residential and small commercial and industrial sales. During 1996, the Company entered long-term power contracts with two of its largest customers. The price under these contracts are lower than permitted under the Company's standard rates, but obligates them to purchase all of their electrical requirements through the year 2000. One additional customer has signed a similar agreement that must be approved by the Maine Public Utilities Commission (MPUC), while two others have verbally accepted the Company's offers. Secondary sales for 1996 of $4,797,000 were $4,178,000 and $3,262,000 more than 1995 and 1994, respectively. 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 Company's Maine Yankee entitlement was sold in 1996 and 1994, during periods of surplus capacity, but not in 1995, due to the year-long resleeving shutdown as further discussed in the "Maine Yankee" section of this Annual Report. The MPUC has jurisdiction over retail rates. As discussed in the "Regulatory Proceedings - Four-Year Rate Plan Approved" section of this Annual Report, the MPUC approved a four-year rate plan effective January 1, 1996. The plan allows for annual increases in retail rates and eliminates the fuel clause. Prior to the four-year rate plan, the Company had not sought a base rate increase since November 1, 1992. (Page 4) 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 126.5% of normal production levels in 1996 and provided 21.1% of the Company's energy requirements. In 1995, hydro production was 90.8% of normal and provided 18.3% of the Company's energy needs. Hydro production in 1994 was 88.9% of normal and accounted for 15.8% of the Company's energy requirements. The availability of low cost hydro, at $17.33 per megawatt hour in 1996, reduces the need for more expensive sources of energy. As more fully explained in the "Maine Yankee" section of this Annual Report, Maine Yankee returned to service in January of 1996 following a year-long outage. During 1996, Maine Yankee was restricted to 90% of rated capacity and was out of service a total of 13 weeks but was able to provide 31.1% of the Company's energy requirements compared to only 1.5% in 1995 and 43.3% in 1994. Maine Yankee operated at full capacity in 1994 with the exception of an unscheduled four-week outage beginning in mid-July. (Chart) Electric Output By Sources (Percent) 1992 1993 1994 1995 1996 Oil 4.5 3.6 2.4 3.6 1.2 Cogeneration 18.2 16.7 16.8 19.1 16.1 Purchases 23.0 21.8 21.7 57.5 30.5 Nuclear 36.3 37.9 43.3 1.5 31.1 Hydro 18.0 20.0 15.8 18.3 21.1 On December 6, 1996, Maine Yankee was again taken out of service to address concerns regarding cabling issues. The nuclear plant is not expected to return to service until the Summer of 1997. The Company has been incurring replacement power costs of approximately $170,000 per week while the Plant has been out of service. The Company purchases economical replacement energy from various sources, including NB Power, Bangor Hydro-Electric, and Central Maine Power on a competitive basis. These purchases accounted for 30.5% of the Company's energy supply in 1996, compared to 57.5% and 21.7% in 1995 and 1994, respectively. The larger than normal energy purchases in 1995 reflect the loss of Maine Yankee production. The Company's oil-fired generating facilities provided 1.2% of the Company's requirements in 1996, compared to 3.6% in 1995 and 2.4% in 1994. In 1986, under an agreement ordered by the Maine Public Utilities Commission that may be renewed by either party in 2000, the Company began purchasing the output from an 18-megawatt wood-burning independent power producer, currently owned by Wheelabrator-Sherman. The mandated purchases from this facility represented 16.1% of the Company's energy needs in 1996, compared to 19.1% and 16.8% in 1995 and 1994, respectively. Operating Expenses For the three-year period 1994-1996, purchased power expenses are as follows: (Dollars in Thousands) 1996 1995 1994 Wheelabrator-Sherman $15,593 $14,507 $13,932 Maine Yankee 10,185 7,972 9,645 NB Power 3,498 9,091 3,841 System Purchases 2,544 408 346 Total $31,820 $31,978 $27,764 The increases in Wheelabrator-Sherman expenses reflect an annual 5% contractual price increase and increased generation in 1996 due to favorable operating conditions. For 1996, 1995, and 1994, these mandated purchases from Wheelabrator-Sherman represented 49.0%; 45.4%; and 50.2%; respectively, of total purchased power expenses. As more fully explained in the "Maine Yankee" section of this Annual Report, Maine Yankee was down for 1995 to resleeve the steam generator tubes and for a scheduled refueling and maintenance outage. During 1996, Maine Yankee was off-line for a total of approximately thirteen weeks to address several issues. The facility has not operated since December 6, 1996 and is not expected to return to service until the summer of 1997 at the earliest. Maine Yankee had a one-month unscheduled outage for repairs in 1994. For ratemaking, the Company normalizes refueling and maintenance expenses due to scheduled refuelings over the refueling cycle. Unscheduled outages are charged to expense as incurred. As part of its rate plan approved by the Maine Public Utilities Commission, the Company's $1.3 million share of the 1995 steam generator tube resleeving was deferred in 1995 and will be collected in rates and expensed over five years beginning in 1996. For 1995, after considering the deferral of the resleeving expenses, Maine Yankee's fuel and capacity expenses were well below normal, as resources were used to complete the resleeving project. For 1996, the resleeving amortization, as well as additional expenses to address issues found during the previously mentioned outages, were the principal reasons for the increase in expenses. The Company purchased Maine Yankee replacement power principally from NB Power. While 1996 and 1994 purchases were similar, purchases in 1995 were $5,593,000 higher because of the extended Maine Yankee outage. System purchases in 1996 increased by $2,136,000 compared to 1995 due to increased power marketing activities, as discussed in the "Operating Revenues and Energy Sales" section of this Annual Report. (Page 5) Other operation and maintenance expenses for the three-year period are as follows: (Dollars in Thousands) 1996 1995 1994 Generation Fuel Expense $ 387 $ 824 $ 602 Other 1,571 2,031 2,096 1,958 2,855 2,698 Deferred Fuel (1,375) (4,937) (744) Fuel Expense Write-off - 3,500 - Transmission and Distribution 4,228 3,668 4,103 Customer Accounting and General Administrative 7,629 6,740 6,669 Total $12,440 $11,826 $12,726 Fuel expenses for generation decreased by $437,000 in 1996, as compared to 1995, because of Maine Yankee's availability in 1996 which displaced oil-fired generation. Other generation expenses decreased by $460,000, reflecting the lay-up of the Caribou Steam Plant as of January 1996 due to the loss of two customers, Loring Air Force Base and Houlton Water Company. The Plant is projected to remain inactive for a minimum of five years. As more fully discussed in the "Regulatory Proceedings -- Four-Year Rate Plan Approved" section of this Annual Report, the fuel clause adjustment was eliminated with the four-year rate plan effective on January 1, 1996 with the exception of the annual Wheelabrator-Sherman deferral of fuel expenses. Deferred fuel expense, a component of other operation and maintenance expenses, was a negative $1,375,000 in 1996, compared to a negative $4,937,000 in 1995 and a negative $744,000 in 1994. Negative deferred fuel indicates that current fuel costs have exceeded fuel revenues and have been deferred to a period when these costs will be collected. As part of the 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 in 1995 under the previous fuel clause. For 1996, transmission and distribution expenses were $560,000 more than 1995 reflecting increased wheeling costs related to increased power marketing activities and additional tree trimming. Customer accounting and general and administrative expenses increased by $889,000 in 1996 reflecting $402,000 in expenses related to an early retirement program in March 1996 and rate plan treatment of postretirement medical expenses of $106,000. Maine Yankee The Company owns 5% of the Common Stock of Maine Yankee, which operates an 860 MW nuclear power plant (the Plant) in Wiscasset, Maine. In 1996, Maine Yankee provided approximately 31.1% of the Company's energy requirements. In early February of 1995, during a scheduled refueling-and-maintenance shutdown, Maine Yankee detected an increased rate of degradation of the Plant's 17,000 steam generator tubes in excess of the number expected and started evaluating several courses of action. Maine Yankee could not resume operations until the necessary repairs had been made. Maine Yankee repaired the tubes by inserting and welding short reinforcing sleeves of an improved material in almost all of the steam generator tubes. The sleeving of the steam generator tubes was not completed until mid-December of 1995, at a cost of approximately $27 million, with the Company's share being approximately $1.3 million. During 1995, while Maine Yankee was out of service, the Company incurred additional replacement power costs of approximately $5.7 million. As more fully explained in the "Regulatory Proceeding - Four-Year Rate Plan Approved" section of this Annual Report, in late 1995 the Maine Public Utilities Commission approved a multi-year rate plan for the Company. As an element of the rate plan, the Company eliminated the fuel adjustment clause except for the cost of power purchased from the Wheelabrator-Sherman Energy Company, an independent power producer. As part of the rate plan, $2.1 million, net of income taxes, of the replacement power costs associated with the Maine Yankee outage was written off in 1995, $300,000, net of income taxes, will be collected in rates and amortized over the four-year rate plan period, and an estimated $1.3 million, net of income taxes, will be deferred until 2000, when rate recovery will be provided. The rate plan also includes a mechanism to handle similar unexpected Maine Yankee outages during the rate plan period. In addition, the rate plan allows for the five-year amortization of the actual sleeving expenses. On December 4, 1995, when the sleeving project was substantially complete, Maine Yankee obtained a copy of a letter from an organization with a history of opposing nuclear power development to a State of Maine nuclear safety official based on documentation from an anonymous employee or former employee of Yankee Atomic Electric Company (Yankee Atomic), an affiliate of Maine Yankee that has regularly performed nuclear engineering and related services for Maine Yankee and other nuclear plant operators. The letter contained allegations that Yankee Atomic knowingly performed inadequate analyses to support two license amendments to increase the rated thermal power at which the Maine Yankee Plant could operate. It was further alleged in the letter that Maine Yankee deliberately misrepresented the analyses to the Nuclear Regulatory Commission (NRC) in seeking the license amendments. The allegedly inadequate analyses related to the operation of the Plant's emergency core cooling system (ECCS) and the calculation of the Plant containment's peak postulated accident pressure, both under certain assumed accident conditions. The analyses were used in support of license amendments that authorized Plant power uprates from 2,440 megawatts thermal, a level equal to approximately 90 percent of the maximum electrical capability of the Plant, to its current 100-percent rated level. The NRC's Office of the Inspector General (OIG) and its Office of Investigation (OI) initiated separate investigations of the allegations made in the letter. On May 9, 1996, the OIG, which was responsible for investigating only the actions of the NRC staff and not those of Maine Yankee and Yankee Atomic, reported on its investigation, finding deficiencies in the NRC staff's review, documentation, and communications practices in connection with the license amendments, as well as "significant indications of possible licensee violations of NRC requirements and regulations." Any such violations by Maine Yankee would be within the purview of the OI investigation, which, with related issues, is being reviewed by the United States Department of Justice. A separate internal investigation authorized by the boards of directors of Maine Yankee and Yankee Atomic and conducted by an independent law firm noted several areas for improvement, including regulatory communications, definition of responsibilities between Maine Yankee and Yankee Atomic, and tracking and documentation of regulatory compliance, but found no wrongdoing by Maine Yankee or Yankee Atomic or any of their employees. The Company cannot predict the results of the investigations by the OI and Department of Justice. (Page 6) On January 3, 1996, the NRC issued a "Confirmatory Order Suspending Authority For And Limiting Power Operation And Containment Pressure (Effective Immediately) and Demand For Information" (the Order), after reviewing the safety analyses performed by Yankee Atomic relating to Maine Yankee's license amendment applications for the power uprates. The Order limited the power output of Maine Yankee to approximately 90% of its rated maximum until the NRC reviewed and approved plant-specific analyses meeting the NRC's criteria for operation of the ECCS under certain postulated accident conditions, in lieu of the analyses based on the questioned computer code. The Order also required an integrated containment analysis demonstrating that the maximum calculated containment pressure under certain postulated accident conditions does not exceed the design pressure of the Plant's containment. On January 10, 1996, Maine Yankee filed with the NRC information specified in the Order that it believes supports operation of the Plant at up to 90% of the Plant's capability. Maine Yankee attained the 90% level of the Plant's capability on January 24, 1996. On June 7, 1996, the NRC formally notified Maine Yankee that it planned to conduct an "Independent Safety Assessment" (ISA) of the Maine Yankee Plant in conjunction with the State of Maine to provide an independent evaluation of the safety performance of Maine Yankee and as a "follow-up" to the NRC's OIG report. The NRC stated that the overall goals and objectives of the ISA were: "(a) provide an independent assessment of conformance to the design and licensing basis; (b) provide an independent assessment of operational safety performance; (c) evaluate the effectiveness of license self-assessments, corrective actions and improvement plans; and (d) determine root cause(s) of safety significant findings and conclusions." The NRC further informed Maine Yankee that the ISA would be carried out by a team of NRC personnel and contractors who were "independent of any recent or significant involvement with the licensing, regulation, or inspection of Maine Yankee." On July 20, 1996, Maine Yankee went off-line to add pressure relief valves to the primary component cooling system, as determined during a comprehensive internal review by Maine Yankee of plant systems and equipment. On September 2, 1996, the Plant returned to service, attaining the 90% capacity limit. On October 7, 1996, the NRC released the results of the ISA at Maine Yankee that concluded that although Maine Yankee was in general conformance with its licensing basis, several items of deficient or weak performance existed. The ISA report further concluded that the overall performance at Maine Yankee was "adequate" for operation of the Plant. The ISA report further concluded that the two principal causes for these deficiencies were: (1) that economic pressures to be a low-cost power producer had limited resources to address corrective actions and some improvements; and (2) that a questioning culture was lacking, which had resulted in a failure to identify or properly correct significant problems in areas perceived by Maine Yankee to be of low safety significance. In a letter to Maine Yankee accompanying the ISA report, Chairman of the NRC Shirley Ann Jackson noted that although overall performance at Maine Yankee was considered adequate for operation, a number of significant weaknesses and deficiencies identified in the report would result in NRC violations. The letter also directed Maine Yankee to provide to the NRC its plans for addressing the root causes of the deficiencies noted in the ISA and identified the NRC offices that would be responsible for overseeing corrective actions and taking any appropriate enforcement actions against Maine Yankee, including as-yet-determined monetary penalties. The Plant went off-line again on December 6, 1996 to review and resolve several cable separation and cable routing issues. Maine Yankee will complete a root cause analysis of the cable issues and will present the analysis to the NRC regional office prior to startup. Having detected indications of minor leakage in a small number of the Plant's fuel rods, Maine Yankee has used this out-of-service time to inspect the Plant's 217 fuel assemblies and has determined that 68 of the fuel assemblies should be replaced. In addition, 24 fuel assemblies will be replaced as part of a refueling. On December 10, 1996, Maine Yankee filed its formal response to the ISA report. In this report, Maine Yankee promised to substantially increase expenditures to address the source of the deficiencies noted in the ISA report, and that the improvements would include physical and operating changes to the Plant, as well as increased staffing primarily in the engineering and maintenance areas, and other changes. Consequently, Maine Yankee's 1997 Operating Budget has been increased by approximately $46.3 million for additional employees, training and equipment in order to address the root causes of the deficiencies identified in the ISA. The Company's share of this additional amount is approximately $2.3 million. Maine Yankee announced the resignation of President Charles D. Frizzle on December 20, 1996. The Board of Directors of Maine Yankee unanimously decided that new leadership was required to deal with deep-rooted cultural issues, a changing regulatory environment, and unprecedented financial pressures. On February 13, 1997, Maine Yankee and Entergy Nuclear, Inc. (Entergy), which is a subsidiary of Entergy Corporation, a Louisiana-based utility holding company and leading nuclear plant operator, entered into a contract under which Entergy will provide management services to Maine Yankee. At the same time, Michael Sellman of Entergy assumed the office of President of Maine Yankee, and the contract contemplates that Entergy will provide other management personnel to Maine Yankee. On January 29, 1997, the NRC announced it had placed the Plant on its "watch list", in "Category 2", which includes plants that display "weaknesses that warrant increased NRC attention," but do not warrant a shut-down order. The Plant is one of 14 nuclear units in the United States on the January 29 "watch list" and one of six listed there for the first time. The Company expects the Plant to remain off-line until the fuel assembly replacement and thorough inspections of the Plant's electrical cabling and steam generators are completed, and restarting is approved by the NRC. The Company cannot predict how long the Plant will remain off-line, and will make replacement power plans for an outage that could last through the summer of 1997. The Company has been incurring replacement power costs of approximately $170,000 per week while the Plant has been out of service. In addition, the Company is responsible for the previously mentioned additional operating costs of $2.3 million associated with the ISA inspection. Further costs are expected when Entergy Corporation begins providing management services to Maine Yankee. Additional costs may also be expected if the complexity of the cable separation and associated issues require an extended period for their resolution. These additional costs can be expected to adversely impact the Company's 1997 financial results. (Page 7) Under the Company's multi-year rate plan, as described in the "Regulatory Proceedings - Four-Year Rate Plan Approved" section of this Annual Report, the Company has the right to receive specified retail rate increases through 1999. This plan also includes provisions for additional cost recovery in certain extraordinary situations such as very low earnings or in the event of a Maine Yankee Plant outage exceeding six consecutive months. The Company will continue to assess whatever options it may have to recover any additional costs and, in addition, is making every effort to reduce its 1997 cash expenditures. These efforts will include a review of the level of dividends on the Company's Common Stock. Moreover, the Company's short-term revolving credit agreement, as well as a letter of credit supporting its 1996 Series of tax-exempt bonds, contain interest coverage tests that the Company must satisfy to avoid default. The Company now believes, based on the projected additional Maine Yankee expenses and replacement power costs during the Plant outage, that it will likely be in violation of these interest coverage tests for the twelve months ended March 31, 1997. The Company will seek a waiver of these requirements from the necessary parties. The Company anticipates that the waiver will be granted, but cannot predict the terms of any such waiver. In a related matter, a Maine-based group that originally announced its intention to start gathering signatures toward a new referendum to force a permanent closure of the Plant by 2000, has now indicated its intent to modify the referendum to prevent any renewal or extension of Maine Yankee's operating license, currently due to expire in June 2008. The group stated that it hoped to put the issues before the Maine electorate in November, 1998. The Company cannot predict whether such a referendum will be held or its outcome. As an owner of Maine Yankee, the Company is responsible for its proportional share of Maine Yankee operating expenses, including fuel and decommissioning expenses. Furthermore, under a Capital Funds Agreement, the Company, along with the other sponsoring utilities, has agreed to provide Maine Yankee's capital requirements which cannot be obtained from other sources. This obligation is limited to each owner's interest in Maine Yankee, subject to obtaining necessary regulatory approvals. In 1994, pursuant to FERC authorization, Maine Yankee increased its annual collection for decommissioning to $14.9 million, approximately $735,000 a year for the Company. This increase was based on a new decommissioning estimate, assuming dismantlement and removal, of $317 million (in 1993 dollars), as a result of an external engineering study. As of December 31, 1996, Maine Yankee's decommissioning funds are valued at $163.5 million. The decommissioning of nuclear power plants is subject to changes in legal and regulatory requirements as well as technological changes. Earnings and Dividends For 1996 and 1994, earnings per share were $1.31 and $2.99, respectively. The loss of Houlton Water Company as a customer in early 1996 and additional Maine Yankee capacity and replacement power expenses from outages totalling thirteen weeks were the principal reasons for the decrease in 1996 earnings. For 1995, earnings per share before and after extraordinary items were $.57 and a loss of $3.29, respectively. Write-offs of the Company's remaining wholesale investment in Seabrook and other wholesale plant have been classified as extraordinary items resulting in a loss of $6.2 million, net of income taxes, $3.86 per share. In addition to the extraordinary write-offs in 1995, the Company also charged $2.1 million to operating expenses, net of income taxes, or $1.30 per share, for previously deferred retail fuel representing the replacement power expenses incurred during the Maine Yankee resleeving outage in 1995. As discussed in the "Regulatory Proceedings" section of this Annual Report, these write-offs were an element of the four-year rate plan approved by the Maine Public Utilities Commission on November 13, 1995. The Company's return on equity for 1996 was 5.48% compared to a negative 12.33%, after extraordinary items for 1995, and 10.33% for 1994. Dividends paid per share for the years 1994 through 1996 were $1.84 per share. For 1996 and 1994, the dividend payout ratios were 141% and 62%, respectively. Before considering the rate plan write-offs, the 1995 payout ratio was 98.4%. In consideration of the additional operating costs at Maine Yankee and the uncertainty of its continued operations, your Board of Directors at its March 7, 1997 meeting declared a dividend of $.25 per share, a reduction of 46%. This action, along with other actions to control 1997 construction expenditures and operating expenses, is required to improve the Company's cash flows. For additional information, see the "Maine Yankee" and "Liquidity and Capital Resources" sections of this Annual Report. The table below portrays the cost components of an average kilowatt hour sale for the three-year period, based on actual sales for those years. The impact of the extraordinary and deferred fuel write-offs in 1995 totalling $8,340,000, net of tax, has not been considered to obtain comparability with previous years. The fuel component for each of the years reflects the fuel recoveries authorized via the annual fuel adjustment clauses. Components of Costs for Average Revenue Per Primary Sale KWH Before 1995 Write-offs (Cents) 1996 1995 1994 Fuel 3.29 3.21 2.90 Purchased Power Capacity and Other Operations 4.06 3.39 3.38 Depreciation .50 .43 .40 Seabrook Amortization .26 .28 .28 Taxes .67 .70 .86 Interest .66 .63 .62 Other Revenues (.50) (.35) (.48) Return to Shareholders .39 .50 .78 Average Revenue Per Primary Sale KWH 9.33 8.79 8.74 (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 1996, despite the loss of Houlton Water Company, previously our largest customer, and additional Maine Yankee capacity and replacement power expenses from thirteen weeks of unscheduled outages, the Company was able to fund its construction requirements and pay the dividends without requiring additional short-term borrowings. Net cash flows generated from operating activities were $7.4 million in 1996. During 1996, a new $15 million series of 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, and during 1996, $1.1 million of the bonds' proceeds were withdrawn based on qualifying property additions and eligible issuance costs. At the end of 1996, the Company has approximately $4.1 million available for future property additions over the next two and one-half years. The Company 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. At the end of 1996, common shareholders' equity was 47.3% of the Company's capital structure, higher than the industry average. 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. In 1994, operating activities generated net cash flows of $10.3 million. In addition, the Company received the final payment of $1.1 million from the trustee of the 1991 Series of tax-exempt bonds upon the completion of qualifying facilities. The Company paid dividends of $3 million, purchased 43,000 shares of its Common Stock in early 1994 for $1.1 million, made debt payments of $1.9 million, including the final payment on its 4-3/4% First Mortgage Bonds, and invested $4.4 million in electric plant. During 1994, the Company had sufficient cash flows and did not require short-term borrowings from its credit facilities. For additional information regarding construction expenditures for 1994 to 1996 and anticipated construction expenditures for 1997, 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 1996 the Company periodically required short-term borrowings from its credit facilities. As was the case at the end of 1995, the Company ended 1996 with $1.4 million of notes outstanding under the credit facilities. During 1994 to 1996, required borrowings 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 provides $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 1996, the effective interest rate since issuance for this series was 5.61%. 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. 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, the Company does not anticipate using the program to adjust its capital structure. The Company can also issue First Mortgage Bonds of $17.5 million and Second Mortgage Bonds of $24 million without bondable property additions. For additional information on long-term debt, see Note 8, "Long-Term Debt", of the Notes to Consolidated Financial Statements. The Company's success with its rate plan depends on the normal operation of Maine Yankee. Additional capacity and replacement power expenses during unscheduled Maine Yankee outages adversely impact the Company's earnings and cash flows. As more fully explained in the "Maine Yankee" section of this Annual Report, the Company's rate plan includes provisions for additional cost recoveries in the event of a Maine Yankee Plant outage of more than six months or when earnings fall below certain prescribed levels. For additional information on the rate plan, see the "Regulatory Proceedings -- Four- (Page 9) Year Rate Plan Approved" section of this Annual Report. Although the Company will continue to assess whatever options are available under the rate plan, all 1997 cash expenditures, including the level of dividends on the Company's Common Stock, will be reviewed. In addition, the Company's short-term revolving credit agreement, as well as the letter of credit supporting the 1996 Series of tax-exempt bonds, contain interest coverage tests that the Company must satisfy to avoid default. Based on projected capacity expenses for Maine Yankee in early 1997, as well as replacement power expenses during 1997, the Company now believes that it will likely be in violation of these interest coverage tests for the twelve months ended March 31, 1997. The Company will seek waivers from these requirements from the necessary parties, but cannot predict the terms of any such waiver or whether the waivers will be granted. Employees At the end of 1996, the Parent Company had 155 full-time employees compared to 169 for 1995. The lay-up of the Caribou Steam Plant and the corresponding voluntary early retirement in late 1995 to create vacancies for the displaced workers, along with an additional early retirement program in early 1996, caused the decrease in the number of employees. The Subsidiary had 10 full-time employees at the end of both 1996 and 1995. Consolidated payroll costs were $6.5 million in 1996 compared to $6.8 million in 1995. 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 three-year contract effective January 1, 1995. Annual wage increases of 3.25% are provided in each year of the contract. Regulatory Proceedings 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 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 will apply only to the last two rate increases, scheduled to occur 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 the Wheelabrator-Sherman Energy Company (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, under the terms of the plan, has recognized write-offs in 1995, totalling 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 seek recovery of this deferred amount, up to a total of $6,000,000, in rates beginning in the year 2001, after the current term of its contract with Wheelabrator-Sherman has expired. The Company will once again attempt to negotiate with Wheelabrator-Sherman to restructure the terms of its power purchase contract, which was mandated by the MPUC acting under the authority of Public Utility Regulatory Policy Act (PURPA). To date, negotiations have not been successful. The Company believes the deferral allowed under this rate plan parallels the accounting effects of a restructured contract. The Company and Wheelabrator-Sherman are continuing discussions, and the benefits of any restructured contract will be passed through to the Company's customers, by applying any savings first to these deferred amounts. The rate plan also allows 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 amortized over the rate plan period. The Company's success under the rate plan depends on the normal operation of Maine Yankee. As discussed in the "Maine Yankee" section of this Annual Report, the additional capacity payments required to address issues raised in the Independent Safety Assessment and the replacement power costs during unscheduled outages adversely impact the Company's earnings and cash flows. Moreover, the Company's short-term revolving credit agreement, as well as a letter of credit supporting its 1996 revenue bonds, contain (Page 10) interest coverage tests that the Company must satisfy to avoid default. The Company now believes, based on the projected additional Maine Yankee expenses and replacement power costs during the Plant outage, that it will likely be in violation of these interest coverage tests for the twelve months ended March 31, 1997. The Company will seek a waiver of these requirements from the necessary parties, but cannot predict the terms of any such waiver or whether they will be granted. Depending on the length of the unscheduled outage to replace fuel assemblies and the inspection of the Plant's electrical cabling, several provisions of the rate plan could be triggered to permit retail rate increases in excess of those scheduled. 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 1997. The Company cannot predict FERC's ultimate decision in this matter. The Company has not recognized approximately $630,000 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. Industry Restructuring In 1995, the Maine Legislature passed Resolve 89 "To Require a Study of Retail Competition in the Electric Utility Industry" (the Resolve), to begin a process for developing recommendations on the future structure of the electric utility industry in Maine. The process included the appointment of a Work Group on Electric Utility Restructuring to develop a plan for the orderly transition to a competitive market for retail purchases and sales of electricity. The Company participated in this Work Group, which was unable to reach a consensus on a recommended plan by its reporting deadline. The Resolve also directed the Maine Public Utilities Commission (MPUC) to conduct a study to develop at least two plans for the orderly transition to retail competition in the electric utility industry in Maine and to submit a report of its findings by January 1, 1997. One plan would be designed to achieve ". . . full retail market competition for purchases and sales of electric energy by the year 2000" and the other to achieve a more limited form of competition. The Resolve also stated that the MPUC's findings would have no legal effect, but would ". . . provide the Legislature with information in order to allow the Legislature to make informal decisions when it evaluates these plans." On December 31, 1996, the MPUC filed its recommended plan with the Maine Legislature. Major provisions of the plan are as follows: * As of January, 2000, all Maine consumers would have the option to choose an electric power supplier in a competitive market. * As of January, 2000, Maine would not regulate, as public utilities, companies producing or selling electric power. * Regulated public utilities would continue to provide electric transmission and distribution services. These transmission and distribution utilities would have exclusive service territories and an obligation to connect customers to the power grid. * As of January, 2000, the Company, Central Maine Power Company (CMP) and Bangor Hydro-Electric Company (BHE), the State's three largest electric utilities, would be required to structurally separate their generation assets and functions from transmission and distribution functions. CMP and BHE would be required to fully divest themselves of their generation assets by 2006. The plan does not recommend generation divestiture for the Company. * All contracts between the utilities and any qualifying facilities under PURPA will remain with the transmission and distribution companies. * The utilities should be provided a reasonable opportunity to fully recover its generation-related stranded costs. All of the Company's anticipated stranded costs are generation-related. Stranded costs would be collected from customers through the regulated charges of the transmission and distribution companies. * Before 2000, the MPUC would consider progress in other jurisdictions and at the regional level in making the decisions necessary to implement retail competition. * The MPUC would not require that other states or Canadian provinces allow retail competition in their jurisdictions as a condition to permitting suppliers from these states or provinces to enter Maine's market. * Maine Yankee's decommissioning liability would be collected in the rates of the transmission and distribution utilities. * Investor-owned transmission and distribution utilities would not market power. While CMP and BHE could not have affiliates to market power after 2005, the Company could have such an affiliate to market power but only in its service territory. The Maine Legislature will consider the plan during its current session. The Company will be active in the debate on several elements of the Plan. These elements include: * The Company is entitled to full recovery of all stranded costs. We must ensure that the MPUC defines (Page 11) methodologies that consistently and fairly determine asset values. In its plan, based on various estimates of power costs, the MPUC estimated a range of stranded costs for the Company from a negative $54 million to a positive $83 million. A range of this magnitude indicates not only the absence of a coherent methodology for estimating stranded costs, but also the risk that the process can be manipulated to unfairly disadvantage the Company's shareholders. * Only suppliers operating in jurisdictions that allow retail competition should be qualified to sell in Maine's competitive market. Failure to insist on this reciprocity will give foreign suppliers an unfair competitive advantage over Maine suppliers. A supplier operating in a State or Canadian Province that has no retail competition will be able to recover its fixed costs from its captive retail market and need recover only its variable costs to successfully market its product in Maine. Maine suppliers, on the other hand, will have to recover both fixed and variable costs in order to compete successfully. Moreover, those foreign suppliers will be able to "cherry pick" large industrial customers or aggregated loads, while Maine suppliers, such as the Company, will be barred from similar opportunities in those foreign markets. Many parties to this proceeding have taken positions that vary substantially from those set forth in the MPUC's plan, and those parties are expected to advocate their positions before the Legislature. Therefore, the Company cannot predict what form the restructuring of Maine's electric utility industry will ultimately take or what effect that restructuring will have on the Company's business operations and financial results. 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; developments in our legislative, regulatory, and competitive environment; and the results of safety investigations, the cost of maintenance or the operating performance of Maine Yankee. Shareholder Information General The Company's Common Stock is listed and traded on the American Stock Exchange. As of December 31, 1996 and 1995, Common Stock shares issued and outstanding were 1,617,250. As of December 31, 1996, shares were held by 1,619 shareholders or nominees in forty-nine states, the District of Columbia, Canada, 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 1996 Dividends The Company has determined that the Common Stock dividends paid in 1996 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 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 1995 First Quarter $23-7/8 $20-5/8 $ .46 $ .46 Second Quarter $22-3/4 $19-7/8 .46 .46 Third Quarter $23-1/4 $21 .46 .46 Fourth Quarter $23-1/2 $20-5/8 .46 .46 Total Dividends $1.84 $1.84 Dividends declared within the quarter are paid on the first day of the succeeding quarter. (Page 12) Five-Year Summary of Selected Financial Data 1996 1995 1994 1993 1992 Operating Revenues $ 57,264,165 $ 55,278,726 $ 58,368,085 $ 60,476,212 $ 56,683,640 Income Before Extraordinary Items $ 2,110,694 $ 920,500 $ 4,845,647 $ 5,300,840 $ 4,864,936 Extraordinary Items, Net of Taxes - (6,235,812) - - - Net Income (Loss) Available for Common Stock $ 2,110,694 $ (5,315,312) $ 4,845,647 $ 5,300,840 $ 4,864,936 Earnings (Loss) Per Share of Common Stock Income Before Extraordinary Items $ 1.31 $ .57 $ 2.99 $ 3.19 $ 2.93 Extraordinary Items - (3.86) - - - Net Income (Loss) $ 1.31 $ (3.29) $ 2.99 $ 3.19 $ 2.93 Dividends Per Share of Common Stock: Declared Basis $ 1.84 $ 1.84 $ 1.84 $ 1.78 $ 1.76 Paid Basis $ 1.84 $ 1.84 $ 1.84 $ 1.76 $ 1.74 Total Assets $116,714,374 $114,074,091 $122,375,442 $124,936,558 $112,047,613 Long-Term Debt Outstanding $ 41,120,000 $ 37,435,000 $ 37,500,000 $ 39,365,000 $ 39,455,000 Less amount due within one year 1,315,000 1,315,000 65,000 1,865,000 90,000 Long-Term Debt $ 39,805,000 $ 36,120,000 $ 37,435,000 $ 37,500,000 $ 39,365,000 (Page 13) Independent Auditors' Report MAINE PUBLIC SERVICE COMPANY: We have audited the accompanying consolidated balance sheet and statement of capitalization of Maine Public Service Company and its Subsidiary, Maine and New Brunswick Electrical Power Company, Limited, as of December 31, 1996, and the related consolidated statements of operations, common shareholders' equity, and cash flows for the year 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 audit. The consolidated financial statements of Maine Public Service Company and its Subsidiary for the years ended December 31, 1995 and 1994, were audited by other auditors, whose report dated February 14, 1996, expressed an unqualified opinion on those statements. 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, the 1996 consolidated financial statements present fairly, in all material respects, the consolidated financial position of Maine Public Service Company and its Subsidiary at December 31, 1996 and the results of their operations and their cash flows for the year then ended in conformity with generally accepted accounting principles. /s/ Coopers & Lybrand, LLP Coopers & Lybrand LLP Portland, Maine February 11, 1997 (Page 14) MAINE PUBLIC SERVICE COMPANY AND SUBSIDIARY Statements of Consolidated Operations Year Ended December 31, 1996 1995 1994 Operating Revenues $ 57,264,165 $ 55,278,726 $ 58,368,085 Operating Expenses Purchased Power 31,819,691 31,978,290 27,764,353 Other Operation and Maintenance 12,439,768 11,826,100 12,726,268 Depreciation and Amortization 4,097,456 4,277,494 4,224,190 Taxes Other Than Income 1,664,685 1,653,228 1,594,422 Provision for Income Taxes 1,954,747 1,179,336 3,739,777 Total Operating Expenses 51,976,347 50,914,448 50,049,010 Operating Income 5,287,818 4,364,278 8,319,075 Other Income (Deductions) Equity in Income of Associated Companies 350,008 360,684 361,752 Allowance for Equity Funds Used During Construction 7,120 3,667 9,174 Provision for Income Taxes (103,681) (73,269) (104,546) Other - Net 95,678 27,172 113,925 Total 349,125 318,254 380,305 Income Before Interest Charges and Extraordinary Items 5,636,943 4,682,532 8,699,380 Interest Charges Long-Term Debt and Notes Payable 3,529,867 3,763,395 3,857,301 Less Allowance for Borrowed Funds Used During Construction (3,618) (1,363) (3,568) Total 3,526,249 3,762,032 3,853,733 Income Before Extraordinary Items 2,110,694 920,500 4,845,647 Extraordinary Items, Net of Taxes of - (6,235,812) - Net Income (Loss) Available for Common Stock $2,110,694 $ (5,315,312) $4,845,647 Earnings (Loss) Per Share of Common Stock Income Before Extraordinary Items $ 1.31 $ .57 $ 2.99 Extraordinary Items - $ (3.86) - Net Income (Loss) $ 1.31 $ (3.29) $ 2.99 Average Shares Outstanding 1,617,250 1,617,250 1,618,700 See Notes to Consolidated Financial Statements. (Page 15) MAINE PUBLIC SERVICE COMPANY AND SUBSIDIARY Statements of Consolidated Cash Flows Year Ended December 31, 1996 1995 1994 Cash Flow From Operating Activities Net Income (Loss) $ 2,110,694 $(5,315,312) $ 4,845,647 Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operations: Depreciation and Amortization 4,097,456 4,277,494 4,224,190 Extraordinary Items, After Income Taxes - 6,235,812 - Deferred Income Taxes - Net (377,355) 1,165,623 (359,942) Deferred Investment Tax Credits (74,662) (77,027) (77,027) Allowance for Funds Used During Construction (10,738) (5,030) (12,742) Income on Tax-Exempt Bonds-Restricted Funds (118,443) - (6,269) Change in Deferred Regulatory and Debt Issuance Costs (267,768) (4,795,603) 1,690,200 Change in Deferred Revenues 275,846 353,653 (119,440) Change in Benefit Obligations 874,267 301,164 53,615 Change in Current Assets and Liabilities: Accounts Receivable and Unbilled Revenue 1,023,602 (246,124) 1,048,069 Deferred Fuel and Purchased Energy Cost - 442,416 (760,990) Other Current Assets (366,995) 39,540 (216,035) Accounts Payable 244,157 1,150,497 495,726 Accrued Taxes and Interest (161,894) 11,374 (654,040) Other Current Liabilities (16,673) 4,291 (11,316) Other - Net 153,205 (115,579) 153,136 Net Cash Flow Provided By Operating Activities 7,384,699 3,427,189 10,292,782 Cash Flow From Financing Activities Dividend Payments (2,975,740) (2,975,740) (2,975,740) Tax-Exempt Bond Issuance Costs (398,585) - - Purchase of Common Stock - - (1,143,137) Issuance of Tax-Exempt Bonds 15,000,000 - - Drawdown of Tax-Exempt Bond Proceeds 1,063,969 - 1,110,637 Retirements of Long-Term Debt (11,315,000) (65,000) (1,865,000) Short-Term Borrowings, Net - 1,400,000 - Net Cash Flow Provided By (Used In) Financing Activities 1,374,644 (1,640,740) (4,873,240) Cash Flow Used In Investing Activities Investment in Restricted Funds (5,000,000) - 169,588 Investment in Electric Plant (3,444,515) (3,428,784) (4,362,620) Net Cash Flow Used In Investing Activities (8,444,515) (3,428,784) (4,193,032) Increase (Decrease) in Cash and Temporary Investments 314,828 (1,642,335) 1,226,510 Cash and Temporary Investments at Beginning of Year 976,083 2,618,418 1,391,908 Cash and Temporary Investments at End of Year $1,290,911 $ 976,083 $2,618,418 Supplemental Disclosure of Cash Flow Information: Cash Paid During The Year For: Interest $3,536,812 $3,499,198 $3,580,862 Income Taxes $2,939,776 $ 235,076 $5,040,950 See Notes to Consolidated Financial Statements. (Page 16) MAINE PUBLIC SERVICE COMPANY AND SUBSIDIARY Consolidated Balance Sheets Assets December 31, 1996 1995 Utility Plant Electric Plant in Service $91,224,297 $88,648,045 Less Accumulated Depreciation 41,670,398 39,674,322 Net Electric Plant in Service 49,553,899 48,973,723 Construction Work-In-Progress 461,435 427,654 Total 50,015,334 49,401,377 Investments in Associated Companies 3,658,627 3,641,211 Net Utility Plant and Investments in Associated Companies 53,673,961 53,042,588 Current Assets: Cash and Temporary Investments 1,290,911 976,083 Deposits for Interest and Dividends 805,512 743,935 Accounts Receivable (less allowance for uncollectible accounts in 1996, $207,028 and 1995, $214,130) 5,020,921 6,225,423 Unbilled Revenue 1,652,720 1,471,820 Deferred Fuel and Purchased Energy Costs 125,000 125,000 Current Deferred Income Taxes 221,578 232,269 Inventory 1,194,222 1,243,597 Prepayments 959,303 542,933 Total 11,270,167 11,561,060 Other Assets: Recoverable Seabrook Costs (less accumulated amortization and write-off in 1996, $25,464,603; in 1995, $24,040,971) 27,722,407 29,146,039 Regulatory Assets-SFAS 109 & 106 12,713,312 13,746,531 Restricted Investments (at cost, which approximates market) 4,054,474 - Deferred Fuel and Purchased Energy Costs 3,950,512 2,575,512 Unamortized Debt Expense (less accumulated amortization in 1996, $1,787,019; in 1995 $1,601,945) 936,376 702,865 Deferred Regulatory Costs (less accumulated amortization in 1996, $1,222,948; in 1995, $1,567,429) 1,756,605 2,698,763 Miscellaneous 636,560 600,733 Total 51,770,246 49,470,443 Total Assets $116,714,374 $114,074,091 See Notes to Consolidated Financial Statements. (Page 17) Capitalization and Liabilities December 31, 1996 1995 Capitalization (see accompanying statements): Common Shareholders' Equity $38,091,749 $38,956,795 Long-Term Debt 39,805,000 36,120,000 Total 77,896,749 75,076,795 Current Liabilities: Long-Term Debt Due Within One Year 1,315,000 1,315,000 Notes Payable to Banks 1,400,000 1,400,000 Accounts Payable 3,026,567 3,176,851 Accounts Payable - Associated Companies 1,182,394 838,863 Accrued Employee Benefits 1,266,011 1,215,101 Dividends Declared 743,936 743,936 Customer Deposits 62,147 78,820 Taxes Accrued 135,759 105,634 Interest Accrued 826,684 1,018,703 Total 9,958,498 9,892,908 Deferred Credits: Deferred Revenues 629,499 353,653 Income Taxes 23,694,229 24,997,851 Investment Tax Credits 720,473 795,135 Miscellaneous 3,814,926 2,957,749 Total 28,859,127 29,104,388 Commitments, Contingencies, and Regulatory Matters (Note 10) Total Capitalization and Liabilities $116,714,374 $114,074,091 (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, 1994 1,660,250 $13,070,750 $38,317 $37,983,249 $(4,571,239) Net Income 4,845,647 Dividends: Common Stock ($1.84 per share) (2,975,740) Stock Repurchased: Common Stock (43,000) (1,143,137) Balance, December 31, 1994 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) See Notes to Consolidated Financial Statements. (Page 19) MAINE PUBLIC SERVICE COMPANY AND SUBSIDIARY Consolidated Statements of Capitalization December 31, 1996 1995 Common Shareholders' Equity Common Stock, $7 Par Value-Authorized 3,000,000 Shares in 1996 and 1995; Issued 1,867,250 Shares in 1996 and 1995 $13,070,750 $13,070,750 Paid-In-Capital 38,317 38,317 Retained Earnings 30,697,058 31,562,104 Total 43,806,125 44,671,171 Treasury Stock-Total Shares of 250,000 in 1996 and 1995, at cost (5,714,376) (5,714,376) Total $38,091,749 $38,956,795 Long-Term Debt First Mortgage and Collateral Trust Bonds: 7-1/8% Due Serially through 1998-Interest Payable, May 1 and November 1 $ 2,920,000 $ 2,960,000 7.95% Due Serially through 2003-Interest Payable, March 1 and September 1 1,950,000 1,975,000 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 6,250,000 7,500,000 Public Utility Revenue Bonds-1991 Series: 7.875% Due 2021-Interest Payable, April 1 and October 1 - 10,000,000 Public Utility Refunding Revenue Bonds- Series 1996: Due 2021-Variable Interest Payable Monthly (4.5% as of December 31, 1996) 15,000,000 - Total Outstanding 41,120,000 37,435,000 Less-Amount Due Within One Year 1,315,000 1,315,000 Total $39,805,000 $36,120,000 Current Maturities and Redemption Requirements for the Succeeding Five Years Are as Follows: Long-Term Debt: 1997 $ 1,315,000 1998 $ 4,155,000 1999 $ 1,275,000 2000 $ 1,275,000 2001 $ 2,635,000 Thereafter $30,465,000 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, 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 $630,000 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 2.99%, 2.96%, and 2.99% for 1996, 1995, and 1994, respectively. Bond issuance costs and premiums paid upon early retirements are amortized over the terms of the related debt. Recoverable Seabrook costs and 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 Temporary Investments 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 temporary investments. Accounting Pronouncements Effective January 1, 1996, the Company adopted Statement of Financial Accounting Standards No. 121 "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of." The adoption of the new standard had no effect on the Company's financial position or results of operations. Reclassifications Certain reclassifications have been made to the 1995 and 1994 financial statements in order to conform to the 1996 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)". 1996 1995 1994 Current income taxes $2,510,445 $ 164,009 $4,281,292 Deferred income taxes (377,355) (687,190) (359,942) Investment credits, net (74,662) (141,613) (77,027) Total income taxes $2,058,428 $ (664,794) $3,844,323 Allocated to: Operating income $1,954,747 $1,179,336 $3,739,777 Other income 103,681 73,269 104,546 Extraordinary Items - (1,917,399) - Total $2,058,428 $ (664,794) $3,844,323 The effective income tax rates differ from the U.S. statutory rate as follows: 1996 1995 1994 Statutory rate 34.0% (34.0)% 34.0% Excess Canadian taxes 4.2 1.6 1.2 Amortization of recoverable Seabrook costs 6.7 5.5 3.8 State income taxes 5.4 (1.7) 5.8 Seabrook wholesale write-off - 16.7 - Other (.9) .8 (.6) Effective rate 49.4% (11.1)% 44.2% The elements of deferred income tax expense (credit) are as follows: (Dollars in Thousands) 1996 1995 1994 Temporary Differences at Statutory Rates: Seabrook - costs $ (200) $ (234) $ (234) Liberalized depreciation 166 219 158 AFUDC-borrowed funds (52) (63) (63) Deferred fuel/Wheelabrator- Sherman expenses 559 582 328 Deferred regulatory expense (345) 829 (573) Unbilled and deferred revenue (110) (141) 48 Accrued pension and post- retirement benefits (414) 40 52 Other 19 (66) (76) Total temporary differences - operations (377) 1,166 (360) Extraordinary Items - (1,853) - Total temporary differences - statutory rates $ (377) $ (687) $ (360) (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 1995, while dividends were $433,243 and $736,492 in 1994 and 1996, respectively. In 1994, the dividend received from the Subsidiary exceeded earnings by $55,816, while for 1996, earnings exceeded the dividend by $8,608. The following summarizes accumulated deferred income taxes established on temporary differences under SFAS 109 as of December 31, 1996 and 1995. (Dollars in Thousands) 1996 1995 Seabrook $15,273 $16,071 Property 8,104 8,396 Regulatory expenses 1,201 915 Investment tax credits (478) (528) Pension and post- retirement benefits (670) (262) Other 264 406 Net accumulated deferred income taxes $23,694 $24,998 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". Dividends received during 1996, 1995, and 1994 from Maine Yankee were approximately $333,750, $172,500, and $347,500, respectively, and from MEPCO approximately $7,900 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 1996 1995 1994 1996 1995 1994 Earnings Operating revenues $185,661 $205,977 $173,857 $ 55,391 $ 49,699 $ 24,746 Earnings applicable to Common Stock $ 6,640 $ 7,060 $ 7,080 $ 220 $ 105 $ 105 Company's equity share of net earnings $ 332 $ 353 $ 354 $ 16 $ 8 $ 8 Investment Total assets $602,061 $580,958 $549,910 $ 10,727 $ 6,025 $ 6,562 Less: Preferred stock 18,000 18,600 19,200 - - - Long-term debt 83,332 89,999 96,666 620 - 1,730 Other liabilities and deferred credits 429,392 401,158 366,550 9,110 5,147 3,954 Net assets $ 71,337 $ 71,201 $ 67,494 $ 997 $ 878 $ 878 Company's equity in net assets $ 3,567 $ 3,560 $ 3,375 $ 75 $ 66 $ 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, 1996 and 1995 is as follows: (Dollars in Thousands) 1996 1995 Electric plant in service $5,924 $5,896 Accumulated depreciation (3,231) (3,078) Net electric plant in service $2,693 $2,818 5. SHORT-TERM CREDIT ARRANGEMENTS The Company has a revolving credit arrangement with a consortium of 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 plus 1/2%. The B Loans bear interest as arranged between the Company and the participating bank. As of December 31, 1996 and 1995, a B Loan for $1.4 million was outstanding under this arrangement at 5.5625% and 6.4%, respectively. 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 1996. 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 1996, 1995, and 1994 plan years, the Company has made contributions of $282,000 in 1997, $284,000 in 1996, and $340,000 in 1995, 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 1996, 1995, and 1994 are as follows: (Dollars in Thousands) 1996 1995 1994 Service costs for benefits earned during the period $ 298 $ 264 $ 329 Interest cost on projected benefit obligation 939 932 891 Return on plan assets: Actual (1,251) (2,021) 83 Deferred 298 1,111 (962) Total (953) (910) (879) Net amortization and deferral (2) (2) (2) Net Pension Cost 282 284 339 Early retirement benefits 402 231 - Total Pension Costs $ 684 $ 515 $ 339 The following table sets forth the plan's funded status, obligations, and assumptions as of December 31, 1996 and 1995: (Dollars in Thousands) 1996 1995 Accumulated benefit obligation: Vested $ 11,016 $ 11,311 Non-vested 153 230 Total $ 11,169 $ 11,541 Projected benefit obligation $(13,041) $(13,949) Fair value of assets 13,067 12,421 Funded status 26 (1,528) Unrecognized prior service costs 892 968 Unrecognized transition amount (481) (558) Unrecognized (gain) loss (2,008) (52) Accrued Pension Cost $(1,571) $(1,170) Assumptions: Discount rate 7.5% 7.0% Salary increases 4.5% 4.5% Expected return on assets 8.5% 8.5% At December 31, 1996, 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 $54,000, $41,000 and $34,000 in 1996, 1995, and 1994, 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 1996. 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) 1996 1995 1994 Service costs for benefits $ 98 $ 97 $ 91 Interest cost 321 365 307 Amortization of transition obligation 213 213 213 Total costs 632 675 611 Current payments for retiree obligations allowed in Company's cost of service (233) (207) (195) Additional SFAS 106 costs $399 $468 $416 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) 1996 1995 Retirees $(2,283) $(2,382) Fully eligible actives (1,295) (1,300) Other actives (892) (1,518) Accumulated postretirement benefit obligation (4,470) (5,200) Transition obligation 3,394 3,607 Net (gain) loss (762) 154 Accrued postretirement benefit cost $(1,838) $(1,439) There were no unrecognized prior service costs. For 1996 and 1995, the Company used an assumed weighted average discount rate of 7.5% and 7%, respectively. The health care cost trend rate used for 1996 was 8%, with the ultimate trend rate of 5% reached in three 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 $642,000, in service costs by $31,000 and interest costs by $48,000. 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 $30,697,058 at December 31, 1996. 8. REFINANCING On April 4, 1991, the Maine Public Utilities Financing Bank (MPUFB) issued $10 million of tax-exempt bonds (the 1991 Series) on behalf of the Company. Pursuant to a letter of credit and reimbursement agreement, the Company caused a Direct Pay Letter of Credit for a term of five years to be issued by Barclays Bank PLC, New York Branch (Barclays Bank) for the benefit of the holders of such bonds. To secure the Company's obligations under the reimbursement agreement, the Company issued a second mortgage bond to Barclays Bank as collateral for the Company's obligation. The bonds had a coupon rate of 7.875% and, after considering the enhancement fees and other costs, the annual cost to the Company was approximately 8.725%. In September 1995, Barclays Bank notified the Company that it would not renew the Direct Pay Letter of Credit for this issue. 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 1991 Series through the payment of the refunding note from Fleet Bank of Maine, used to redeem the 1991 Series, and provides $5 million for the acquisition of qualifying property, of which $4.1 million remains in trust as of December 31, 1996. 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 initially selected the weekly interest period. After considering issuance costs and credit enhancement fees, the effective interest rate was 5.61% for 1996. 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, 1996, the Company's long-term debt had a carrying value of approximately $41.1 million and a fair value of approximately $43.7 million. (Page 25) 10. COMMITMENTS, CONTINGENCIES, AND REGULATORY MATTERS Customer Rates On November 13, 1995, the Maine Public Utilities Commission (MPUC) approved a stipulation establishing a four-year rate plan. Under the terms of the stipulation, the Company's retail rates increased by 4.4% on January 1, 1996 and 2.9% on February 1, 1997, and will increase by 2.75% on February 1, 1998, and February 1, 1999, respectively. The Company has agreed to seek no other increase, for either base or fuel rates, except as provided under the terms of the rate plan. For the increases scheduled to occur in 1998 and 1999, a profit-sharing mechanism based on a target return on equity of 11%, calculated using certain retail ratemaking methodologies, will also apply. 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. However, the Company is permitted to adjust the annual increases for certain mandated costs, such as tax or accounting changes that exceed $300,000 in annual revenue requirements. The plan also provides that if either Maine Yankee or Wheelabrator-Sherman ceases operations for more than six months, one-half of the resulting net costs or net savings will adjust the allowed rate increases. Any net costs or net savings realized during the first six months of the outage accrues entirely to the shareholders. 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 plan. Under the terms of the rate plan, the Company agreed to write off to operating expenses $2,104,000, net of income taxes, of deferred retail fuel representing replacement power costs incurred during the 1995 Maine Yankee outage. As a result of the application of SFAS No. 101 "Accounting for the Discontinuation of Application of FASB Statement No. 71", the Company wrote off approximately $4,846,000, net of income taxes, of the Company's investment in the Seabrook nuclear power project previously allocated to the wholesale customers and $1,390,000, net of income taxes, of other wholesale plant and regulatory assets. The plan also permits the Company to annually defer $1.5 million 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 seek recovery of this deferred amount, up to a total of $6 million, in rates beginning in the year 2001, after the current term of its contract with Wheelabrator-Sherman expires. The rate plan also allows the deferral, until the year 2000, of approximately $1.3 million, net of taxes, of uncollected retail fuel at the beginning of the rate plan, while an additional $300,000, net of income taxes, will be amortized over the rate plan period. The Company's success under the rate plan depends on the normal operation of Maine Yankee. The additional capacity payments required to address issues raised in the Independent Safety Assessment and the replacement power costs during unscheduled outages adversely impact the Company's earnings and cash flows. Moreover, the Company's short-term revolving credit agreement, as well as a letter of credit supporting its 1996 revenue bonds, contain interest coverage tests that the Company must satisfy to avoid default. The Company now believes, based on the projected additional Maine Yankee expenses and replacement power costs during the Plant outage, that it will likely be in violation of these interest coverage tests for the twelve months ended March 31, 1997. The Company will seek a waiver of these requirements from the necessary parties, but cannot predict the terms of any such waiver or whether they will be granted. Depending on the length of the unscheduled outage to replace fuel assemblies and the inspection of the Plant's electrical cabling and steam generators, several provisions of the rate plan could be triggered to permit retail rate increases in excess of those scheduled. During outages, the Company incurs approximately $170,000 of additional purchase power costs per week. During 1996, the Company entered long-term power contracts with two of its largest customers. The price under these contracts are lower than permitted under the Company's standard rates, but obligates them to purchase all of their electrical requirements through the year 2000. One additional customer has signed a similar agreement that must be approved by the MPUC, while two others have verbally accepted the Company's offers. 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. Competition and Industry Restructuring In 1995, the Maine Legislature passed Resolve 89 "To Require a Study of Retail Competition in the Electric Utility Industry" (the Resolve), to begin a process for developing recommendations on the future structure of the electric utility industry in Maine. The process included the appointment of a Work Group on Electric Utility Restructuring to develop a plan for the orderly transition to a competitive market for retail purchases and sales of electricity. The Resolve also directed the Maine Public Utilities Commission (MPUC) to conduct a study to develop at least two plans for the orderly transition to retail competition in the electric utility industry in Maine and to submit a report of its findings by January 1, 1997. One plan would be designed to achieve ". . . full retail market competition for purchases and sales of electric energy by the year 2000" and the other to achieve a more limited form of competition. The Resolve also stated that the MPUC's findings would have no legal effect, but would ". . . provide the Legislature with information in order to allow the Legislature to make informal decisions when it evaluates these plans." On December 31, 1996, the MPUC filed its recommended plan with the Maine Legislature. Major provisions of the plan are as follows: * As of January, 2000, all Maine consumers would have the option to choose an electric power supplier in a competitive market. * As of January, 2000, Maine would not regulate, as public utilities, companies producing or selling electric power. * Regulated public utilities would continue to provide electric transmission and distribution services. These transmission and distribution utilities would have exclusive service territories and an obligation to connect customers to the power grid. * As of January, 2000, the Company, Central Maine Power Company (CMP) and Bangor Hydro-Electric Company (BHE), the State's three largest electric utilities, would be required to structurally separate their generation assets and functions from transmission and distribution functions. CMP and BHE would be required to fully divest themselves of their generation assets by 2006. The plan does not recommend generation divestiture for the Company. (Page 26) * All contracts between the utilities and any qualifying facilities under PURPA will remain with the transmission and distribution companies. * The utilities should be provided a reasonable opportunity to fully recover its generation-related stranded costs. All of the Company's anticipated stranded costs are generation-related. Stranded costs would be collected from customers through the regulated charges of the transmission and distribution companies. * Before 2000, the MPUC would consider progress in other jurisdictions and at the regional level in making the decisions necessary to implement retail competition. * The MPUC would not require that other states or Canadian provinces allow retail competition in their jurisdictions as a condition to permitting suppliers from these states or provinces to enter Maine's market. * Maine Yankee's decommissioning liability would be collected in the rates of the transmission and distribution utilities. * Investor-owned transmission and distribution utilities would not market power. While CMP and BHE could not have affiliates to market power after 2005, the Company could have such an affiliate to market power but only in its service territory. Many parties to this proceeding have taken positions that vary substantially from those set forth in the MPUC's plan, and those parties are expected to advocate their positions before the Legislature. Therefore, the Company cannot predict what form the restructuring of Maine's electric utility industry will ultimately take or what effect that restructuring will have on the Company's business operations and financial results. 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, 1996 and 1995 are as follows: (Dollars in Thousands) 1996 1995 Retail $43,136 $43,136 Accumulated Amortization (15,414) (13,990) Retail, Net $27,722 $29,146 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 $3.6 million or $.5 million annually, without considering inflation indexing. Capacity Arrangements The Company owns 5% of the Common Stock of the Maine Yankee Atomic Power Company (Maine Yankee). Maine Yankee owns and operates an 860,000 kilowatt nuclear generating plant in Wiscasset, Maine. The Company is entitled to purchase approximately 4.9% of the energy produced by the Plant. During 1996, 1995, and 1994, Maine Yankee purchased power expenses were $10,185,000, $7,972,000, and $9,645,000, respectively. During most of 1995, Maine Yankee was not in service in order to repair its steam generator tubes using welded sleeves. The sleeving of the steam generator tubes was completed in mid-December of 1995 at a cost of approximately $27 million, with the Company's share being approximately $1.3 million. In accordance with the Company's rate plan, discussed previously, the Company began recovering these costs over five years starting in 1996. After responding to allegations regarding certain safety analyses performed to increase the rated capacity of the Plant, the Nuclear Regulatory Commission (NRC) informed Maine Yankee that the allegations would be subject to investigations, but allowed Maine Yankee to operate at 90% of its rated maximum capacity until the NRC reviewed and approved plant-specific analyses. On January 22, 1996, Maine Yankee attained the 90% level of the Plant's capability. Maine Yankee was out of service a total of thirteen weeks in 1996 because of the January outage, a six-week unscheduled outage in July and August, and the current outage that began on December 6, 1996. The Plant is expected to remain out of service through the summer of 1997 to allow the review and resolution of several cable separation and cable routing issues and the replacement of 68 of the Plant's 217 fuel assemblies due to the detection of minor leakages in a small number of the Plant's fuel rods. In addition, 24 fuel assemblies will be replaced as part of a refueling. These issues were discovered as a result of the NRC's "Independent Safety Assessment" (ISA) and subsequent internal investigation. The Company's share of expenses to address these issues is approximately $2.3 million in 1997 for additional employees, training, and equipment. The Company incurs approximately $170,000 per week for replacement power costs while Maine Yankee is out of service. On January 29, 1997, the NRC announced that it had placed the Plant on its "watch list" in "Category 2", which includes plants that display "weaknesses that warrant increased attention", but do not warrant a shut-down order. The Plant is one of 14 nuclear units in the United States on the January 19, 1997, "watch list" and one of six listed for the first time. Moreover, the Company's short-term revolving credit agreement, as well as a letter of credit supporting its 1996 Series of tax-exempt bonds, contain interest coverage tests that the Company must satisfy to avoid default. The Company now believes, based on the projected additional Maine Yankee expenses and replacement power costs during the Plant outage, that it will likely be in violation of these interest coverage tests for the twelve months ended March 31, 1997. The Company will seek a waiver of these requirements from the necessary parties. The Company anticipates that the waiver will be granted, but cannot predict the terms of any such waiver. As an owner of Maine Yankee, the Company is responsible for its proportional share of Maine Yankee operating expenses, including fuel and decommissioning expenses. Furthermore, under a Capital Funds Agreement, the Company, along with the other sponsoring utilities, has agreed to provide Maine Yankee's capital requirements which cannot be obtained from other sources. This obligation is limited to each owner's interest in Maine Yankee, subject to obtaining necessary regulatory approvals. In 1994, pursuant to FERC authorization, Maine Yankee increased its annual collection for decommissioning to $14.9 million, approximately $735,000 a year for the Company. This increase was (Page 27) based on a new decommissioning estimate, assuming dismantlement and removal, of $317 million (in 1993 dollars), as a result of an external engineering study. As of December 31, 1996, Maine Yankee's decommissioning funds are valued at $163.5 million. The decommissioning of nuclear power plants is subject to changes in legal and regulatory requirements as well as technological changes. 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. 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 Maine Yankee and 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., owner of an 18 megawatt wood-burning cogenerator plant, began selling power to the Company. The Company purchases the entire output from the cogenerator under a contract ordered by the MPUC that will expire in 2001. This contract includes a 5% annual price increase. During 1996, 1995, and 1994, purchases from Wheelabrator-Sherman were $15,593,000, $14,507,000, and $13,932,000, respectively. Construction Program Expenditures on additions, replacements and equipment for the years ended December 31, 1996, 1995, and 1994, along with 1997 estimated expenditures, are as follows: (Dollars in Thousands) 1997 1996 1995 1994 (Unaudited Estimates) Parent Company Generation $ 69 $ 345 $ 131 $ 178 Transmission 420 322 364 357 Distribution 2,032 2,080 1,993 2,235 General 417 626 845 1,015 Total Parent 2,938 3,373 3,333 3,785 Subsidiary 131 72 96 578 Total $3,069 $3,445 $3,429 $4,363 11. QUARTERLY INFORMATION (unaudited) Quarterly financial data for the two years ended December 31, 1996 is as follows: (Dollars in Thousands Except Per Share Amounts) 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 $ .90 $ .38 $ (.41) $ .44 1995 by Quarter 1st 2nd 3rd 4th Operating revenues $15,556 $12,471 $12,273 $14,947 Operating expenses (13,801) (10,589) (10,857) (15,635) Operating income 1,755 1,882 1,416 (688) Interest charges (943) (939) (938) (942) Other income-net 62 63 111 82 Income (loss) before extraordinary items 874 1,006 589 (1,548) Extraordinary items - - - (6,236) Net income (loss) $ 874 $ 1,006 $ 589 $(7,784) Earnings (loss) per common share Income (loss) before extra- ordinary items $ .54 $ .62 $ .36 $ (.95) Extraordinary items - - - (3.86) Net income (loss) $ .54 $ .62 $ .36 $ (4.81) (Page 28 & 29) MAINE PUBLIC SERVICE COMPANY and Subsidiary All share information and per share amounts reflect the stock split on March 3, 1989. Consolidated Financial Statistics 1996 1995 1994 Capitalization Including Bank Borrowings (year-end) Debt (including amount due within one year) 52.75% 49.92% 44.25% Preferred Stock (including amount due within one year) 0% 0% 0% Common Shareholders' Equity 47.25% 50.08% 55.75% Times Interest Earned - * Before Income Taxes 2.18 2.51 3.25 After Income Taxes 1.60 1.80 2.26 Times Interest and Preferred Dividends Earned - * After Income Taxes 1.60 1.80 2.26 Embedded Cost of Long-Term Debt (year-end) 8.01% 9.36% 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 Earnings Per Share of Common Stock (average shares) Income Before Cumulative Effect of Accounting Change and Extra- ordinary Items 1.31 .57 2.99 Cumulative Effect of Accounting Change - - - Extraordinary Items - (3.86) - Net Income (Loss) 1.31 (3.29) 2.99 Dividends Per Share of Common Stock Declared Basis 1.84 1.84 1.84 Paid Basis l.84 l.84 l.84 Common Stock Dividend Payout Ratio - ** 140.46% 98.40% 61.54% Book Value Per Share of Common Stock (year-end) 23.55 24.09 29.22 Market Price Per Share of Common Stock High 22 3/8 23 7/8 27 3/8 Low 16 7/8 19 7/8 20 1/2 Close 18 1/8 21 3/8 20 3/4 Price Earnings Ratio (year-end) 13.84 - 6.94 Number of Common Shareholders (year-end) 1,619 1,634 1,650 * Consolidated income before cumulative effect of accounting change and extraordinary items. Includes AFUDC and Deferred Return on Seabrook Investment. Excludes all Seabrook write-offs in 1985 and 1986 and all regulatory write-offs in 1995. ** Before regulatory write-offs in 1995. Consolidated Financial Statistics 1993 1992 1991 Capitalization Including Bank Borrowings (year-end) Debt (including amount due within one year) 45.83% 50.16% 53.01% Preferred Stock (including amount due within one year) 0% 0% 0% Common Shareholders' Equity 54.17% 49.84% 46.99% Times Interest Earned - * Before Income Taxes 3.49 3.01 2.81 After Income Taxes 2.36 2.09 2.00 Times Interest and Preferred Dividends Earned - * After Income Taxes 2.36 2.09 2.00 Embedded Cost of Long-Term Debt (year-end) 9.14% 9.14% 9.28% Embedded Cost of Preferred Stock (year-end) 0% 0% 0% Common Shares Outstanding (year-end) 1,660,250 1,660,250 1,660,250 Earnings Per Share of Common Stock (average shares) Income Before Cumulative Effect of Accounting Change and Extraordinary Items 3.19 2.93 2.62 Cumulative Effect of Accounting Change - - - Extraordinary Items - - - Net Income (Loss) 3.19 2.93 2.62 Dividends Per Share of Common Stock Declared Basis 1.78 1.76 1.68 Paid Basis l.76 1.74 1.68 Common Stock Dividend Payout Ratio - ** 55.80% 60.07% 64.12% Book Value Per Share of Common Stock (year-end) 28.02 26.61 25.44 Market Price Per Share of Common Stock High 31 1/4 26 7/8 26 3/8 Low 25 5/8 24 1/4 20 3/4 Close 25 7/8 25 7/8 26 3/8 Price Earnings Ratio (year-end) 8.11 8.83 10.07 Number of Common Shareholders (year-end) 1,720 1,768 1,823 * Consolidated income before cumulative effect of accounting change and extraordinary items. Includes AFUDC and Deferred Return on Seabrook Investment. Excludes all Seabrook write-offs in 1985 and 1986 and all regulatory write-offs in 1995. ** Before regulatory write-offs in 1995. Consolidated Financial Statistics (Continued) 1990 1989 1988 Capitalization Including Bank Borrowings (year-end) Debt (including amount due within one year) 49.40% 43.12% 47.76% Preferred Stock (including amount due within one year) 0% 4.02% 4.41% Common Shareholders' Equity 50.60% 52.86% 47.83% Times Interest Earned - * Before Income Taxes 3.24 3.21 3.07 After Income Taxes 2.22 2.26 2.29 Times Interest and Preferred Dividends Earned - * After Income Taxes 2.18 2.09 2.05 Embedded Cost of Long-Term Debt (year-end) 9.92% 9.71% 10.80% Embedded Cost of Preferred Stock (year-end) 0% 9.74% 9.74% Common Shares Outstanding (year-end) 1,761,050 1,849,550 1,865,666 Earnings Per Share of Common Stock (average shares) Income Before Cumulative Effect of Accounting Change and Extraordinary Items 2.58 2.71 3.12 Cumulative Effect of Accounting Change - - - Extraordinary Items - - - Net Income (Loss) 2.58 2.71 3.12 Dividends Per Share of Common Stock Declared Basis 1.68 1.575 1.175 Paid Basis 1.66 1.55 1.025 Common Stock Dividend Payout Ratio - ** 65.12% 58.12% 37.66% Book Value Per Share of Common Stock (year-end) 24.38 23.39 22.26 Market Price Per Share of Common Stock High 23 3/8 24 7/8 20 13/16 Low 19 1/2 20 5/16 11 7/8 Close 22 1/4 22 3/8 20 1/2 Price Earnings Ratio (year-end) 8.62 8.26 6.57 Number of Common Shareholders (year-end) 2,061 1,919 1,933 * Consolidated income before cumulative effect of accounting change and extraordinary items. Includes AFUDC and Deferred Return on Seabrook Investment. Excludes all Seabrook write-offs in 1985 and 1986 and all regulatory write-offs in 1995. ** Before regulatory write-offs in 1995. Consolidated Financial Statistics (Continued) 1987 1986 Capitalization Including Bank Borrowings (year-end) Debt (including amount due within one year) 49.32% 55.97% Preferred Stock (including amount due within one year) 8.32% 7.92% Common Shareholders' Equity 42.36% 36.11% Times Interest Earned - * Before Income Taxes 2.27 2.31 After Income Taxes 1.69 1.92 Times Interest and Preferred Dividends Earned - * After Income Taxes 1.49 1.73 Embedded Cost of Long-Term Debt (year-end) 10.98% 11.56% Embedded Cost of Preferred Stock (year-end) 11.20% 11.12% Common Shares Outstanding (year-end) 1,862,478 1,858,472 Earnings Per Share of Common Stock (average shares) Income Before Cumulative Effect of Accounting Change & Extraordinary Items 1.59 3.43 Cumulative Effect of Accounting Change .45 - Extraordinary Items - (1.38) Net Income (Loss) 2.04 2.05 Dividends Per Share of Common Stock Declared Basis .80 .525 Paid Basis .75 .35 Common Stock Dividend Payout Ratio - ** 39.22% 25.60% Book Value Per Share of Common Stock (year-end) 20.41 19.18 Market Price Per Share of Common Stock High 15 7/16 16 Low 11 1/2 9 3/4 Close 12 9/16 14 1/16 Price Earnings Ratio (year-end) 6.16 6.86 Number of Common Shareholders (year-end) 2,045 2,188 * Consolidated income before cumulative effect of accounting change and extraordinary items. Includes AFUDC and Deferred Return on Seabrook Investment. Excludes all Seabrook write-offs in 1985 and 1986 and all regulatory write-offs in 1995. ** Before regulatory write-offs in 1995. 1996 Sources of Income Millions of Dollars (Total $57.6) and Percent of Total Other Income -- $2.7 Million [4.7%] Residential -- $20.0 Million [34.7%] Commercial -- $16.4 Million [28.5%] Industrial -- $10.1 Million [17.5%] Other Electric Sales -- $8.4 Million [14.6%] 1996 Distribution of Income Millions of Dollars (Total $57.6) and Percent of Total Retained Earnings -- $(.9) Million [(1.6%)] Fuel & Purchased Power -- $31.8 Million [55.2%] Wages and Employee Benefits -- $6.9 Million [12.0%] Taxes -- $3.7 Million [6.4%] Other Operating Expenses -- $9.6 Million [16.7%] Interest -- $3.5 Million [6.1%] Common Dividends -- $3.0 Million [5.2%] (Pages 30-31) MAINE PUBLIC SERVICE COMPANY and Subsidiary Consolidated Operating Statistics 1996 1995 1994 Operating Revenues Residential $19,961,192 $19,080,662 $19,646,681 Commercial and Industrial - Small 16,420,167 15,723,439 15,614,453 Commercial and Industrial - Large 10,111,758 9,437,409 9,225,131 Municipal Street Lighting 538,890 524,616 517,793 Area Lighting 273,985 272,896 271,115 Other Municipal and Other Public Authorities 710,106 903,370 2,105,933 Other Electric Utilities 6,893,598 7,573,360 8,481,483 Other Operating Revenues (Revenue Adjustments) 2,354,469 1,762,974 2,505,496 Total Operating Revenues $57,264,165 $55,278,726 $58,368,085 Number of Customers (average) Residential 28,515 28,385 28,300 Commercial and Industrial - Small 5,541 5,465 5,418 Commercial and Industrial - Large 15 15 16 Municipal Street Lighting 38 38 38 Area Lighting 1,059 1,048 1,048 Other Municipal and Other Public Authorities 5 5 8 Other Electric Utilities 10 9 9 Total Customers 35,183 34,965 34,837 Net Generation, Purchases and Sales (thousands of kilowatt-hours) Net Generation: Steam 10,201 22,867 18,559 Hydro 168,993 121,252 118,759 Diesel (674) 1,046 (153) Purchases: Nuclear Generated 249,083 9,718 326,334 Fossil Fuel Generated 372,431 508,266 290,172 Inadvertent Received (Delivered) 741 (1,449) 651 Total 800,775 661,700 754,322 Losses, Unaccounted for and Unbilled 33,303 36,411 42,880 Company Use 1,517 1,490 1,518 Electricity Sold 765,955 623,799 709,924 Sales: Residential 169,298 168,640 175,685 Commercial and Industrial - Small 163,804 165,914 167,485 Commercial and Industrial - Large 134,588 128,478 127,327 Municipal Street Lighting 1,658 1,655 1,642 Area Lighting 1,418 1,457 1,472 Other Municipal and Other Public Authorities 10,090 11,747 28,621 Other Electric Utilities 285,099 145,908 207,692 Total Sales 765,955 623,799 709,924 Average Use and Revenue Per Residential Customer Kilowatt-hours 5,937 5,941 6,208 Revenue $700.02 $672.21 $694.23 Revenue per Kilowatt-hour 11.79 cents 11.31 cents 11.18 cents Consolidated Operating Statistics 1993 1992 1991 Operating Revenues Residential $19,669,749 $18,704,900 $19,194,469 Commercial and Industrial - Small 15,177,992 13,787,720 13,991,693 Commercial and Industrial - Large 9,554,566 8,891,123 10,105,693 Municipal Street Lighting 512,439 499,814 512,640 Area Lighting 269,925 261,984 267,518 Other Municipal and Other Public Authorities 3,597,514 3,761,815 3,977,098 Other Electric Utilities 9,188,561 8,150,094 7,328,914 Other Operating Revenues (Revenue Adjustments) 2,505,466 2,626,190 2,460,062 Total Operating Revenues $60,476,212 $56,683,640 $57,838,087 Number of Customers (average) Residential 28,220 28,102 28,052 Commercial and Industrial - Small 5,364 5,261 5,205 Commercial and Industrial - Large 16 15 15 Municipal Street Lighting 38 38 38 Area Lighting 1,061 1,075 1,091 Other Municipal and Other Public Authorities 8 8 8 Other Electric Utilities 8 7 7 Total Customers 34,715 34,506 34,416 Net Generation, Purchases and Sales (thousands of kilowatt-hours) Net Generation: Steam 26,456 33,509 28,868 Hydro 148,719 130,407 135,619 Diesel 169 (636) (178) Purchases: Nuclear Generated 282,199 263,313 307,769 Fossil Fuel Generated 288,487 300,930 246,172 Inadvertent Received (Delivered) (1,053) (2,232) 1,861 Total 744,977 725,291 720,111 Losses, Unaccounted for and Unbilled 43,944 43,686 42,114 Company Use 1,542 1,462 1,499 Electricity Sold 699,491 680,143 676,498 Sales: Residential 176,732 176,814 176,028 Commercial and Industrial - Small 162,949 155,267 149,709 Commercial and Industrial - Large 135,029 129,981 139,931 Municipal Street Lighting 1,630 1,864 2,336 Area Lighting 1,482 1,538 1,591 Other Municipal and Other Public Authorities 53,021 58,388 57,687 Other Electric Utilities 168,648 156,291 149,216 Total Sales 699,491 680,143 676,498 Average Use and Revenue Per Residential Customer Kilowatt-hours 6,263 6,292 6,275 Revenue $697.01 $665.61 $684.25 Revenue per Kilowatt-hour 11.13 cents 10.58 cents 10.90 cents Consolidated Operating Statistics 1990 1989 1988 Operating Revenues Residential $18,189,325 $18,537,902 $17,787,713 Commercial and Industrial - Small 12,708,677 13,379,207 12,374,719 Commercial and Industrial - Large 10,115,772 9,785,058 9,673,266 Municipal Street Lighting 505,063 573,351 559,478 Area Lighting 262,845 288,378 285,979 Other Municipal and Other Public Authorities 3,611,220 3,736,851 3,546,473 Other Electric Utilities 9,649,398 10,980,817 9,244,874 Other Operating Revenues (Revenue Adjustments) 1,701,167 (62,314) 649,746 Total Operating Revenues $56,743,467 $57,219,250 $54,122,248 Number of Customers (average) Residential 27,983 27,737 27,358 Commercial and Industrial - Small 5,108 4,940 4,866 Commercial and Industrial - Large 15 17 18 Municipal Street Lighting 38 38 37 Area Lighting 1,114 1,155 1,166 Other Municipal and Other Public Authorities 8 8 8 Other Electric Utilities 7 8 7 Total Customers 34,273 33,903 33,460 Net Generation, Purchases and Sales (thousands of kilowatt-hours) Net Generation: Steam 59,252 91,361 81,583 Hydro 176,832 106,571 112,953 Diesel (186) 2,664 1,933 Purchases: Nuclear Generated 253,321 369,315 266,851 Fossil Fuel Generated 289,177 217,166 299,838 Inadvertent Received (Delivered) (151) 1,611 (677) Total 778,245 788,688 762,481 Losses, Unaccounted for and Unbilled 40,613 42,474 44,883 Company Use 1,559 1,723 1,555 Electricity Sold 736,073 744,491 716,043 Sales: Residential 178,011 178,668 176,680 Commercial and Industrial - Small 146,881 145,364 139,220 Commercial and Industrial - Large 155,782 145,307 148,220 Municipal Street Lighting 2,697 2,722 2,695 Area Lighting 1,643 1,580 1,585 Other Municipal and Other Public Authorities 57,034 59,190 59,268 Other Electric Utilities 194,025 211,660 188,375 Total Sales 736,073 744,491 716,043 Average Use and Revenue Per Residential Customer Kilowatt-hours 6,361 6,442 6,458 Revenue $650.01 $668.35 $650.18 Revenue per Kilowatt-hour 10.22 cents 10.38 cents 10.07 cents Consolidated Operating Statistics (Continued) 1987 1986 Operating Revenues Residential $15,948,095 $15,641,623 Commercial and Industrial - Small 10,700,466 10,077,605 Commercial and Industrial - Large 7,736,051 8,468,298 Municipal Street Lighting 541,853 526,156 Area Lighting 273,570 285,856 Other Municipal and Other Public Authorities 2,955,417 2,820,227 Other Electric Utilities 8,735,459 5,843,057 Other Operating Revenues (Revenue Adjustments) 527,707 159,303 Total Operating Revenues $47,418,618 $43,822,125 Number of Customers (average) Residential 27,074 26,855 Commercial and Industrial - Small 4,789 4,763 Commercial and Industrial - Large 17 17 Municipal Street Lighting 37 37 Area Lighting 1,238 1,323 Other Municipal and Other Public Authorities 8 8 Other Electric Utilities 7 6 Total Customers 33,170 33,009 Net Generation, Purchases and Sales (thousands of kilowatt-hours) Net Generation: Steam 71,649 61,533 Hydro 100,158 149,323 Diesel 572 (758) Purchases: Nuclear Generated 215,006 331,988 Fossil Fuel Generated 327,016 175,648 Inadvertent Received (Delivered) (432) (74) Total 713,969 717,660 Losses, Unaccounted for and Unbilled 43,377 42,076 Company Use 1,472 1,453 Electricity Sold 669,120 674,131 Sales: Residential 173,580 173,799 Commercial and Industrial-Small 131,535 125,742 Commercial and Industrial-Large 133,405 150,881 Municipal Street Lighting 2,744 2,751 Area Lighting 1,626 1,740 Other Municipal and Other Public Authorities 56,180 53,683 Other Electric Utilities 170,050 165,535 Total Sales 669,120 674,131 Average Use and Revenue Per Residential Customer Kilowatt-hours 6,411 6,472 Revenue $589.06 $582.45 Revenue per Kilowatt-hour 9.19 cents 9.00 cents (Chart) Year-End Capitalization (Percent) 1992 1993 1994 1995 1996 Total Debt 50.16 45.83 44.25 49.92 52.75 Common Equity 49.84 54.17 55.75 50.08 47.25 (Page 32) Board of Directors Maine Public Service Company's eleven-member Board of Directors is composed of ten 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 Audit Committee Budget and Finance Committee PAUL R. CARIANI President & Chief Executive Officer 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 David D. Daigle Farms, Inc. Fort Kent, Maine & Orlando, Florida Executive Compensation Committee RICHARD G. DAIGLE President & Chief Executive Officer Cold Brook Energy, Inc., President Daigle Oil Company Fort Kent, Maine Audit Committee Executive Compensation Committee J. GREGORY FREEMAN President & Chief Executive Officer Pepsi-Cola Bottling Company of Aroostook, Inc. Presque Isle, Maine Budget and Finance Committee Nominating Committee DEBORAH L. GALLANT President & CEO Dix-Gallant Associates Portland, Maine Executive Compensation Committee NATHAN L. GRASS President Grassland Equipment, Inc. Presque Isle, Maine Executive Compensation Committee J. PAUL LEVESQUE President & Chief Executive Officer J. Paul Levesque & Sons, Inc. (Lumber Mill) and Antonio Levesque & Sons, Inc. (Logging Operation) Ashland, Maine Pension Investment Committee WALTER M. REED, JR. President Reed Farms, Inc. Fort Fairfield, Maine Pension Investment Committee Budget and Finance Committee (Back Inside Cover) Transfer Agent The Bank of New York Shareholder Relations Dept. - 11E P. O. Box 11258, Church Street Station New York, NY 10286-1258 Tel. No. 1-800-524-4458 E-Mail: Shareowner-svcs@Email.bony.com Stock Registrar The Bank of New York Annual Meeting Tuesday, May 13, 1997 Form 10-K The Company will provide shareholders with copies of the Form 10-K upon request. 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@agate.net 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 Director and Officer Changes Over the last year, several departments were combined and reorganized into three lines of management, wholesale, retail, and administration, in order to improve efficiencies and prepare for a future of change and possible deregulation. Frederick C. Bustard, previously Vice President of Engineering and Operations, was named Vice President of Power Supply and Environment. He now directs the efforts of the Company's wholesale operations. Engineering and operations functions, including retail sales, are now led by Vice President of Customer Service Stephen A. Johnson. Walter J. Elish, Director of Economic Development, was hired in October, 1996 to step up efforts in spurring economic growth and development in our service territory. Joining forces with community economic development councils, Walt is coordinating various expositions, trade fairs, direct mail, and other business recruitment functions to attract development to the northern Maine region. (Back Outside Cover) 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@agate.net Exhibit 16 Deloitte & Touche LLP 125 Summer Street Boston Massachusetts 02110-1617 Telephone: (617) 261-8000 Facsimile: (617) 261-8111 March 8, 1996 Securities and Exchange Commission Mail Stop 9-5 450 5th Street N.W. Washington, DC 20549 Dear Sir/Madame: We have read and, except as indicated in the following sentence, agree with the comments in Item 4 of Form 8-K of Maine Public Service Company dated March 8, 1996. We have no basis to agree or disagree with the statements made in (a) the second, third, fourth, fifth and sixth sentences of the first paragraph, and (b) the fourth paragraph. Yours truly, /s/ Deloitte & Touche LLP Deloitte Touche Tohmatsu International Exhibit 99(n) STATE OF MAINE Docket No. 95-052 PUBLIC UTILITIES COMMISSION June 26, 1996 MAINE PUBLIC SERVICE COMPANY ORDER Proposed Increase in Rates (Rate Design) TABLE OF CONTENTS I. SUMMARY OF DECISION . . . . . . . . . . . . . . . . . . . . . . . 4 II. INTRODUCTION . . . . . . . . . . . . . . . . . . . . . . . . . . 4 A. Overview of the Case . . . . . . . . . . . . . . . . . . . 4 B. Background . . . . . . . . . . . . . . . . . . . . . . . . 6 C. Note on Precedent . . . . . . . . . . . . . . . . . . . . . 7 III. MARGINAL CUSTOMER COSTS . . . . . . . . . . . . . . . . . . . . . 9 A. Explanation of Marginal Cost and Rate Design Concepts . . . 9 B. Positions of the Parties . . . . . . . . . . . . . . . . . 11 1. MPS and McCain's . . . . . . . . . . . . . . . . . . 11 2. Public Advocate . . . . . . . . . . . . . . . . . . 12 3. Advocacy Staff . . . . . . . . . . . . . . . . . . . 12 C. Analysis . . . . . . . . . . . . . . . . . . . . . . . . . 13 1. MPS . . . . . . . . . . . . . . . . . . . . . . . . 14 2. OPA . . . . . . . . . . . . . . . . . . . . . . . . 14 3. Staff . . . . . . . . . . . . . . . . . . . . . . . 16 IV. MARGINAL TRANSMISSION AND DISTRIBUTION COSTS . . . . . . . . . . 18 A. Methodology: Reliability Index vs. Vintaged Plant . . . . 18 1. The Reliability Index Method . . . . . . . . . . . . 18 2. The Vintaged Plant Method . . . . . . . . . . . . . 18 B. Unit Costs . . . . . . . . . . . . . . . . . . . . . . . . 18 1. Marginal Unit Transmission Cost . . . . . . . . . . 18 2. Marginal Distribution Capacity Cost . . . . . . . . 19 a. Method . . . . . . . . . . . . . . . . . . . . 19 b. Positions of the Parties . . . . . . . . . . . 19 c. The MPS Response to Staff and OPA Criticism . 20 d. Transmission and Dist. O&M Marginal Costs . . 21 e. The Significance of Statistical Tests of the Regression Equations . . . . . . . . . . . . . 21 C. Analysis . . . . . . . . . . . . . . . . . . . . . . . . . 22 D. Total Costs and Allocation . . . . . . . . . . . . . . . . 23 1. Distribution . . . . . . . . . . . . . . . . . . . . 23 a. Positions of the Parties . . . . . . . . . . . 24 b. Analysis . . . . . . . . . . . . . . . . . . . 26 c. Data Quality . . . . . . . . . . . . . . . . . 27 d. Invitation to File Updated Class NCP Data . . 29 2. Transmission . . . . . . . . . . . . . . . . . . . . 30 a. Analysis . . . . . . . . . . . . . . . . . . . 31 V. MARGINAL ENERGY COSTS . . . . . . . . . . . . . . . . . . . . . 32 Analysis . . . . . . . . . . . . . . . . . . . . . . . . . 33 VI. MARGINAL GENERATION CAPACITY COSTS . . . . . . . . . . . . . . . 34 Analysis . . . . . . . . . . . . . . . . . . . . . . . . . 36 VII. REVENUE RECONCILIATION . . . . . . . . . . . . . . . . . . . . . 37 A. EPMC and Other Reconciliation Methodologies . . . . . . . 37 B. OPA's Proposed Generation Allocator Method . . . . . . . . 38 C. Conclusion . . . . . . . . . . . . . . . . . . . . . . . . 40 VIII. RATE STABILITY AND RATE DESIGN DETERMINATION . . . . . . . 41 A. Rate Design Determination . . . . . . . . . . . . . . . . 41 B. Rate Design Policy Issues . . . . . . . . . . . . . . . . 43 IX. CONCLUSION . . . . . . . . . . . . . . . . . . . . . . . . . . . 46 APPENDIX A . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48 Procedural History . . . . . . . . . . . . . . . . . . . . . . . . . . 48 I. SUMMARY OF DECISION In resolving this matter of rate design for the Maine Public Service Company ("MPS" or "the Company"), we largely adopt the analysis and recommendations developed by Advisory Staff but further modify the Advisors' proposed rate design to comport with our judgment on fair allocations to classes. In so doing, we find that the Advisory Staff has identified marginal cost results that provide a reasonable starting point for designing rates, but because of data, methodological, and rate stability concerns, we will not order full implementation of the marginal cost results. We find that conservative rate design changes are reasonable due to data and methodological concerns and to avoid further rate shock to customers who already face three further rate increases in the next four years. The class revenue requirements are shown on Exhibit 1 attached hereto. The reader should note that the figures shown in Exhibit 1 are stated relative to rate levels in December, 1995. Consequently, it is necessary to subtract 4.4% increase already in effect for all classes as of January 1, 1996 in order to arrive at the incremental increase or decrease that will result for any class as a result of this Order. Finally, recognizing that the distribution marginal cost results in this case were made less reliable by outdated and mismatched non- coincident peak (NCP) data, we invite the Company to present revised NCP data for consideration in a limited proceeding for additional adjustments to this rate design for implementation in February, 1998, if warranted at that time. We would also consider rate design flexibility proposals at that time, if proposed by any party. II. INTRODUCTION The Procedural History for this proceeding is contained in Appendix A to this Report. A. Overview of the Case This case is both overdue and timely. Rate design review for MPS is overdue, given the passage of time since its last rate design case and the changes that have occurred within the Company's service territory over the last 10 to 15 years. It is timely to do so now because of the changes that are now occurring in the electric industry. This case and the related rate plan establishing a multi-year revenue requirement will set the starting point for MPS and its customers' participation in an increasingly competitive electricity market. This case contained a high degree of controversy over the Company's presentation of its case in this proceeding. The Company has acknowledged that it prepared its cost studies and rate design proposal using data, methodology, and analysis from preparation for its last rate design proceeding in 1987 (including class usage data from the early 1980s. The Company's proposals also did not reflect or address significant, more recent precedent on rate design methodologies and policies. /1 These facts diminished the value of this ratesetting exercise and its results. Although the Company made several subsequent modifications as the case progressed, incorporating portions of updated data or methodologies as the Company was able to collect or analyze more recent data available to it, in our view, certain infirmities, such as the quality of the NCP data, have not been adequately redressed. /2 This circumstance, unfortunately, has resulted in a proceeding that makes difficult the confident delivery of a comprehensive redesign of rates and contributes to our decision not to move further toward full EPMC results. While we are cognizant of the Company's small size and minimal staffing levels, the quality of a ratemaking decision depends greatly on the quality of supporting evidence in a case, and all -- parties, decisionmakers, and customers -- are impacted by this circumstance. Nonetheless, while the determination of a reasonable and fair rate design is never free from doubt, we are confident that our conclusions have taken into account the uncertainties inherent in the evidence and provide a reasonable basis for some modest rate design changes. The risk of basing some changes on relatively poor data is no greater, perhaps, than the continued risk of perpetuating a rate design based on even older data and methodologies that this Commission no longer uses. We do not wish to suggest that the Company has otherwise not performed adequately. We recognize that errors will occur, particularly when working under time pressures, and some compromises in data or analysis may be necessary in certain circumstances. We recognize, too, that ultimately many rate design decisions are a matter of analytic or policy judgment about which experts and policy makers may disagree. All of the witnesses in this case have given us the benefit of a full understanding of the differences in how they have applied that judgment and how they view the applicability of the evidence for the outcome of this case. It is our task, then, to sort through the facts and argument to determine how to establish just and reasonable rates for the Company and to make our policies as clear as possible. B. Background MPS's last rate design case, Docket No. 87-009, set class revenue requirements based on embedded cost studies but based intraclass rate elements on marginal cost analysis. The case was resolved by a stipulation in which MPS agreed to conduct further class load research (some of which was used in this case). Subsequent revenue increases have been applied across-the-board, in effect perpetuating a rate design based on embedded cost principles. In the intervening years between Docket No. 87-009 and this case, the Commission fully adopted and developed its marginal cost methodologies for electric rate design, primarily in Docket Nos. 89-068 and 92-315(I), both involving Central Maine Power Company. Prior to Docket No. 89-068, marginal costs had only been used to establish rate elements within rate classes. In Docket No. 89-68, marginal cost, rather than embedded cost, was first used to allocate revenues to classes. This change in rate design policy was based, in part, on the expectation that marginal cost allocation would be easier and less complex to do, and the belief that it would be a less arbitrary method of assigning costs to classes than the embedded methodology which relied heavily upon judgments about how to divide up responsibility for common costs. With marginal cost methodology, unit cost figures could be calculated. /3 In Docket No. 92-315(I), the Commission set out to find the general utility planning strategy that best comports with the public interest, and to develop a set of general guidelines that can be used by CMP in a subsequent case to translate that strategy and its underlying costs into a specific rate design proposal. /4 The case was ultimately stipulated by most of the participating parties. However, in its final Order, the Commission delineated several cost and policy findings related to the electric industry in general and to ratesetting in this jurisdiction. Docket No. 92-315(I) was designed to be a precursor to conducting a rate design case for CMP, /5 resolving foundational cost and policy issues. Notably, in 92-315(I), while the Commission found insufficient reason to approve CMP's proposed declining block rate, the Commission did agree that there no longer appeared to be a basis for requiring inclining block rates. The Commission also rejected CMP's proposal for optional rate classes reaffirmed existing ratesetting policies, further defined planning horizons for determining costs and designing rates, and endorsed particular methodologies, including the modified peaker method, for use in CMP's next marginal cost study. C. Note on Precedent There has been much discussion in this proceeding among the parties regarding the appropriate methodologies for marginal cost rate design for electric utilities. Both the Staff and the Company have asserted that the methodologies they have used have been "approved" by the Commission and, therefore, provide authoritative precedent. In general, a stipulated result does not have (and is not intended to have) the same precedential significance that a litigated resolution will have. That is because stipulated results, more often than not, involve compromises by the parties made to resolve issues that would otherwise consume much time and resources in litigation, and as a hedge against the uncertainty of the end result if left in the hands of the decisionmaker. The ultimate significance of the parties' eagerness to claim the authority of precedent can be distilled to the realization that, as a general matter, regulatory policy is accretive, building upon prior determinations. Prior approvals legitimize current and similar proposals and help persuade the decisionmaker. Commissions will recognize and employ current, established policies even as they work to form new ones for the future. Consequently, as with all regulatory determinations, while another utility may not be absolutely bound to apply methodologies endorsed by the Commission in the most recent prior proceedings, insofar as any utility proposes to depart from that precedent, it will bear the burden to persuade the Commission that it is reasonable to do so. In this context, it is useful to realize that Docket No. 92- 315(I) is not adequately described as a case resolved by stipulation of the parties, for while some issues were resolved by stipulation, the Commission explicitly issued an Order containing many findings and policy determinations of its own on several issues of fundamental importance to guide future electric rate design. Consequently, the case did provide important regulatory policy statements and precedent on those issues. III. MARGINAL CUSTOMER COSTS A. Explanation of Marginal Cost and Rate Design Concepts To promote clarity in what may be a complex and confusing discussion, we begin with a discussion of the concepts involved in marginal cost economic theory as well as their applicability to rate design and the specific cost elements therein. In economics, marginal cost is defined in terms of the total cost concept. The total cost curve gives the sum of all costs incurred to produce a given level of output. Total costs include fixed costs (e.g., for physical plant), which are incurred whether or not any output is produced, and variable costs (e.g., labor and raw materials), which are incurred as a result of production. Opportunity costs are not included in total cost. Marginal cost is defined as the change in total cost associated with an additional unit of output. Both the total and the marginal-cost curves are defined over an entire output range, and the marginal cost associated with a given unit of output does not depend on whether or not the unit has actually been produced. Rate design involves classifying and analyzing the various components of electric utility total costs. Specific cost elements are identified (e.g., transmission capacity, distribution capacity, generation capacity, energy, and customer costs), and a per unit cost for each cost element is determined. Once known, the cost elements can be used to design rates that will collect total costs per year, based on the units of each cost element (or "billing determinants") used by a rate class during a year. For customer costs - the costs associated specifically with establishing and continuing service for a particular customer - there are two general types of cost element. One represents the cost of physical capital used to serve a customer (e.g. meters and service drops), usually incurred on a one-time basis. The other represents ongoing expenses incurred in billing and servicing an account. We will refer to these cost elements as equipment customer costs and account customer costs respectively. Equipment customer costs are actually quite variable from one customer installation to another, and there can even be disagreement on whether certain costs (e.g., some poles and transformers) should be classified as customer costs or as distribution capacity costs. In this proceeding all parties agree that the appropriate proxy for equipment customer costs is the purchase-plus-installation costs of a meter and service drop. Let us assume that this total is $M. The meter cost, $M, is a cost element per life of the meter, say 35 years. A meter cost per year is an annualized level amount that will amortize $M over 35 years. The meter cost per year can be thought of as similar to a mortgage payment, or a rental fee, that will pay for the meter over its service life. /6 There are two major approaches to establishing a dollar amount for cost elements. The first is to use historical (or "embedded") costs actually incurred. The second, more modern, is to use marginal costs, i.e., the cost of the next unit. A straightforward and plausible application of the historical approach to equipment customer costs would be to find the average purchase-plus-installation cost of meter and service drop of the utility, and then annualize that amount to determine equipment customer cost per year. This average cost will be different than the actual cost caused by specific customers for almost every customer; few if any customers impose precisely the average cost on the utility. A straightforward and plausible application of the marginal cost approach would be to use the purchase-plus-installation cost of a new meter and service drop, annualized, to establish the marginal equipment customer cost per year. /7 If all customers were charged this amount in rates only the new customers would be paying the costs that they imposed. Others would be paying more, or perhaps less, depending on the specifics of the costs that they imposed in the past. If all customers were paying a marginal equipment customer cost in rates, this charge could be thought of as an equipment rental charge based on the current replacement cost of their equipment. Current rate design policy in Maine is to use marginal costs to determine the dollar amount for rate elements. One rationale for this involves giving the "right" price signal. The underlying theoretical argument appeals to allocative efficiency: if some consumer is willing to pay the costs of producing the next unit, then that unit will be supplied. (Strictly speaking, this is the textbook argument for short term marginal cost pricing. It would normally count against pricing at long term costs.) Another rationale offered for the use of marginal costs involves cost causation, because marginal cost pricing results in customers paying the costs that they actually impose on the utility. This justification, however, may be misleading, in that historical costs are the costs that customers have caused, while marginal costs are the costs that will be imposed by future expansion, which may be caused more by new customers than by the increased use of existing customers. An historical cost approach to rate design would generally set rate elements equal to average historical costs for a cost element (per year). When these rate elements are applied to billing determinants that represent the unit use of each cost element, they will collect a total amount that covers the utility's total historical costs (per year). A marginal cost approach to rate design would set rate elements equal to marginal costs. When marginal cost rate elements are applied to the same set of billing determinants, the total amount collected, marginal cost revenues, may be higher or lower than the utility's total costs (or revenue requirement). This requires an adjustment to marginal cost rates, the "reconciliation," in order to design rates that collect the correct amount of total costs. In Maine we have used EPMC (equal percentage of marginal costs) to perform the reconciliation, which simply marks up (or down) all rate elements by the same percentage, so that the total collected will equal the revenue requirement. This procedure preserves marginal cost price ratios, but does not price at marginal cost. In this proceeding, the resulting rates will be about twice the marginal costs. B. Positions of the Parties 1. MPS and McCain's MPS calculates marginal equipment customer costs using the "straightforward" marginal cost method outlined in the preceding section. According to the Company's calculation, totals for meter and service range from about $250 per customer for the residential class to about $20,000 per customer for the H-T industrial class. The annual costs range from about $27 per residential customer to about $2,100 for an H-T customer. Totals for all account marginal customer costs range from about $51 per customer per year for residential customer to about $2,200 for an H-T customer. Total marginal customer costs (equipment costs plus account costs per customer per year) range from about $78 for residential customers to about $4,300 for H-T customers. These totals are then used to calculate marginal customer cost revenues, which are then added to all other types of marginal costs, to obtain total marginal cost revenues for each class. Finally EPMC is performed and the required percentage rate change for each rate class is calculated. Marginal customer costs as a percentage of total marginal costs are about 17% for the residential class and about 1% for the H-T class. This reflects the difference in the number and size of customers in these classes. Intervenor McCain Foods (McCain's) supports the position of MPS on marginal customer costs. 2. Public Advocate The Office of the Public Advocate ("The Public Advocate" or "OPA") calculates equipment customer costs using a variant of the historical method outlined in Section A above: "Marginal customer capacity cost should be based upon the total of embedded customer costs." However, instead of using an average of historical costs of meters and services, OPA uses a depreciated amount. OPA's witness Smith shows about $26 for meter cost and $44 for account cost for residential customers. MPS calculates about $68 and $178, respectively. The effect is similar for other classes. OPA then uses the same 35-year annualization factor that MPS uses (0.10740) to calculate the annualized amount. The result is an annualized meter customer cost of $7.67, while MPS calculates $26.67 for this cost. OPA's calculation of marginal account customer costs differs from MPS's calculation largely in the expense for customer service and information. After examining and revising MPS's data for this account and making a number of revisions, OPA concludes on the basis of regression analysis that there is no relationship between this type of expense and the number of customers. OPA therefore places zero in all entries for account customer costs thereby eliminating a very small expense item from its calculation of total marginal customer costs. OPA gives total marginal customer costs, per customer per year, ranging from about $49.50 for residential customers to about $3,340 for H-T customers. This compares with MPS's $78 and $4300 for the corresponding costs. OPA offers a number of criticisms of MPS's approach to marginal customer costs. First, existing customers do not impose the annualized costs of a new meter on the utility. Second, marginal cost price signals are not relevant for the decision to become a customer and might be prohibitive if used. Third, using MPS's marginal customer costs in combination with EPMC reconciliation will inappropriately allocate other costs. Finally, MPS's procedure treats existing customers as if they are new, as if all meters and services will "need to be replaced this year and again next year and again the year after." 3. Advocacy Staff Staff argues against applying marginal equipment costs for new customers to existing customers, as MPS does, on the theory that equipment for existing customers are sunk and, therefore, by definition cannot be marginal. Staff argues instead that an appropriate conception of marginal costs for existing customers would reflect the "ongoing marginal capital costs" of continuing to serve a customer already on the system. This ongoing marginal cost is the opportunity cost of having the capital equipment in place. The equipment could be used to serve another customer, as an alternative to purchasing and installing new equipment. In practice only meters, and not service drops, are reused, so Staff calculates the opportunity cost of an in-place meter. This calculation takes into account such costs as removing and refurbishing the in-place meter, subtracting these from the purchase cost of a new meter. This is the value to the utility of an in-place meter that could be used as alternative to a new meter. This opportunity cost is the ongoing marginal capital customer cost of an existing customer. Staff claims that this treatment of marginal costs for existing equipment as the opportunity cost of having such equipment in use is consistent with other marginal cost procedures used by this Commission. For example, the marginal cost of generation capacity is measured using the market value of that capacity, which is the opportunity cost of using it to serve the utility's customers. Staff calculates the market value (marginal cost) of meters, and then combines them with account marginal costs to calculate total marginal customer costs. These totals range from about $48 for residential customers to about $2,400 for H-T customers. These figures compare to $78 and $4,300 for MPS and $50 and $3,400 for OPA. Then total marginal costs by rate class and the remainder of the EPMC reconciliation are calculated. Staff's treatment of account marginal costs differs from that of MPS, which includes uncollectibles expense as a customer cost. Based on a regression analysis showing a very low R2, MPS determined that uncollectibles are not a marginal cost, and therefore omitted them from the study. Staff argues that these costs are marginal, since they are incurred at the margin and are largely related to the addition of customers. C. Analysis The differences among the parties on customer cost issues are largely conceptual. The parties agree that meters and service drops are the appropriate proxy for equipment costs, and there is little disagreement over the data. OPA disagrees with MPS on whether customer information costs should be treated as marginal, and Staff disagrees with MPS on whether uncollectibles costs are marginal. 1. MPS As noted above, MPS has performed a straightforward and conceptually orthodox calculation of marginal customer costs, using a methodology that has been endorsed by the National Association of Regulatory Utility Commissioners ("NARUC"). The resolution of this issue will depend both on the strength of the alternative methods endorsed by OPA and Staff and on our conclusions with respect to the ongoing validity of applying standard marginal cost ratemaking principles to this cost item. 2. OPA As noted above, OPA employs a variant of the historical cost method, using depreciated rather than original total meter and service costs in rate base, and then analyzing this cost using a 35-year factor. This is an inconsistent historical approach. It would have been consistent to use total original costs and a 35-year factor, or to use depreciated costs and an annualization factor based on average remaining meter life. Mixing costs that have been depreciated for a number of years with a full life annualization factor understates this cost. This is comparable to telling the bank that your level mortgage payment should now be cut in half, because you have paid off half the principal. In our view, this is a serious flaw in the OPA's customer cost proposal. Another difficulty is that this Commission has in a place a marginal cost rate design policy. To consider an alternative treatment of this cost item as OPA suggests, a justification for departing from standard cost allocation methodology is necessary. We must assess the strength of the reasons given by OPA for departing from this policy in the case of customer costs. First, OPA correctly points out that new customers do not impose the annualized costs of a new meter on the utility. However, existing customers do impose the annualized full costs of their meter when it was new. If cost causation is the rationale underlying this OPA argument, then its marginal cost amounts are too low, because they apply a 35-year annualization factor to an already depreciated cost. Furthermore, and more importantly, it is not assumed in the MPS calculation that existing customers imposed the annualized costs of a new meter. The costs of the new meter are used because that is what is dictated by the marginal cost methodology for this cost element. If there is a quarrel here it is with the marginal cost rate design methodology, not with any assumption about cost causation. Standard marginal cost methodology always, and in principle, uses costs of the next unit for valuing cost elements. All units are priced in relation to that cost, however dissimilar it may be from historical or depreciated costs. Second, OPA argues that a marginal cost price signal from this cost element is not relevant to the customer's service decision, and might be prohibitive if they were used. The annualized cost for meter and service in MPS's study, however, is $26.67, only a little over $2 a month - - and hardly prohibitive as a stand alone component of rates. It is also not clear why a price signal should not influence the service decision. Suppose the customer were deciding whether to install a new service for his barn or to extend his existing service. A customer charge could be the marginal cost consideration. Further, if marginal customer costs became prohibitive to some, the Commission could take this into account, weighing the benefits of mitigation measures against the value of economic decision-making through accurate price signals. Third, OPA argues that marginal customer costs will inappropriately allocate other costs via the EPMC reconciliation. For example, uneconomic generation costs responsible for the reconciliation gap will be overallocated to customer classes that have a relatively higher proportion of customer costs. /8 This effect, however, is intrinsic to marginal cost methodology, even if it does clash with some intuitive judgments about cost causation and fairness. While the Commission is always free to consider whether there are modifications of the marginal cost methodology that improve upon the current standard methodology, we decline to depart from the established methodology in this instance. Fourth, the OPA argues that the method used by MPS treats all customers as if they were new. On one interpretation this argument is the same as the first, above. If, however, we focus on language about treating all meters and services as if they will "need to be replaced every year," we apparently discover a fundamental misconception. MPS's treatment does not attempt to collect a full meter and service cost every year for every customer. Rather it develops an annualized cost reflecting a 35-year life so that the cost of the meter is collected over the life of the meter. On balance, none of the arguments offered by OPA persuade us to depart from our use of marginal costs as the starting point for rate design. 3. Staff As explained above, Staff's position rests on their conception of ongoing marginal costs for existing customers. Part of the supporting argument involves the claim that meter costs for existing customers are sunk and therefore cannot be the marginal costs for these customers. While Staff's discussion of opportunity cost as the proper measure of marginal cost has conceptual appeal and academic support where costs are genuinely "sunk," we do not agree that the opportunity cost approach should be used here. First, opportunity cost is not an ongoing cost in the sense of an expenditure that the Company incurs to serve existing customers, nor is it a component of the Company's total costs. It therefore cannot be part of a change in total costs, and similarly it cannot be a marginal cost in the usual sense. In reply to this criticism Staff could say that the ongoing marginal cost for existing customers is a component of total marginal costs. In this use, however, total marginal costs cannot be defined independently of the specific marginal costs (such as marginal meter customer costs) that are added to obtain the total. There is a circularity in the definitions of total and marginal costs in Staff's approach. The standard total cost concept can be independently defined, and then used to define marginal cost (as explained in Section A, above). Moreover, we do not agree that, for the purposes of marginal cost analysis, the cost of meters represents a "sunk" cost. The parties in this case agree that a net increase in customers is the proper proxy for marginal class usage. In order to increase the membership in the customer class by one, one new meter must be added - all existing meters (including refurbished meters no longer used by departing customers and returned to service for customers who replace those departing customers) are in use. The cost of the new meter to serve the incremental customer is no more "sunk," for marginal cost analysis, than the cost of a new car sitting on the dealer's lot. As a final observation, and an additional reason to decline to adopt the opportunity cost approach with respect to equipment customer costs, we note that Staff's marginal equipment customer cost is, in effect, a salvage value to the utility of an in-place meter, an amount that could be almost any percentage of new meter cost, or even zero, depending on the particulars. If it were zero, then equipment customer costs would be zero and would play no role in rate design. That result is, in our view, unacceptable on its face. Having rejected the OPA and Staff approaches, we are left with MPS's more conventional marginal cost approach to customer costs, and we will adopt it here. On two remaining matters of detail we will adopt the MPS proposal. The first is whether uncollectibles should be considered a marginal customer cost. We accept MPS's regression analysis as reasonable evidence that there is not a marginal cost relationship here. Furthermore, we are unpersuaded by Staff's argument that these costs are marginal because they are incurred at the margin and are largely related to new customers. /9 On the remaining issue, whether customer information costs are marginal, we believe it is reasonable to conclude that such costs would increase with the number of customers. The OPA's regression analysis or the assumptions used do not persuade us to change our conclusion. Consequently, we will adopt MPS's treatment of customer costs in its entirety. The degree of difference on customer cost issues among the various experts involved in this proceeding gives us further reason why, to the greatest extent possible, consistent with the protection of ratepayers, the Commission should get out of the pricing business. Free markets are better determinants of appropriate price levels. Where there are market failures we will remain involved, but, in general, we favor systems in which companies risking and customers spending their own money set prices. IV. MARGINAL TRANSMISSION AND DISTRIBUTION COSTS A. Methodology: Reliability Index vs. Vintaged Plant 1. The Reliability Index Method MPS has used a method originally referred to as the "Functional Subtraction Method" in the NARUC Electric Utility Cost Allocation Manual, /10 to separate growth-related additions from reliability-related additions to plant. In this proceeding, the method has been called the "Reliability Index Method." The Reliability Index Method requires that individual work orders be examined and classified as required for either load growth or reliability. Cumulative growth-related additions in dollars are plotted against actual loads in kilowatts over an 18-year period. A linear relationship is determined by a least squares regression. The slope of the resulting line is the unit cost. Both transmission and distribution unit costs are determined in this way. The Reliability Index Method was used by MPS in Docket No. 87-009. 2. The Vintaged Plant Method The Staff objects to MPS's use of the Reliability Index Method. The Staff has a strong preference for a method used by both CMP and Staff in Docket No. 92-315 called the "Vintaged Plant Method." Staff believes the process of separating growth-related from reliability-related plant investment to be too "judgmental" and "arbitrary." Instead of using data based on growth related investment, the vintaged plant method uses data based on net additions to plant that can be obtained directly from plant records. Unable to secure net additions plant data from MPS, Staff consultants, Swan and Psacharopoulos (S&P), modified the MPS Reliability Index Method to correct perceived infirmities. B. Unit Costs 1. Marginal Unit Transmission Cost S&P show that the period over which the transmission data is selected can have a significant impact on the slope of the regression curve, $63.76 for 1977-1994, $32.14 for 1980-1994, and negative $66.71 for 1986-1994. A longer time period, such as the 65 years used by CMP, should theoretically produce a more stable result. S&P elected to use forecast peak loads rather than actual peak loads since actual load growth has been highly variable, even negative in recent years. Another problem of concern to S&P was the lumpiness of transmission investment with large amounts in some years and virtually nothing in others. S&P elected to smooth the investment by using a 3-year moving average rather than single year investments. In Docket No. 92-315, CMP excluded investments in the 345 kV "backbone" transmission system because they believed that those investments should be considered to be part of generation capacity cost. S&P believe that MPS improperly included "backbone" transmission costs. However, since those costs could not be identified, no adjustment was made. The S&P adjustments produce a marginal unit transmission cost of $35.73 per kW compared to MPS's $63.76 per kW in 1994$. The Public Advocate accepts the MPS Marginal Transmission Cost. 2. Marginal Distribution Capacity Cost a. Method MPS used the same Reliability Index Method for marginal distribution capacity cost as for marginal transmission capacity cost. Staff has the same disagreements here as with marginal transmission cost. Both Staff and OPA have additional objections to the underlying data and its application. b. Positions of the Parties Staff S&P criticized MPS for using the 1986 index value of 0.44 to separate growth-related from reliability-related investments for the years 1977 through 1985 when only total investment data was available. Staff and OPA found the average index value of the years 1986 through 1994 of 0.68 would be more appropriate since it represents a much larger population of individually analyzed work orders. Staff and OPA corrected the data using the 0.68 index value. In rebuttal MPS accepted this correction as being appropriate. Public Advocate In deposition testimony, Gerow described how MPS "sampled" distribution investments by looking at accounts with large amounts of spending. The Public Advocate's consultant, Lee Smith, asserts that MPS provided no evidence that the sample was representative of the accounts that were not analyzed. Smith corrected a typographical error in the MPS calculation for 1994 and applied the same data modification as Staff, except that Smith did not change actual peak loads to forecast peaks. c. The MPS Response to Staff and OPA Criticism MPS questions the theoretical basis for the Vintaged Plant Method. MPS states that the method is based on the assumption that any change in the current value of total plant from one year to the next must be due to growth-related investments. MPS believes that the value could change due to upgrades in construction quality. MPS cites the fact that Staff was unable to produce any evidence that the Vintage Plant Method was recognized in any other jurisdiction or had been scrutinized by the Commission in Docket No. 92-315 where it had been accepted by stipulation of the parties. MPS stands by its use of the Reliability Index Method pointing out that the method is recognized by NERA in the Gray Book series and is discussed in the NARUC Cost Allocation Manual. MPS also disagrees with Staff's criticism of the process used by MPS in analyzing work orders and separating reliability from growth-related investments, citing the Deposition Testimony of Howard where the process was discussed. MPS points out that the separation was done by accountants under the supervision of and in close consultation with knowledgeable engineers. MPS also asserts that to the extent there may be errors of over or under estimating of reliability-related investments, the errors would tend to be offsetting. MPS believes that Staff's use of long-term forecast loads as the independent variable in the regression equations is improper because; (a) MPS uses annual budget forecasts as the basis for its construction planning not long-term forecasts, (b) actual loads better represent and are closer in timing to construction, and (c) Staff didn't use the 1992 forecast for the years 1992-1994 which recognized the closing of Loring AFB. The latter choice is a major reason why the Staff's resulting unit costs are lower than MPS. MPS accepts Staff's and OPA's correction of the use of a 0.68 reliability index in place of 0.44 for estimating the separation of reliability related investment from total investment for the years 1977- 1987, for which work orders were not available to be analyzed. MPS believes the fact that Staff's marginal cost result is below embedded cost is a further indication that Staff's result is too low. MPS cites that fact that Aroostook County has a less dense population than CMP's territory as justification of why the MPS marginal distribution cost is higher than CMP's. Conversely, MPS cites the fact that its transmission system is predominantly 69 kV compared to CMP's system at 115 kV as justification for MPS's marginal transmission cost being lower than CMP's. d. Transmission and Distribution O&M Marginal Costs Staff found that O&M regression equations had very poor R2 results, 0.14 for transmission and 0.02 for distribution. Expenditures seemed to be relatively constant from year-to-year, possibly more a function of year-to-year budgeting than load changes. MPS believes that there should be some amount of O&M that is load-related but admits that the data does not produce a convincing relationship. Finally, Staff recommended that the marginal O&M costs be set at zero, and MPS did not object. Since there is a poor regression R2 and the amounts are probably small, (less than $2.00/kW), we agree with Staff that marginal transmission and distribution O&M should be excluded from the calculation. e. The Significance of Statistical Tests of the Regression Equations We have examined the R2 calculations used to evaluate the relationship between load and investment in the Company and Staff analyses. We find that while Staff's adjustments to the data produced better R2 values, our confidence in their results did not increase correspondingly, because the use of forecasted load increases the linearity of the independent variable thereby yielding a better mathematical result. The procedure does nothing, however, to mitigate flaws in the dependent variable that result from a fairly arbitrary separation of growth- and reliability-related investment. C. Analysis Both transmission and distribution plant are constructed for a variety of reasons, primarily either to accommodate load growth or to improve reliability. It is thought that for purposes of determining the cost of constructing an additional unit (marginal capacity cost) to serve an increasing load, either for existing customers or new customers, only that construction cost necessary to serve load growth should be used in the calculation. The construction cost associated with reliability- related improvements should be excluded. In this proceeding, we are presented with two methods to produce marginal transmission and distribution capacity costs. The methods are similar in that they attempt to develop a relationship between construction expenditures and load over a time period of many years. This long term relationship is an attempt to solve the problem of wide swings in short-term costs from project to project due to size and uniqueness and varying leads and lags in timing with respect to load growth. Both methods have shortcomings. The Reliability Index Method requires a tedious analysis of the records of individual work orders to classify them as either growth related or reliability related. The results depend on many arbitrary and likely inaccurate judgments about the purpose of each project. The Staff's concerns about data reliability are justified but the relative size of errors or potential error has not been shown. The Vintaged Plant Method uses net plant cost as shown on the utility's books without the need for arbitrary judgments about growth versus reliability. However, the use of net plant requires the theoretical assumption that retirements of undepreciated plant can be used as a proxy for reliability-related plant since gross plant cost is reduced by each in the same way. It should be much easier to develop net plant cost data than data that has been purged of reliability-related costs. However, no party produced vintaged net plant data in this proceeding. Thus, we have no comparable results to consider. There are differences among the parties over whether the costs should be related to actual loads or forecast loads. There is a certain theoretical charm to using actual loads since plant construction will likely occur at a lesser or greater rate than forecast loads would dictate if the forecasts are typically inaccurate. In the MPS situation, actual load growth is far from uniform. It levels off and then declines in recent years producing a relationship to construction cost that can hardly be considered linear and amenable to least squares regression. On the other hand, the Company's budget represents the Company's own best judgment of the costs it will need to incur to accommodate growth, and for that reason may also serve as an appropriate basis for our calculations. While it is not obvious on this record which is the better methodological approach, for purposes of this case, we will adopt the Advisors' recommendation to use forecast loads in part because they result in a better R2 value. Having so decided, we will also note that in Docket No. 92-315, CMP found that a non-linear, logarithmic equation provided a better fit for relating investment cost to load. It cannot be said for certain that the relationship of construction cost to load growth is linear regardless of whether loads are actual or forecast. In addition, the record is not clear with regard to the causation and timing of construction expenditures. Rather than being directly related to load growth, the Company argued that construction spending may be more a function of the utility's annual budget which is tied to expectations of its earnings and cash flow. It is certain that expenditures occur in a "lumpy" way over time. Staff's rolling 3-year average is an appropriate way to smooth "lumpiness" and at the same time show an improved fit of the regression equation. Staff's improvements to the MPS marginal transmission cost study effectively reduce the unit cost by 44%. Distribution unit cost is reduced by 28%. The reductions are significant showing that different approaches to the analysis can produce results that substantially impact overall revenue allocations. With less-than-complete confidence in their accuracy, we will accept Staff's resulting unit costs. Although stipulated for use in Docket No. 92-315, we are not satisfied that we are able to sufficiently examine the Vintaged Plant Method or its application to this proceeding on this record. Thus, we are not prepared to endorse the Vintaged Plant Method, over other methods, as a matter of general rate design policy at this time. D. Total Costs and Allocation 1. Distribution Our findings with regard to the unit marginal costs for distribution are set forth above. Calculating the total amount and allocation of the distribution marginal costs to the individual rate classes requires examination of a variety of issues. Each of the parties has presented its calculations based on varying methodologies and data interpretation and manipulation techniques. However, Staff and the Company seem to agree on the key element of the method that should be used in such calculation (i.e., 12 NCP), provided that reliable data are available. The calculation of total marginal distribution costs by each party shows the relative significance of this category of costs. The Company's total distribution costs represent 13.1% of its total marginal costs, the Staff amount represents 10.0%, and the OPA's proposed distribution total amount equals 12.7% of the total marginal costs presented by his witness. In addition, the allocation of costs to the individual rate classes shows wide variations among the parties. For example, the Company assigns 55.3% of its total distribution costs to the residential class, the Staff allocation to residential is 47.3% of total distribution costs, and the OPA assigns 49.9% of total distribution marginal costs to residential customers. Accordingly, we view this category as having both a relative and an absolute significance in arriving at our overall marginal costs result. In addition, as discussed more fully below, this category of costs brings into focus the serious concerns expressed by the Staff and the OPA regarding the quality of the data presented by the Company. While our decision in this case is based on the record before us, we also will allow an opportunity for a limited look at updated data and for parties to provide support for their proposed method of employing those data. a. Positions of the Parties The Company has proposed a calculation and an assignment of total distribution marginal costs that is based on weighting the 12 monthly Non-Coincident Peaks (NCP) for each class by the proportional responsibility (PR) method. The Company's calculation involves multiplying the PR-weighted 12 NCPs of each class by the Company's calculated marginal cost per Kilowatt (KW). The PR weighting method is a capacity-related cost allocation mechanism that uses system load data to calculate a demand responsibility for each month, day or hour to be used as the cost allocator in cost of service studies. MPS calculates an on-peak and an off-peak responsibility for each month, then sums these to get each month's total PR, which is then multiplied by the monthly NCP to arrive at the weighted NCP. The unit costs are determined and applied separately to the primary and secondary level distribution customers based on their proportionate share of the monthly NCPs. The individual class marginal costs are then summed to arrive at total company marginal distribution costs. The Company first made use of the PR-weighted 12 NCP method in its Rebuttal filing. It asserts that this method assigns cost responsibility among the time periods and among the classes in relation to actual cost causation. The Staff concurs that use of NCP data for assigning distribution marginal cost responsibility is theoretically correct, but as will be discussed below, Staff felt it could not rely on the NCP data that MPS presented. However, Staff does not agree with the PR weighting method, stating that it is a rather old procedure that was developed to facilitate the allocation of embedded costs. The Staff's recommended method looks at each class's maximum demand on the distribution system, no matter when it occurs, but by using and weighting equally all 12 months, it also considers seasonal cost causation factors. All parties agree that distribution demand costs are likely incurred to meet demand at times other than just at the annual coincident peak, so that NCP data is preferable to CP for use in any allocation scheme. While the Staff endorses the use of 12 months of NCP data to allocate marginal distribution cost responsibility among classes, it finds the load data supplied by MPS to be of such poor quality as to render it useless for assigning costs in this case. Staff asserts that the fact that the Company has mixed data from several sources and from different time periods gives results that are anomalous, inconsistent or impossible by definition. Specifically, Staff points out that load data for the residential class is taken from a 1979 study and combined with CP data from a 1990 study. While this technique resulted in only one of the months (July) actually showing a diversity factor of less than one (which is by definition, an impossibility), Staff concludes that other months may have similar errors embedded in their results which are less obvious. Staff also asserts that the commercial class results suffer from similar problems of staleness and lack of support. Further, the NCPs for the ES and EP-T classes were developed not through use of monthly estimated diversity factors, but by use of a 2-month average factor which may not be representative of the whole year. The Company seems to agree that its load data is less than perfect, but asserts that it has arrived at a reasonable NCP approximation that is usable in designing rates. The OPA's witness, Lee Smith, has used a single NCP allocator to assign cost responsibility among the various classes. She argues that the distribution system is sized to meet the maximum demand placed upon it at any one time by each customer class, and that this cost causative responsibility is best reflected by using the individual class annual NCPs multiplied by the marginal distribution cost per KW. In her view, usage other than at the time of class annual peak is largely irrelevant. As with the Staff, Ms. Smith was troubled by the inconsistencies and anomalies present in the load data supplied by MPS. To arrive at the class NCPs used in her analysis, she made numerous modifications to the Company's class results, in many cases relying on her analytical experience with similarly situated companies to estimate a value. The OPA asserts that the results presented by Ms. Smith are a reasonable compromise between the Staff's and the Company's positions, and would allow the Commission to apply the theoretically correct NCP methodology with class NCPs that are reasonable approximations. b. Analysis We find the load data problem troubling. It appears that the Company revised its CP results at the Rebuttal stage of the case and did not present any NCP numbers until that point in the proceeding. Those NCP results engendered a high degree of discomfort among the other parties. The Company attempted to introduce very late in the case further revised (1994) load research data. Those data were excluded from the record because of their untimeliness. It would have been preferable for the Company to have provided these data at a much earlier stage. Certainly, MPS should have been aware, prior to filing this case, of the Commission's preference for the use of NCP data in allocating distribution marginal costs. A utility always has the right to seek to vary from a Commission's expressed policy or preference, so long as it can support its arguments on theoretical or factual grounds, but it should not simply ignore prior Commission policy. We agree with many of Ms. Smith assessments with respect to the quality of the load data and commend her efforts to salvage something from the NCP results put forth by the Company. We also agree with the Staff that the class NCP data is sufficiently flawed as to make it unreliable for establishing marginal cost-based rates. While Ms. Smith skillfully employed her experience and judgment in developing alternative data inputs, we are concerned that in several areas her results may not yield reasonable approximations of the true values being sought. To ensure that the current regulatory policy in this jurisdiction is clear, we reconfirm our finding from Docket No. 92-315 that class NCP data is the proper measure to use in allocating marginal distribution costs among customer classes. We are not able to make a finding at this time as to whether the single NCP method, as asserted by OPA witness Smith, is the appropriate allocator, or whether the 12 NCP methodology advocated by Staff and MPS is more appropriate. We find some merit in the assertions made by both Ms. Smith and the opposing viewpoint of Staff witnesses Swan and Psacharopoulos on the issue. There is considerable logic in Ms. Smith's assertion that the distribution system is built to meet the highest class demand whenever that occurs. However, we have no evidence that the annual NCP for each class provides a good approximation of how individual circuits, which serve customers from several classes, are used. The Staff's proposed weighting technique could present a better measure of the overall use of the system. Their recommendation may provide a way of accounting for the fact that individual distribution circuits serve more than one class of customer, each of whom may put different demands on the system at different times of the year and whose combined demand may drive the level of investment in distribution plant. The weighting by proportional responsibility, as advocated by MPS, gives additional weight to the times of the year when the system generating and transmission portions of the utility system are most heavily utilized, but it may be that some parts of the distribution system are most heavily stressed at other times. We believe that the issue needs to be explored further, as the record before us does not adequately address the issues involved. As a matter of overall policy we are unable to make a conclusive finding based on the record before us on whether it is more appropriate to use 1 NCP or 12 NCP. To establish marginal distribution costs for this docket, however, we will employ the Staff's proposed method of applying equal monthly weighting to the calculation of each class's probable contribution to each month's CP. As explained above, the use of CP's is not our preferred method, but given the infirmities of the NCP data in the record, we accept Staff's proposed method as the best available alternative. In addition, this method has been employed in other rate design cases when NCP data was not available to develop rates that were implemented by the Commission. As discussed further below, it also appears that the CP data does not suffer from the serious defects that are present in the Company's NCP data. We will discuss later in this report how the use of less-than-ideal data and methods affects our overall decision. c. Data Quality Staff witnesses presented many criticisms of the data presented by MPS in this case. We must examine those claims, as they have a direct bearing on our ability to rely on the marginal cost results in establishing class revenue responsibility. We have already discussed the lack of reliability surrounding the Company's NCP results. However, in the case of all the marginal demand cost areas (i.e., generation, transmission and distribution) our findings have relied on the coincident peak data supplied by the Company as modified by Staff's witnesses. The Staff in its Direct testimony claimed that a large number of problems were present in the Company's CP data. These problems generally can be classified as inconsistencies or anomalies. At Rebuttal the Company presented revised CP numbers that it was able to obtain through additional load research and billing analysis. While the Staff did not express complete confidence in the Company's revised CP numbers, its criticisms were limited to several specific areas, as detailed in the Surrebuttal testimony of Swan and Psacharopoulos. In fact, the witnesses presented adjustments to the Company's results that appeared to correct the most obvious of the problems, most of which can be characterized as errors in computations. The most significant problem area was the method by which the Company scaled up its estimated class CPs to arrive at the known (i.e., measured) system monthly peak. The Company employed an annual scaling factor that it applied to all rate classes, while Dr. Swan used a separate factor for each month that was applied only to those classes that were not actually measured. As described more fully later in our discussion of the generation capacity costs, we have found Dr. Swan's modifications to be reasonable and appropriate. They are based on sound logic, and MPS did not dispute their validity. As discussed in Section IV. C. above, the Staff also raised significant concerns about data quality and reliability in the calculation of unit costs for transmission and distribution. While we agree with Staff's concern about the calculation of the unit marginal costs for distribution and transmission plant, we must look at how these results are applied in the final analysis. In the case of transmission plant, a single unit cost is calculated for all customers that use the transmission system, i.e. every customer class. A second calculation is done for customers who take service at less than transmission voltage (everyone except the H-T class), and the results of the two calculations are added together to arrive at total marginal transmission costs. The important point is that, except for the slightly lower rate charged only to the transmission voltage level customers, all customer classes receive the same unit cost, and changes to the unit cost will affect all customer classes in a relatively (but not exactly) equivalent manner. A similar marginal cost calculation occurs with distribution costs. Here the distinction is between secondary and primary voltage level customers. The classes that do not use the distribution system at all (H-T and S-T) receive no distribution cost. The remaining classes are allocated an amount based on the cost of the primary distribution facilities, and those that take power at the secondary level (the same as primary except the ES and EP classes are excluded) are charged an additional increment based on the cost of the secondary system. When unit distribution costs are recalculated, all categories of classes change to the new rate. Assuming no change in allocation, the change in distribution costs would be proportionately equal for all classes. In addition, the ratio of distribution to total marginal costs affects the overall result, and the EPMC reconciliation magnifies any difference. We have conducted relatively simple sensitivity analyses to determine the parameters that encompass the possible changes in marginal distribution costs. Transmission costs were not so analyzed because they are relatively small. We examined the results of three scenarios, all used in conjunction with Staff's allocation percentages: 1) cutting MPS's estimated unit distribution cost in half; 2) doubling MPS's estimate, and 3) using MPS's unit costs with the Staff allocations. Using MPS's unit cost with the Staff allocation has the least effect on the required increase as calculated with the EPMC reconciliation, although the spread between the largest increase and largest decrease widens. Reducing MPS's estimated distribution cost by one-half reduces the spread, while doubling the estimate widens the spread. The absolute numbers, while showing large variations in the required revenue adjustment, are not as crucial as the fact that the positions of each class do not change in relation to one another. Hence, we conclude that a carefully designed rate stability adjustment could be effective in overcoming these data concerns. While we agree with the Staff that the data underlying the unit cost calculations exhibit serious problems, we find that those problems are not fatal but can be considered and accommodated through the rate stability adjustment that we have proposed. Accordingly, we conclude that the data quality problems are not as extensive as Staff claims, and can, to a large degree, be addressed by avoiding the use of the most seriously flawed data and by not blindly implementing the final marginal cost results. Consequently, we have not used the data which presents the major problems, the class NCPs, in arriving at marginal costs. While the CP information is not completely reliable, is a reasonable starting point in establishing rates based in part on marginal costs. We must use the cost results with caution, but we do not find that the CP data is so bad as to render it unusable. Nor do we find, in light of past rate design cases before this Commission, that substituting use of an equally weighted CP in place of a more preferable NCP factor in calculating class marginal distribution costs leads to unacceptable results. Rather than reject the results of all of the marginal cost calculation, we will take the data shortcomings into account in reaching our final conclusion. We will use Staff's results as the proper calculation of total marginal distribution costs, as well as of the allocation of those costs among customer classes. d. Invitation to File Updated Class NCP Data To address the NCP data quality problem, we will allow MPS the opportunity to file updated class NCP data, as well as its proposed method of using NCP's as the basis for allocating distribution marginal costs. Should MPS choose to make this filing, our intention is that this limited proceeding will be completed in time to be implemented with the Company's rate change currently scheduled for February, 1998. The only issues to be considered are the class NCP data itself, the use of one annual NCP versus 12 monthly NCP's as the proper allocator, and if the 12 NCP allocator is used, the proper method for weighting each of the monthly numbers. We encourage the Company to work with the Staff, and other interested parties in developing the methodology to be used in the study and in resolving as many disputes as possible prior to making its filing. 2. Transmission Having decided how to set the marginal cost of transmission in Section IV.C. above, we now allocate those costs to the individual rate classes. Here the differences among the parties' positions are not great, but they do reflect some conceptual variations that may indicate fundamental differences, or even misunderstandings, about the allocation process. While the absolute dollar differences among the parties is not a major driver of the total marginal cost calculation, the large reconciliation from marginal to embedded costs serves to magnify in the final results the relatively small transmission cost differences. In the Company's calculation, transmission represents about 2.5% of total marginal costs, while the Staff proposal regarding transmission costs equates to about 1.6% of the total. While the OPA witness used a calculation that is fairly close to the Company's number, in his Brief the OPA supports the Company's calculation. Both the Company and the Staff assign marginal transmission costs to each of the rate classes by use of 12 CP weighted by Probability of Peak (POP) methodology, which is the same method each used in allocating their generation capacity costs. In fact, each uses the same CP numbers for each calculation. MPS does not determine a total-company marginal transmission cost by multiplying the actual annual CP by the marginal unit cost. Rather, it multiplies the weighted loss-adjusted CP for each class by its determination of the marginal cost for that class and then sums up the class amounts to get its total company cost. The H-T class receives slightly lower per unit cost, since it does not make use of the subtransmission system as all other classes do. Before allocating costs to each class, the Staff determines the total-company marginal cost by multiplying the annual actual CP by the unit transmission marginal cost applicable to the transmission and secondary/sub-transmission portions of the system. Staff then allocates this total to the individual classes by use of the ratio of each class's contribution to the monthly peak multiplied by each month's probability of it being the annual peak. The Staff also assigns no subtransmission cost to the H-T class, and performs its transmission and subtransmission allocations in a two-step process, which accomplishes essentially the same result that the Company shows in a single step. The key difference is that the Staff allocates the total cost derived by use of the annual CP, while the Company sums the costs that it calculates for each class, based on the POP-weighted CPs to arrive at a total cost. Staff also employed class CP numbers that were adjusted by Dr. Swan to account for inconsistencies and anomalies. a. Analysis We find that Staff has applied the marginal cost theory correctly by first determining total costs, and then allocating those costs to the individual classes. The Company's method and subsequent result are inconsistent with the proper application of marginal cost theory. While it is also not clear if the Company's miscalculation is simply a result of mathematical errors or a misunderstanding of the marginal cost theories employed by the Commission, we expect the Company to correct this in any future rate design filings. In this case, we accept the Staff's allocation methodology and allocation factors using the CP numbers as adjusted by Dr. Swan. V. MARGINAL ENERGY COSTS Marginal energy costs are designed to measure the Company's cost of supplying an extra kilowatt hour (Kwh) of power to its various customer classes during each of its four seasonal and daily time periods. It is measured by running the Company's production costing model through successive iterations assuming small increments in additional energy use over an intermediate term (5 years in this case) and applying the average seasonal and diurnal per Kwh results to the test year energy billing units. There is essentially no dispute between the Company and the other parties regarding this methodology, because Company witness Gerow asserts that he has accepted the modifications proposed by the Staff witnesses. The actual cost of energy on a per Kwh basis used in the calculation varies slightly between Staff and Company, but the difference represents only about .25% of the total marginal costs, a very small difference, inconsequential to the overall result. As discussed below, the OPA has proposed a slightly different per Kwh cost result, based on the recommendations of its witness, Ms. Smith. The OPA's marginal energy costs are approximately 9% higher than those of the Company and the Staff. In its Reply Brief Staff mentions the issue of variable O&M costs, which MPS claims the Staff failed to include in its marginal energy costs, as well as having excluded them from its marginal generation costs. As explained below in our discussion of marginal generation capacity costs, we have found that Staff was correct in excluding variable O&M from the calculation of marginal capacity costs. In the case of marginal energy costs, Staff responds that it merely used information supplied by the Company in computing the forward-looking marginal energy costs. It accepted the Company's determination of what generating unit or power purchase was on the margin at any point in time over the 1996 to 2000 time period. Most of the Company's additional energy is supplied from power purchases, and there would be no variable O&M associated with this energy. The OPA witness agrees with the methodology used by the Company, but she asserts that several changes should be made to the Company's energy resource plans in order to more accurately reflect how MPS should be running its system. The adjustments made by OPA witness Smith are: 1) a price of $15.00/Mwh is imputed for Maine Yankee off-system sales, based on other sales prices obtained by utilities in New England; 2) a further increase in the sale price for Maine Yankee above the inflation estimate is added to the Company's numbers; and 3) a reduction in Maine Yankee's capacity rating is recognized over the remaining life of the plant due to the recently completed generator tube resleeving operation. The OPA questions the Company's conduct of its off-system sales practice, because the Company typically sells a portion of its Maine Yankee entitlement while at the same time purchasing replacement power from New Brunswick, thus lowering the net amount received by the Company. The OPA suggests that such transactions should not be happening to the degree they appear to be, since the overall result of these sales is to reduce MPS net sales revenues relative to the market price of Maine Yankee entitlement. Both the Company and the Staff respond to the Maine Yankee sales price assertions made by the OPA witness. Staff asserts that its estimate of $10.98 is based on actual 1994 sales results and is a good indicator of actual future prices. Staff does not take issue with the manner in which such transactions have occurred previously, or make any statement opposing future transactions of this type. Further, Staff asserts that any de- rating of Maine Yankee capacity is quite uncertain over the 5-year time horizon being examined. The Company defends its past sales/repurchase transactions as effective in lowering its overall energy costs. It states that it is selling small quantities of surplus power from Maine Yankee for relatively short time periods, while the OPA witness is comparing those with longer- duration sales commitments made by other utilities. Additionally, MPS states that while it sells its Maine Yankee entitlement for relatively short-time periods, it may have to purchase even smaller amounts of power from New Brunswick to meet peak demands on it system. Analysis We find that the marginal energy costs presented by the Company and Staff are most appropriate for use in establishing the Company's rate design, based on the 5-year forward looking production cost methodology employed. We reject the OPA's assertions with regard to Maine Yankee de- rating as being too speculative at present. In addition, we cannot find on the basis of this record that the OPA's assertions concerning the price and conduct of Maine Yankee off-system sales are accurate. A slight difference exists between the Company's and the Staff's presentation of the actual marginal energy costs. The difference is apparently caused by the manner and inputs used in running the production cost model. In addition, the Company presented no evidence that any variable O&M cost has been left out of the calculation. For our purposes, we will use the numbers supplied by Staff. VI. MARGINAL GENERATION CAPACITY COSTS Marginal generation capacity costs refer to the costs that a utility incurs in order to supply an additional amount (usually measured in megawatts, MW) of generating capacity to meet an increased load. Although not the case at the beginning of the proceeding, the parties now generally agree on the basic methodology to be used in calculating the unit marginal cost and the allocation of those costs to the individual rate classes. However, several disputes remain concerning the correct numbers to be used in the calculations. The cost is calculated by determining the type of peaking generating unit that would be used to meet the additional load and associated reserve requirement, based on the utility's least cost resource plan. When the utility's resource plan shows a short-term excess of capacity, the cost of the peaker is discounted from the year of anticipated need to the year for which rates are being set. When the resource plan indicates no such excess, no discounting is necessary. To determine a utility's total marginal cost of generation, the per KW annual carrying cost of the peaker unit is determined and then multiplied by the utility's coincident peak load. The total marginal cost is allocated to the individual rate classes by looking at each class's monthly coincident peak load as a percentage of the system's monthly CP, and then weighting each month's results by the associated probability of peak. The calculation must, by definition, sum to 1.00, or 100% of the utility's peak generation capacity cost. In the instant case the parties agree that the appropriate unit to use as the assumed peaking unit is the combustion turbine, the same proxy unit used in several prior Commission rate design proceedings. Although it originally advocated a method of class allocation that combined the cost of a short-term probabilistic purchase with a discounted peaker method, at the rebuttal stage the Company altered its position and accepted the discounted peaker method as proposed by the Staff. However, MPS asserted that the year of need is 1997, and it included in the annual carrying cost calculation an amount that was designed to account for the variable O&M associated with running the peaking plant. Although it did not originally do so, at rebuttal the Company allocated the cost responsibility to the classes by use of the 12 coincident peak (12 CP) methodology. This method was put forth by Staff in its Direct case, and has been accepted by this Commission in prior rate design proceedings. MPS arrives at a marginal generation capacity cost of $90.03/KW based on 1997 as the year of need. The Company claims that Staff erred in excluding variable O&M from both its capacity and its energy calculations. Staff calculates the marginal generation capacity cost to be $85.18/KW, based on 1996 as the year of need and no variable O&M included in the amount. Staff states that only a half year of discounting for 1996 might be appropriate, because new rates from this proceeding will not become effective until the middle of the year. The Staff assigns cost responsibilities to the various classes by use of the probability of peak (POP) weighted 12 CP method, although its allocation varies from that of MPS because of several corrections made by Staff witnesses Swan and Psacharopoulos to the CP data supplied by the Company due to discrepancies or anomalies in the Company's method of calculating CP's for each of the classes. In essence, the Company's method scales up all classes' POP weighted monthly CPs to agree with the measured system CP by use of an annual scaling factor. The Staff method scales up only those classes that have unmeasured CPs, and the scaling is accomplished by use of a month-by- month factor. The Company did not respond to the Staff's corrections, either in its witness's rebuttal filing or in its Brief or Reply Brief. Nevertheless, the Company continued to use the class allocations proposed in the Rebuttal Testimony of Mr. Gerow. Staff further asserts that the methodology employed by MPS in allocating costs to the individual classes fails to arrive at the correct total marginal generation cost, because the Company does not multiply the individual class annual allocated responsibility by the annual system peak, but only sums the individual months' allocations, which, as described above, differ from those calculated by the Staff. By failing to multiply the class responsibilities by the system peak, the Company's calculation arrives at a cost that is something less than the system peak. Staff further assert that no variable O&M should be included in the calculation, because the purpose of the exercise is to determine the marginal capacity cost of the peaking unit that is on the margin, not the costs of actually supplying energy from that unit. Staff's calculation does include an amount, albeit relatively small, to account for the fixed O&M costs associated with the marginal peaking unit. Staff assert that any variable O&M for energy supplied should be included in the marginal energy cost, and we have addressed that concern in our discussion about marginal energy. The witness for the OPA, Lee Smith, presented a calculation of marginal generation capacity costs that was based on a year of need of 2000, and that included variable O&M costs, as proposed by MPS. The resulting amount, which was used in arriving at the rate design changes recommended by Ms. Smith in her Exhibit 20 (part of OPA # 31), was $77.28/KW. This unit cost was applied to the Company's single CP numbers for each class. However, the OPA states in his Brief that he accepts the Company's marginal generation costs for the purpose of setting rates in this case. Analysis Based on the evidence before us and on Commission precedent, we find, with one minor exception, that Staff's recommendations regarding marginal generation capacity costs should be adopted in their entirety. In accord with our findings in Docket No. 92-315, we affirm that the discounted peaker methodology provides the best estimate of the intermediate term marginal cost of generation capacity. The minor exception to the Staff's calculation is that we find that 1997 should be considered the year of need for the purposes of applying the discounting technique to the capital cost of the peaker unit, because the rate design that derives from this proceeding will not go into effect until mid-way through 1996, and because the Company's resource plan shows 1996 to be have a small excess, so no need actually exists until 1997. Although new rates are to become effective in mid-1996, we will not use an additional half-year of discounting, as suggested by Staff. This will simplify the calculation, and it would result in only a de minimis change to the overall marginal cost result. We further find that variable O&M is not properly included in the capacity cost of the peaker unit, because as Staff correctly points out, the calculation is designed to measure only the capacity costs, not the operating costs, of the peaking unit. We further find that generation capacity costs should be allocated to each class based on the monthly CPs weighted by their probability of peak, as presented by Staff. As with other data areas in this case, the Company should refine its load research techniques, so that in future cases there can be a higher degree of confidence in the monthly CP numbers. In summary, we find that the total marginal cost of generation capacity and the allocations to each class as proposed by Staff should be used in determining the Company's total marginal costs. VII. REVENUE RECONCILIATION A. EPMC and Other Reconciliation Methodologies When rates are to be based on marginal costs, it is usually necessary to reconcile the amount of revenue that the marginal costs would yield when applied to the test year billing units to the total revenues that the utility is allowed to collect, as determined through a revenue requirement proceeding. Since a company's revenue requirement usually is calculated on the basis of its booked accounting costs, this amount is generally referred to as its embedded revenue requirement, and so the reconciliation is characterized as marginal cost to embedded cost. The size of this reconciliation varies from company to company, depending on the relationship between the utility's embedded costs and its marginal costs. In this proceeding the amount of reconciliation is quite large, no matter which party's estimate of marginal costs is employed. Based on MPS's calculation, the mark-up from total marginal to total embedded costs is 77.1%; the Staff's estimate of marginal requires a 98.9% add-on, and the OPA marginal cost recommendation requires a mark-up of 87.0%. As is discussed below, when the reconciliation is of the magnitude needed here, the validity of the marginal cost based price signal is seriously jeopardized. In fact, under such circumstance the validity of the use of marginal costs to set rates may be called into question. Nevertheless, our decision is based on the continued use of marginal costs as the starting point from which rates are established. However, we invite comments in future proceedings on alternative methods of setting rates where the reconciliation is so large. The total company marginal costs, as calculated using the Examiner's recommendation for each category, are $25,932,941, which requires a reconciliation amount of $24,251,174, or 93.5%. See Exhibit 2. The parties have presented two recommendations for determining the amount of reconciliation that is applied to each rate class. One, supported by the Company and the Staff, is the equal percentage of marginal cost (EPMC) method, in which each rate class receives the same percentage of the reconciliation amount as is equal to the class's contribution to total marginal costs. This method has been employed by the Commission in recent rate design proceedings where marginal costs were used as the basis upon which inter-class revenue allocations were determined. The OPA has proposed a novel approach which it refers to as the generation capacity allocator. This method allocates the required reconciliation amount by each class's proportional share of the total marginal generation and energy costs. The theory behind this proposed method is that the difference between the total marginal and embedded costs is caused by the Company's uneconomic generation (including energy) cost commitments, and this proposed allocator allegedly assigns the responsibility for the revenue difference to each class more fairly than the EPMC method. The EPMC reconciliation method has been used previously because it is relatively simple to apply and assigns cost responsibility equitably; determining actual cost causation responsibility is a difficult, complex and time-consuming process that would expend large amounts of resources. However, the use of EPMC is questionable when the amount of reconciliation is as large as it is in the instant case. Clearly, the price signal that is supposedly sent by basing prices on marginal costs is considerably dampened, if not totally nullified, with a large reconciliation factor. However, some method of reconciliation is required, and the EPMC method has several attributes that make its use desirable. Among those are simplicity, equity and understandability by customers. In prior cases the Commission has considered other methods to accomplish the reconciliation. Among those are Ramsey pricing and embedded cost studies. However, both are fraught with problems of their own and, for varying reasons, have not been used to assign cost responsibility. Ramsey pricing assigns the reconciliation amount on the basis of inverse elasticity of demand, that is, the customer classes that are found to be the least elastic would receive the largest reconciliation amount, since they are the least likely to alter their usage based on the price of the product. While this method has a basis in economic theory, it is difficult to apply in practice, mainly because reliable measures of relative class elasticities are not available, and because it is often viewed as being less than equitable. Since no party proposed its use here, we will not consider it further. Use of embedded cost studies, which were relied on by this Commission prior to the change to marginal cost based pricing, require a complete examination of the utility's investments and operating costs in order to assign cost responsibility. The studies are generally complex undertakings that require a method of assigning the joint and common costs that are present to the various classes. Here again, assignment can be difficult and contentious, and since there may be no "right" answer, the ultimate allocation tends to be arbitrary and the level of such costs can be quite large. No party has proposed use of an embedded study in this docket, and the required information is not in the record. B. OPA's Proposed Generation Allocator Method The Public Advocate has proposed a novel reconciliation methodology, in which the reconciliation amount would be allocated to rate classes on the basis of a generation allocator which takes into account both the capacity and energy requirements of each rate class. OPA's support for this proposal rests on the claim that the revenue deficiency (i.e. the reconciliation amount) is the result of uneconomic generation assets and energy purchase commitments, and revenue responsibility should be allocated on this basis to reflect the cause of the deficiency. OPA also argues that when the reconciliation gap is so large, EPMC will inappropriately allocate revenue responsibility. MPS responds to the OPA reconciliation proposal with several arguments. First, MPS argues, the proposal amounts to "reverse Ramsey" pricing, allocating more revenue responsibility to the more elastic customers, those with alternatives. This will drive them off the system and result in higher rates for remaining customers. Second, MPS argues that the OPA's claim that the reconciliation gap is due to uneconomic generation-related costs has not been adequately supported. The Company purports to show that where the revenue deficiency is broken down by function, the resulting reconciliation is closer to EPMC than to the OPA proposal. As explained above, the policy of this Commission has been to use an EPMC (equal percentage of marginal costs) reconciliation to bring marginal costs revenues into equality with the utility's revenue requirement. We are willing to consider a departure from this precedent but will need substantial record basis for doing so. We believe that if OPA's proposal produced pricing with the actual perverse effects claimed by MPS, it would be bad policy. When we look at OPA's recommendation, however, the recommended change to the residential class is a small decrease (about 2%); the change to the commercial class is a small increase about 1.4%); and the change to the industrial class is a small decrease (about 2%). This is not what would be expected from "reverse Ramsey" pricing and could be found to be an acceptable result if otherwise justified. We find MPS's second argument, an attempt to account for the reconciliation gap in a precise manner, to be interesting. A number of assumptions in the Exhibit are not explained, however, and their basis is not clear (e.g. the claim that no excess costs are due to energy and how MPS's contract with Wheelabrator-Sherman is taken into account). Therefore, we cannot accept its conclusions at this time. On the other hand, we would like to see OPA's assertion about uneconomic costs put to the test, and MPS does so in a fashion that at least raises plausible doubts. We cannot find in favor of either party on this issue at this time. OPA's reconciliation method is a hybrid of marginal cost and historical cost allocation methods. This is a novel concept and no party has analyzed its pros and cons in sufficient detail to allow for a confident finding either way by this Commission. Therefore, we find that this record provides insufficient evidence to persuade us to depart from precedent. For now we will continue our policy of using EPMC. C. Conclusion While we recognize that use of the EPMC methodology in a case where there is a large reconciliation amount may present problems, we find that its positive attributes make it reasonable as a reconciliation method. We will use it here calculate total revenue responsibility for each class, based on the marginal costs determined above. This does not mean that the actual rates will be set on this result, but it is the starting point for our ultimate pricing decision. We are not prepared to fully reaffirm EPMC as requested by Staff. In principle, we would prefer to allocate reconciliation-gap costs in a way that maximizes social welfare, recognizing the need for perceived as well as actual fairness. We will leave open for the future our ability to explore alternative methods at reconciliation, including increased flexibility for the Company, as discussed in VIII.B. below. VIII. RATE STABILITY AND RATE DESIGN DETERMINATION A. Rate Design Determination Having determined that class revenue responsibility should be based on marginal costs plus an EPMC reconciliation, we next decide how actual prices should be set. The major factors that will impact our decision are the reliability of the data used in calculating the class revenue requirements and our concerns with rate stability and fairness to each class. The area of data quality and reliability has been thoroughly discussed in the sections where we determined the marginal costs for each class by each category of cost. We found that the data was not completely reliable, but was not so bad as to be useless. In making our final class rate determinations, we will temper the results of the revenue requirement calculation to account for the infirmities present in the data. This tempering must reflect our judgment regarding the magnitude of the data problems. We also consider rate stability in order to avoid "rate shock" to customers. Here we take into account how large an increase each particular class can and should absorb, and what the various classes should expect from a proceeding of this type. The OPA asks us to consider that the service territory of MPS is among the poorest in the State and that the customers of MPS will be required to absorb additional rate increases over the next few years, based on the Stipulation approved by the Commission in the revenue requirement phase of the instant proceeding. The OPA urges that the Commission consider the ability of customers to pay for these rather large increases. We share the concerns set forth in the OPA's Brief. However, even the OPA's own recommendations would require that one class of customers (sub-transmission) receive an increase of more than 20%, another class (ES) a 9.1% increase, while two other classes (Municipal and street lighting) would receive decreases greater than 20% each. Such a result does not contribute to overall rate stability. Every class could put forth arguments as to why it should not receive much of an increase or, alternatively, that it deserves a decrease in its rates. We must balance the somewhat often inconsistent goals of rate stability and cost causation in a manner that is reasonable and equitable to all customer classes, while at the same time affording the Company the opportunity to earn its revenue requirement. Rather than accept the recommendation of the OPA, we will follow the Staff's recommendation that because of the data infirmities, any percentage increase should be conservative. Staff recommends increases that are relatively equal for each class, with the transmission and lighting classes receiving slightly lower increases. However, we have found that the data problems are not fatal to our marginal cost results, and while we are recommending relatively small changes, we find that the results of the EPMC-reconciled marginal cost analysis may reasonably be reflected to a greater extent than Staff has done. Our rate design determinations are based on a comparison with the rates that were in place in December of 1995, that is, prior to the 4.4% across-the-board increase that was implemented according to the Stipulation approved on November 30, 1995. Based on the concerns previously expressed, we will implement a rate design procedure that provides for a very slight decrease to one class, no change to another and limits the maximum increase to 7.5%, which only one class receives. By doing so, we have made some movement toward implementing marginal cost based rate design, but have moderated the final result because of our concerns with 1) data reliability, 2) the ability of any one class to absorb this and the additional increases that are to occur over the next three years, and 3) the validity of implementing marginal cost based rate design in general and, in particular, when the amount of reconciliation from marginal to embedded costs is as large as it is here. Our rate design determination is shown on attached Exhibit 1. It moves each customer class in the direction indicated by the EPMC-reconciled marginal cost results, except for the two classes whose results indicated decreases from test year rates. For these classes, we will decrease only the H-T rate slightly, more in accordance with the marginal cost results, and the SL/T class will remain unchanged. Given that additional increases are scheduled to occur, we find it would be difficult for other classes to absorb the additional increases that they would result from the two classes' receiving greater decreases based on the cost information before us. /11 We find further support for this decision in the comparison of MPS's rates for the two classes that might have received decreases with other Maine electric utilities (as reported on FERC Form 1, 1995) showing that the rates are in line with those other Maine utilities for these classes. /12 Our determination regarding the exact amount of rate change for each class involves a fair degree of judgment, but it is designed to implement the policy described above, while simultaneously arriving at the correct amount of the total revenue requirement. B. Rate Design Policy Issues In the course of developing our rate design determination in this case, we have made a number of observations about marginal cost rate design methodology as it operated here. We would like to briefly note these. One of the most troubling features of this proceeding is the size of the reconciliation gap. The EPMC markup for MPS is close to 100%. First, with a price that is almost twice what the underlying economic rationale says is it should be, the price signal being given is of questionable value, especially for interclass pricing. Intraclass rate design at least preserves marginal cost price ratios for seasons and time- of-use periods, which probably has some merit, even if the absolute level of prices greatly exceeds their underlying marginal costs. Second, the EPMC will magnify the effects of any errors in marginal cost measurement. To the extent that there are data problems, or other reasons to question the reliability of the marginal cost estimates, it becomes more difficult to use an EPMC reconciliation as a basis for rate changes. /13 Third, as noted by the OPA's witness Smith, when a particular rate class has proportionately more of a particular category of marginal cost in its total class marginal costs, the EPMC will allocate other costs to that class (from the revenue deficiency) in a way that appears be inappropriate when viewed from the perspective of historical cost causation. Smith argued strongly that under current conditions some features of marginal cost rate design with EPMC are not serving their intended purpose. The size of the EPMC adjustment appears to be one factor at least partly explaining the novel treatments of customer costs advocated by Staff and OPA, as well as OPA's novel reconciliation proposal. Another troubling theme was Staff's lack of confidence in their EPMC results, despite heroic and protracted efforts. Staff did not believe that their study was reliable enough to justify any extensive changes in class revenue responsibility. Data problems were certainly a part of this, but we wonder whether there may also be infirmities in marginal cost methodology, particularly in the measurement of transmissions and distribution marginal costs, that create additional uncertainties. Both OPA witness Smith and Staff witness Swan appear to have misgivings about certain aspects of marginal cost allocation studies. During examination, Swan questioned whether it is possible to determine meaningful distribution marginal costs since the level of investment seems to be more related to budgeting and availability of crews and other resources. In addition, we are not completely satisfied with either of the methods (vintage plant and reliability index) advocated here. The lumpiness of investment is one problem, decline in load is another. We wonder whether it is feasible to accurately separate transmission and distribution investment into growth and reliability components. This Commission first used a marginal cost study to allocate revenues among rate classes in a CMP case, Docket No. 89-068. At that time, most of the parties argued that the proponents of marginal cost allocation had been unable to resolve problems of equity, stability, continuity, and customer understanding. Supporters of the marginal cost allocation argued that it was the most economically efficient approach. A divided Commission accepted Staff's reasoning with one commissioner dissenting on the use of marginal costs to allocate revenues among classes. Like this case, Docket No. 89-068 was fraught with methodological and data validity concerns. The problems of excess revenue allocation and rate stability continue and are more extreme here. However, many of the difficulties in this case are different and were unforeseen at the conclusion of Docket No. 89-068. It is not illogical to expect that marginal cost studies of the future will continue to such disputes. We raise these matters because of issues that have arisen in this case and because of the possibility that improvements may be found to current rate design methodology that would address these concerns. We are interested in receiving comments or proposals in future proceedings for adjustments to current marginal cost rate design in this period of change in the electric industry, as well as comments on the role and methodology for rate design under current conditions, or suggestions regarding how the Commission may best address these matters. We are open to considering "rate design flexibility" proposals wherein the Company would be permitted to set the exact rates for each class anywhere within approved parameters at the time of its compliance filing. The rates applied to the test year billing units would have to equal the total company revenue requirement. The rationale for such a process is to allow the Company some flexibility to set its prices, based on its knowledge of its own customers, within reasonable limits. The Company may be in a better position to understand how certain customer classes might react to rate changes. Of course, setting the parameters for such a proposal would have to be done with considerable care, and could involve setting up a bandwidth within which rates could be found reasonable, such as the degree of change between current and an approved marginal cost result. Our consideration of any such proposal would necessarily include a determination whether "rate design flexibility" is consistent with Maine law and is in the public interest as a matter of policy. IX. CONCLUSION We hereby approve changes in rate design for Maine Public Service Company that are based to a degree upon marginal cost results from evidence presented by the parties in this proceeding. We decline to move rates to full EPMC results. Our decision to move only part way toward the marginal cost results is based on our combined concerns about data quality, methodology, and rate stability. Further, we invite the Company to present updated NCP data for consideration in a limited proceeding to determine whether further adjustments to interclass rate design are warranted for implementation in February, 1998. Accordingly, it is O R D E R E D 1. That Maine Public Service Company shall file rate schedules in compliance with the determinations contained herein. Dated at Augusta, Maine, this 26th day of June, 1996. BY ORDER OF THE COMMISSION /s/ Christopher P. Simpson Christopher P. Simpson Administrative Director COMMISSIONERS VOTING FOR: Welch Nugent Hunt NOTICE OF RIGHTS TO REVIEW OR APPEAL 5 M.R.S.A. SS 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 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 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. SS 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. SS 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 attached 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. APPENDIX A Procedural History On February 10, 1995, the Company filed a 60-day notice of its intention to file a general rate case and that it would file a request for a 5-year rate stabilization plan, including a flexible pricing component pursuant to SS 3195(6). On May 1, 1995, MPS filed a multi-year revenue increase and rate stabilization plan. The plan included proposed rate design changes in the form of class revenue requirements; no intraclass rate element changes were proposed. The intervention deadline was May 26, 1995. Intervention was granted for the Office of the Public Advocate (OPA), Hannaford Bros. Co. (Hannaford), and McCain Foods, Inc. (McCains) at the prehearing conference held on June 9, 1995. At the prehearing conference on June 9th bifurcation of the proceedings and schedules for the revenue, rate plan and rate design cases were discussed. The revenue increase and rate plan portion of the case was scheduled for resolution by February 1, 1996. The rate design portion of the case was initially scheduled for implementation by April 1. A series of events resulted in several extensions of the schedule. A Partial Stipulation (Flexible Pricing) was approved by the Commission by Order dated August 7, 1995, resolving the flexible pricing issues in this case. Under this plan, a discounted agricultural produce storage rate proposed by the Company was approved on November 29, 1995, in Docket No. 95-803. Public witness hearings on MPS's proposed multi-year revenue increases, rate stability plan and rate design were held on November 8, 1995 in Fort Kent and Presque Isle. Notice of the hearing was provided by bill inserts, a Commission Notice and press release distributed to media in MPS's service area. An Order Approving Stipulation (Rate Case/Rate Plan) dated November 30, 1995 approved a second stipulation establishing a multi-year revenue requirement and rate stability plan for MPS to extend through 2001. The approved rate plan included an initial increase of 4.4% across- the-board to all classes on January 1, 1996, and annual increases for the next three years of 2.9%, 2.75% and 2.75% respectively. On December 19, 1995, a Supplemental Stipulation executed by Advocacy Staff, the Public Advocate and the Company was approved without objection from non-signatory parties. The Supplemental Stipulation addressed revenue issues related to MPS's low income, Power Pact program. Subsequent to its May 1, 1995 filing which contained the direct testimony of Ward D. Gerow and an initial cost of service study, the Company filed revised marginal cost of service studies, incorporating various corrections and modifications, on June 29, 1995 and August 28, 1995. The Company also filed the rebuttal testimony of Mr. Gerow on December 1, 1995 and his surrebuttal testimony on January 18, 1996. Advocacy Staff filed the direct and surrebuttal testimony of Angela Monroe and William Gibson, of the Commission Staff, and of Dale Swan and Daphne Psacharopoulos of Exeter Associates, Inc., on October 11, 1995 and January 19, 1996, respectively. The OPA filed the direct, rebuttal and surrebuttal testimony of Lee Smith of LaCapra Associates on October 11, 1995, December 1, 1995, and January 19, 1996. Depositions were taken of Company representatives Ward D. Gerow, Edward Howard, and Tim Brown on September 13, 1995 and the transcript was entered into the record. A case management conference was held on March 12th and hearings were held on March 14 and 15, 1995 at which all witnesses were cross-examined. Briefs and reply briefs were filed by the Company, Advocacy Staff, OPA, and McCains. Exceptions to this Report were filed by Advocacy Staff, OPA and MPS on May 15, 1996. The Commission deliberated this matter on May 24, 1996. End Notes / 1 Utilities, of course, have an obligation to stay abreast of developments in Commission policy and regulation in their industry. / 2 Following the rebuttal stage, the Company sought to provide updated NCP data (from 1994 information) because it had then extracted it from its records. It was excluded for being too late in the process and would have required yet more resources to be committed to the proceeding, then nearly completed. While revisions and updates are not unacceptable during the course of rate design proceedings, when substantial data and methodological revisions are required, a heavy burden is imposed on all parties to the proceeding, and some limits are necessary. / 3 In the early days of marginal cost methodology, it may have been expected that future marginal costs would be above average cost. In Docket No. 89-068, calculating final rates to recover CMP's total revenue requirement required an approximately 30% mark-up over marginal cost allocation results. In this case, the mark- up will be close to 100%. / 4 See Order, Investigation of Central Maine Power Company's Resource Planning, Rate Structures, and Long-Term Avoided Costs, Docket No. 92-315(I), February 18, 1994, at page 1. / 5 The Commission recently confirmed that Docket No. 92-315(II) will address rate design for CMP and will begin once this proceeding is completed. / 6 In this case, the interest rate used to calculate the amortization amount is derived from the utility's capital structure and cost of capital. See Gerow Pref. Reb. Test., Ex. 10. / 7 A full exposition of this method can be found in NARUC's Electric Utility Cost Allocation Manual (1992), pages 144-146. / 8 It could be noted that during the early years of PURPA and marginal cost thinking it was believed that generation capacity marginal costs were greater than historical costs. Under this condition an EPMC reconciliation would "overallocate" other kinds of costs to classes with relatively higher capacity marginal costs. This may have been considered desirable by marginal cost enthusiasts (a "right" price signal). What is happening here with customer costs and allocation is exactly the same methodological effect, but involving a different type of cost and a different perception. / 9 This argument seems to be at odds with their position on the capital customer cost issue, because sunk costs for meters are also incurred at the margin (when the meter is installed) and are largely related to new customers. /10 Electricity Utility Cost Allocation Manual, National Association of Regulatory Utility Commissioners, January, 1992. /11 Of course, these two classes will receive at least 4.4% decreases from the rates that they are paying today, which were implemented with the across the board increase on January 1, 1996. /12 The report of revenue (cents/Kwh) for the classes is as follows: Large Industrial: MPS (H-T) 6.95, BHE 7.72, CMP 6.55 Lighting (Total): MPS 25.63, BHE 21.49, CMP 29.61 /13 To date, probably also for rate stability reasons, the Commission has never implemented rates indeed based solely on the EPMC calculated rate design results. Maine Public Service Co. Exhibit 1 Docket 95-052 Revenue Requirement by Customer Class Total EPMC Revenue Customer Marginal Reconcil- % Require- % Class Costs iation Increase ment Increase Residential $11,188,882 $21,652,158 7.44% $21,268,554 5.53% Commercial 4,632,058 8,963,724 12.05% 8,599,996 7.50% ES/ES-T 4,154,354 8,039,296 5.08% 7,987,014 4.40% EP/EP-T 921,687 1,783,602 2.96% 1,774,659 2.45% S-T 1,344,991 2,602,759 -0.37% 2,638,428 1.00% H-T 3,170,173 6,134,758 -11.08% 6,884,170 -0.22% Municipal 143,149 277,015 23.90% 233,420 4.40% SL/T 377,647 730,803 -8.41% 797,874 0.00% Total $25,932,941 $50,184,115 4.40% $50,184,115 4.40% Maine Public Service Co. Exhibit 2 Docket 95-052 Marginal Costs by Customer Class Customer Class/ Total Trans- Distri- Marginal Generation mission bution Customer Energy Cost Residential $3,126,274 $171,611 $1,197,042 $2,209,199 $ 4,484,756 $11,188,882 Commercial 1,319,769 72,438 597,877 627,412 2,014,562 $ 4,632,058 ES/ES-T 1,240,016 68,064 581,668 83,301 2,181,305 $ 4,154,354 EP/EP-T 281,850 15,472 78,005 26,880 519,480 $ 921,687 S - T 519,525 28,516 0 15,015 781,935 $ 1,344,991 H - T 958,544 46,463 0 29,853 2,135,313 $ 3,170,173 Municipal 0 0 62,404 10,114 70,631 $ 143,149 SL/T 92,116 5,056 13,168 192,062 75,245 $ 377,647 Total $7,538,094 $407,620 $2,530,164 $3,193,836 $12,263,227 $25,932,941 Exhibit 99(o) MAINE PUBLIC UTILITIES COMMISSION ELECTRIC UTILITY INDUSTRY RESTRUCTURING Docket No. 95-462 REPORT AND RECOMMENDED PLAN December 31, 1996 Chairman Thomas L. Welch Commissioner William M. Nugent Commissioner Heather F. Hunt Executive Summary On July 3, 1995, Legislative Resolve 1995, ch. 48 "Resolve, to Require a Study of Retail Competition in the Electric Industry" became Maine law. The underpinning of the Resolve is that broader market competition and customer choice in the electric market will benefit the public more than continued regulation. A central question of the Resolve is how to facilitate development of a competitive market in the retail purchase and sale of electric energy consistent with the public interest. The Resolve directed the Commission to construct a plan for the Legislature's consideration to achieve retail market competition for the purchase and sale of electric energy in Maine. Today, we advance a recommendation to restructure the market which fundamentally challenges the historical method of delivering, purchasing and regulating the provision of electric services. We embrace competition and advocate cautious implementation. The following fundamental principles guided the Commission's recommended path to achieve retail competition by the year 2000: * Where viable markets exist, market mechanisms should be preferred over regulation and the risk of business decisions should fall on investors rather than consumers. * Consumers' needs and preferences should be met with the lowest costs. * All consumers should have a reasonable opportunity to benefit from a restructured electric industry. * Electric industry restructuring should not diminish environmental quality, compromise energy efficiency, or jeopardize energy security. * All consumers should have access to reliable, safe and reasonably priced electric service. * Electric industry restructuring should not diminish low income assistance or other consumer protections. * The electric industry structure should be lawful, understandable to the public, and fair and perceived to be fair. * Electric industry restructuring should improve Maine's business climate. We believe our recommendation comports with these fundamental principles and approaches industry restructuring in a manner that is practical, efficient and in the public interest. - 2 - Our recommendation reflects our preference for competition and market mechanisms. We believe the principal long-term benefit of our recommendation is to shift the risk of business decisions about investment in generation away from ratepayers and onto shareholders. Another benefit is to bring competitive pressure to rates, which may move Maine's electric prices closer to the national average. Our recommendation reveals our desire to make the transition from theory to implementation in a way that allows Maine to benefit from the experience of other states and to preserve important state objectives. In broad outline, we recommend the following: Retail Competition and Deregulation * Beginning on January 1, 2000, all customers would have the option to purchase power in the competitive market. * All customers would have the option to purchase power directly from power suppliers or from intermediaries such as load aggregators, power marketers or energy service companies. * All customers could aggregate in any manner. * Once customers can purchase power in the competitive market, the Commission would not regulate, as public utilities, companies that produce or sell power. * The Commission would continue to regulate as public utilities the companies that transmit and distribute electricity. These transmission and distribution (T&D) utilities would have exclusive service territories and an obligation to connect customers to the power grid. * Before 2000, the Commission would consider progress in other jurisdictions and at the regional level in making the decisions necessary to implement retail competition. * The Commission would not require that other states or Canadian provinces allow retail competition in their jurisdictions as a condition to permitting suppliers from those states or provinces to enter Maine's market. - 3 - Corporate Structure and Divestiture * By January 2000, investor-owned utilities would transfer all generation related assets to corporations distinct from their transmission and distribution businesses. * By January 2006, Central Maine Power Company and Bangor Hydro-Electric Company would be required to divest all generation assets. They could divest earlier. * By January 2000, investor-owned utilities would be required to transfer the rights to power from all qualifying facilities (QF) contracts. * Consumer-owned utilities would not have to structurally separate or divest their generation assets. * Contracts between investor owned utilities and qualifying facilities would remain with the transmission and distribution utilities. * Maine Yankee decommissioning liability would be collected in the rates of transmission and distribution utilities. * Investor-owned transmission and distribution utilities would not market power. After 2006 Central Maine Power Company and Bangor Hydro-Electric Company could not have affiliates that market power. Maine Public Service Company may have such an affiliate, but it could market power only in its service territory. * After 2005, consumer-owned utilities could market power only within their service territories. Standard Offer * Standard offer service would be provided to customers who do not choose a competitive power provider and to those who cannot obtain power in the market on reasonable terms. * The transmission and distribution utility would administer a competitive bid process to select the standard offer service provider. Prior to a request for bids, the Commission would decide the terms and conditions of the standard offer service. - 4 - * Standard offer service price would be capped so that the price for power combined with the regulated rates of T&D utility service will not, on average, exceed the total rate for electricity prior to retail competition. * If the standard offer service price plus the regulated rates of transmission and distribution service is not, on average, at or below the total rate for electricity prior to retail competition, the Commission would investigate whether beginning retail competition at that time remains in the public interest. * The Commission would regulate the credit, collection, and disconnection practices relating to standard offer service. Customer Protection * The Commission would regulate power suppliers' interactions with customers, but not the prices or services offered. * The Commission would regulate the transmission and distribution utilities, including their rates and credit, collection, and disconnection practices. * The Commission would resolve customer complaints against transmission and distribution utilities. * Transmission and distribution utilities could not disconnect customers from their systems for non-payment of charges by, or other disputes with, power suppliers. * If a power supplier terminates service to a customer, that customer would default to the standard offer service. * Upon passage of an electric restructuring plan by the Legislature, the Commission would immediately begin customer education and outreach programs. - 5 - Low Income Assistance * The Commission strongly recommends that the Legislature fund low income assistance programs through either the general fund or a tax or surcharge on all energy services. * If low income assistance is not funded through taxes, low income programs would continue to be funded by ratepayers through the rates of the T&D companies. Energy Policy and the Environment Renewable sources * All companies selling power to retail customers in Maine should include a minimum amount of renewable energy in their generation portfolio. * Power suppliers could meet minimum renewable requirements with credits they could buy and sell. * The Commission would consider the market's ability to develop and sell power from renewable resources in establishing the renewable portfolio standard. Conservation and Load Management * Ratepayers would continue to fund cost effective energy efficiency programs through revenue collected in the rates of transmission and distribution utilities. * The transmission and distribution utility, with Commission oversight, would select the energy efficiency service providers through periodic competitive bidding. Siting and certification * The Commission would not review or approve construction of generating facilities. - 6 - Environmental risk * The Commission supports the application of air emissions standards that minimize differentiation between old and new source generating plants. The Commission will work with other states and appropriate agencies to accomplish this goal. Stranded Costs * Utilities would have a reasonable opportunity to recover legitimate, verifiable, and unmitigatable costs stranded as a result of retail competition. Utilities should have only the opportunity for cost recovery comparable to that under current regulation. * The Commission would require utilities to take all reasonable steps to mitigate those costs. * The Commission would establish initial estimates of stranded costs prior to 2000, using market information wherever possible. The Commission would not reconcile stranded costs after the fact, but would review them periodically and adjust them if warranted. The stranded costs associated with QF contracts would be subject to adjustment until the contracts end. * Stranded costs would be collected from customers through the regulated rates of the transmission and distribution utilities. * To the extent generation-related costs incurred after March 1995 become uneconomic due to retail competition, the Commission would not include any recovery for those costs in the stranded cost recovery charge. Regional issues * The Commission endorses and will continue to work for reforms to the governance of the New England Power Pool (NEPOOL) to allow fair and meaningful representation for all market participants. * The reformed NEPOOL should ensure that providers meet the North American Electric Reliability Council reliability standards. * The Commission endorses the establishment of an Independent System Operator (ISO)to be responsible for the day-to-day operations of the transmission system; the ISO must be effectively independent and have no financial interest in any market participant. * The Commission endorses the establishment of a voluntary power exchange. TABLE OF CONTENTS I. INTRODUCTION. . . . . . . . . . . . . . . . . . . . . . . 1 II. RETAIL COMPETITION AND DEREGULATION . . . . . . . . . . . 4 A. Recommendation . . . . . . . . . . . . . . . . . . . 4 B. Discussion . . . . . . . . . . . . . . . . . . . . . 5 1. Existing Industry Structure . . . . . . . . . . 5 a. Regulatory system. . . . . . . . . . . . . 5 b. Development of competition . . . . . . . . 7 2. Retail Competition. . . . . . . . . . . . . . . 9 a. Description. . . . . . . . . . . . . . . . 9 b. Benefits, risks and uncertainties. . . . . 12 c. State and local economies. . . . . . . . . 15 d. Rural electricity consumers. . . . . . . . 18 3. Timeframe for Retail Competition . . . . . . . 19 4. Customer Access and Options . . . . . . . . . . 23 a. Simultaneous access. . . . . . . . . . . . 23 b. Available options. . . . . . . . . . . . . 25 c. Special meters . . . . . . . . . . . . . . 26 5. Reciprocity . . . . . . . . . . . . . . . . . . 27 C. Further Proceedings. . . . . . . . . . . . . . . . . 29 III. CORPORATE STRUCTURE AND DIVESTITURE . . . . . . . . . . . 32 A. Recommendation . . . . . . . . . . . . . . . . . . . 32 B. Discussion . . . . . . . . . . . . . . . . . . . . . 34 1. Need for Divestiture. . . . . . . . . . . . . . 34 a. Power production and sales . . . . . . . . 34 b. Other services . . . . . . . . . . . . . . 39 2. Authority to Order Divestiture. . . . . . . . . 39 3. Process for Divestiture . . . . . . . . . . . . 41 4. Separation of Qualifying Facilities & Maine Yankee Power . . . . . . . . . . . . . . . . . 42 a. Qualifying facility contracts. . . . . . . 42 b. Maine Yankee . . . . . . . . . . . . . . . 44 5. Maine Public Service Company. . . . . . . . . . 46 6. Consumer-Owned Utilities. . . . . . . . . . . . 47 C. Further Proceedings. . . . . . . . . . . . . . . . . 49 IV. STANDARD OFFER. . . . . . . . . . . . . . . . . . . . . . 50 A. Recommendation . . . . . . . . . . . . . . . . . . . 50 B. Discussion . . . . . . . . . . . . . . . . . . . . . 51 1. Need for Standard Offer Service . . . . . . . . 51 2. Provider of Standard Offer Service. . . . . . . 52 a. Competitive bid. . . . . . . . . . . . . . 52 b. Bidding process. . . . . . . . . . . . . . 54 c. Standard offer service territories . . . . 56 d. Availability of information. . . . . . . . 57 3. Price Cap on Standard Offer Service . . . . . . 59 4. Terms and Conditions on the Standard Offer. . . 61 C. Further Proceedings. . . . . . . . . . . . . . . . . 63 V. CUSTOMER PROTECTION AND LOW INCOME ASSISTANCE . . . . . . 65 A. Recommendation . . . . . . . . . . . . . . . . . . . 65 B. Discussion . . . . . . . . . . . . . . . . . . . . . 66 1. Oversight of Generation Providers . . . . . . . 66 a. Registration and reporting . . . . . . . . 68 b. Business practices . . . . . . . . . . . . 69 c. Filing requirements. . . . . . . . . . . . 70 d. Standard billing . . . . . . . . . . . . . 70 e. Dispute resolution . . . . . . . . . . . . 71 2. Credit, Collection, and Disconnection . . . . . 71 3. Low Income Assistance Program . . . . . . . . . 72 4. Customer Education and Information. . . . . . . 75 C. Further Proceedings. . . . . . . . . . . . . . . . . 76 VI. ENERGY POLICY AND THE ENVIRONMENT . . . . . . . . . . . . 79 A. Recommendation . . . . . . . . . . . . . . . . . . . 79 B. Discussion . . . . . . . . . . . . . . . . . . . . . 80 1. Energy Policy and Electricity . . . . . . . . . 80 2. Renewable Resources in Electric Power Generation. . . . . . . . . . . . . . . . 83 a. Perspective. . . . . . . . . . . . . . . . 83 b. Renewable portfolio standard . . . . . . . 85 c. Resource mix disclosure. . . . . . . . . . 88 3. Efficient Use of Electricity. . . . . . . . . . 90 4. Long Term Resource Planning and Certification of Need . . . . . . . . . . . . . 92 5. Air Quality Impacts of Restructuring. . . . . . 92 C. Further Proceedings. . . . . . . . . . . . . . . . . 95 VII. STRANDED COST . . . . . . . . . . . . . . . . . . . . . . 97 A. Recommendation . . . . . . . . . . . . . . . . . . . 97 B. Discussion . . . . . . . . . . . . . . . . . . . . . 98 1. Nature of Stranded Costs. . . . . . . . . . . . 98 2. Utility Recovery of Stranded Costs. . . . . . .100 a. Opportunity for recovery . . . . . . . . .100 b. Mitigation . . . . . . . . . . . . . . . .102 c. Cost recovery limitation . . . . . . . . .104 d. Constitutional authority . . . . . . . . .106 3. Determination of Stranded Cost Charges. . . . .107 a. Process. . . . . . . . . . . . . . . . . .107 b. Methodology. . . . . . . . . . . . . . . .110 4. Recovery Mechanisms and Rate Design . . . . . .111 C. Further Proceedings. . . . . . . . . . . . . . . . .113 VIII.REGIONAL ISSUES . . . . . . . . . . . . . . . . . . . . .115 A. Recommendation . . . . . . . . . . . . . . . . . . .115 B. Discussion . . . . . . . . . . . . . . . . . . . . .116 1. Perspective . . . . . . . . . . . . . . . . . .116 2. Reliability . . . . . . . . . . . . . . . . . .117 3. Governance Issues in NEPOOL Reform. . . . . . .119 4. The Independent System Operator . . . . . . . .119 5. Transmission Pricing and Access . . . . . . . .120 6. The Power Exchange. . . . . . . . . . . . . . .122 7. Horizontal Market Power Study . . . . . . . . .124 C. Further Proceedings. . . . . . . . . . . . . . . . .125 TABLE OF APPENDICES 1. Legislative Resolve 2. Proposed Restructuring Legislation 3. Implementation Proceedings and Schedules 4. Survey of Residential and Small Business Customers 5. Estimates of Stranded Costs 6. Resolve Transition Issues 7. Customer Perspective 8. Restructuring Activities in Other States 9. The Deregulation Experience: Lessons Learned for Electric Power Industry (National Regulatory Research Institute, August, 1996) 10. Public Advocate's Consumer Working Group Recommendation 11. Commenters 12. Glossary of Abbreviations I. INTRODUCTION This document advances the Commission's recommendation for electric utility industry restructuring in Maine. An outline of the recommendation is attached in the Executive Summary. Legislative Resolve 1995, ch. 48 "Resolve, to Require a Study of Retail Competition in the Electric Industry" became law on July 3, 1995. Through the Resolve, the Legislature directed the Commission to begin to study restructuring Maine's electric utility industry no later than January 1, 1996 and to submit a report to the Legislature by January 1, 1997. The Commission initiated the study through a Notice of Inquiry on December 12, 1995. To obtain the proposals and views of various stakeholders, the Commission solicited and received written comments. Twenty-two parties filed initial comments, and 11 filed responsive comments. Thirty-five parties filed comments on the Draft Plan issued July 19, 1996. Eleven filed reply comments. The Commission used a variety of means to gather public opinion. Specifically, the Commission held a series of roundtable discussions with various interest groups; created a "homepage" on the World Wide Web to share information and receive comment; held a total of nine public hearings around the state, in May and September; issued four restructuring bulletins; met with groups of small business owners; produced, in cooperation with Time Warner Cable Company, a television program called "Electricity: Can We Cut Your Bill?," which was shown on cable public access channels throughout Maine; conducted formal surveys of both residential and small business customers to learn more about their attitudes, expectations and information regarding retail competition; and participated in regional and national conferences on electric utility restructuring. The recommendation follows careful consideration of the positions and arguments articulated throughout this process, a study of activities in other states and the vast literature on industry restructuring. The following fundamental principles guided the Commission's recommendation to achieve retail competition by the year 2000: * Where viable markets exist, market mechanisms should be preferred over regulation and the risk of business decisions should fall on investors rather than consumers. * Consumers' needs and preferences should be met with the lowest costs. * All consumers should have a reasonable opportunity to benefit from a restructured electric industry. * Electric industry restructuring should not diminish environmental quality, compromise energy efficiency, or jeopardize energy security. * All consumers should have access to reliable, safe and reasonably priced electric service. * Electric industry restructuring should not diminish low income assistance or other consumer protections. * The electric industry structure should be lawful, understandable to the public, and fair and perceived to be fair. * Electric industry restructuring should improve Maine's business climate. The Commission believes the recommendation comports with these fundamental principles and approaches industry restructuring in a manner that is practical, efficient and in the public interest. II. RETAIL COMPETITION AND DEREGULATION A. Recommendation On January 1, 2000, electricity customers in Maine would have the option to choose their power supplier, that is, the entity that sells electric power as distinct from the entity that delivers the power over wires and other facilities. All customers, regardless of size, type, or location, would have the opportunity to elect a power supplier effective on the same date. Customers could contract with power suppliers, purchase from power exchanges and spot markets, and aggregate in any manner they elect. Customers would not need special meters to choose their power provider. After retail competition begins, Maine would no longer regulate, as public utilities, companies that generate or sell electric power. Regulated public utilities would provide electric transmission and distribution (T&D) services. The T&D utilities would have to allow generation service providers /1 to reach any customer within their exclusive service territories. The Commission would retain regulatory authority over the T&D utilities' rates and other activities. The Commission would not require that other states or Canadian provinces allow retail competition in their jurisdictions as a condition to permitting providers from those states or provinces to enter Maine's retail market. Maine customers should have the opportunity to purchase diverse products and services from providers in any location. The Commission would watch closely other states' and regional initiatives concerning retail competition. The Commission would implement, or recommend to the Legislature as appropriate, changes to the restructuring plan proposed here to the extent warranted by experience and developments elsewhere. B. Discussion 1. Existing Industry Structure a. Regulatory system Currently, the Commission regulates the electric industry comprehensively. There is limited competition. This industry structure developed because providing electricity had natural monopoly characteristics, such as economies of scale, which suggested a single entity could provide service at the lowest cost. As a result, electric utilities have provided generation, transmission and distribution services packaged or "bundled" together to all customers within geographic service territories. As a substitute for competition, the government regulated electric utilities to ensure they provided all customers with safe and reliable service at just and reasonable rates. Government imposed a system of regulation called "rate of return" or "cost-of-service." It allowed utilities to collect sufficient revenue to meet the legitimate costs of providing service, including a fair return on necessary capital investment. Rate of return regulation produced reasonable results for many years. In the 1970s, however, high inflation, "oil shocks," and cost overruns for new generating plants, primarily nuclear, increased rates. Because rate of return regulation was based on actual utility costs, ratepayers, not shareholders, carried the business risks of those events. As a result, in the 1980s, regulators focused on "before-the-fact" reviews of utilities' activities; utility commissions began to review utility proposals to construct or purchase generating capacity and established rules for utility resource planning. Nevertheless, the ratepayers continued to carry the primary risks and benefits of power supply decisions. In the late 1980s and early 1990s, Maine's electric rates increased significantly for two principal reasons. First, utilities were bound by contract to purchase power from qualifying facilities (QFs) at rates which were based on estimates of future costs which turned out to be too high. Second, an economic recession reduced electricity consumption, which consequently decreased the revenue available to cover the utilities' fixed operational costs. The rate increases suggested that utilities were not operating as efficiently as possible and that traditional regulatory tools, as applied in Maine, were ineffective at keeping prices low. Moreover, utilities with high rates were vulnerable to competition from different energy sources, such as self-generation and other heating fuels. In Maine and elsewhere in New England, increases in the price of electricity outpaced the increases in other regions of the country. Maine responded by adopting price cap regulation for the electric industry. /2 The price cap approach focuses on price, not the utility's underlying cost, and relies on indices, such as the rate of inflation, to determine rate changes. Price cap regulation provides utilities with pricing flexibility to meet competition and transfers more of the business risks away from ratepayers and onto shareholders. Price cap regulation has delivered predictable and stable prices to ratepayers. For utilities, it has created incentives to minimize cost and allowed some flexibility to compete for current and new customers. b. Development of competition Competition in the generation market began when Congress enacted the Public Utility Regulatory Policies Act of 1978 (PURPA). That legislation was Congress's response to a series of oil embargoes by the OPEC nations and to forecasts that the world was rapidly depleting known oil reserves. PURPA encouraged cogenerators and small power producers to produce energy efficiently and using renewable fuels. /3 The PURPA requirements advanced a non-utility independent power industry that proved entities other than utilities could provide electricity reliably. New technologies suggested that electric generation did not have significant economies of scale and could be delivered in a competitive market. A competitive wholesale market developed in which independent power producers and utilities in New England and Canada competed to provide power to retail utilities. For example, the Maine PUC required utilities to buy the power needed to serve their customers through a competitive bid process. However, because utilities that owned transmission were not generally required to allow competitors to use their systems, competition in the wholesale markets was not robust. Further, the pricing of transmission distorted the wholesale market. To encourage more effective competition in wholesale generation markets, Congress enacted the Energy Policy Act of 1992 (EPAct). EPAct broadened the class of independent power producers and required utilities that owned transmission to allow competitors to use their systems for wholesale transactions. Pursuant to EPAct, the Federal Energy Regulatory Commission (FERC) adopted rules to promote competition in wholesale markets. FERC Order No. 888 (April 24, 1996). FERC required transmission utilities to provide competitors the use of their system, for wholesale transactions, on terms comparable to what utilities provide themselves. FERC also required all utilities to file "open access" transmission rates. /4 In addition, New England utilities and others are developing a transmission pricing system to create uniform prices and terms for transmission throughout the region. /5 The goal of these Federal and regional efforts is effective competition in the wholesale market. Currently, electricity prices in the wholesale market are low, due in part to excess generating capacity in New England. The excess capacity is the result of utilities preparing for an increased need for power that never occurred due to the recession in the early 1990s. New England's low wholesale prices, contrasted with high retail prices, have increased pressure to deregulate the retail market. /6 2. Retail Competition a. Description A cornerstone of restructuring is to allow customers to choose their power provider. Once customers can purchase power in the competitive market, the Commission would not regulate, as public utilities, entities that sell power. The Commission would regulate entities that own transmission and distribution facilities ("T&D utilities"). However, the T&D utilities would no longer buy power for their customers. Customers would have the option to buy power directly from power suppliers or from intermediaries such as a load aggregators, power marketers or energy service companies. The Commission would regulate as public utilities the companies providing T&D services because they would continue to have natural monopoly characteristics. /7 The T&D utilities' rights and obligations would mirror many of those of traditional utilities. For example, T&D utilities would have exclusive service territories and an obligation to connect customers, with wires and other facilities, to the regional electric grid. /8 T&D utilities would have to provide reliable and safe service at regulated rates. Supplying power reliably depends on distribution line maintenance and regional grid operation. Because a regulated T&D utility would maintain the distribution system, restructuring should not adversely affect its reliability. Restructuring may, however, affect the reliability of the regional grid. /9 The T&D utilities would provide their services separately from the companies providing power; customers would no longer buy T&D services and power packaged or "bundled" from one company. Customers would pay T&D utilities regulated rates and pay power providers rates set by the market. /10 Each would charge customers separately; however, T&D utilities and power suppliers could contract to include both charges in one bill. This practice is common in the telephone industry, where local exchange companies' bills often include the charges of unaffiliated long distance carriers. The Commission would establish the T&D utilities' retail rates and rate design. /11 T&D utility regulation is likely to occur through performance based regulation, such as price caps, not rate of return-based regulation. Although some commenters expressed varying degrees of caution regarding the restructuring process, there is general support for customer choice at the retail level. b. Benefits, risks and uncertainties Allowing customers to choose their power supplier should create significant benefits to Maine and its consumers. Wholesale competition holds the promise of lowering the cost of producing power. Retail competition, however, will dramatically increase the number of buyers in the power market. This increase alone should spur even greater efficiencies (and lower prices) in power production. Economists generally agree that competition works best when there are many buyers and many sellers. Creating a direct market relationship between many sellers of power and many buyers should also lead to creative service offerings: better reliability for a premium price, for example, or less reliable service at a discount. Customers will also have the opportunity, either alone or through associations or brokers, to negotiate credit and risk management instruments better tailored to their needs than the products that are generally available under regulation. /12 Just as important, for Maine in particular, retail competition and the deregulation of power production would transfer business risks associated with power generation away from ratepayers and onto investors. Shareholders, not ratepayers, would suffer financial loss if the plants they build, or the contracts they execute, lose value due to changes in the marketplace. Companies that make wise business decisions will thrive, while those that make poor decisions may fail. /13 No matter what companies win and what companies lose, Maine is likely to benefit by shifting investment risk from ratepayers to shareholders. The cost of power in Maine would be determined by the price in the regional and perhaps national competitive market and not by whether Maine's utilities or regulators predict the future accurately. These benefits will occur provided there are effective markets and vigorous competition. Most benefits from retail competition would occur gradually over several years, from innovation and efficiencies as providers construct new plants and tailor their services to meet customer needs. Other benefits, such as lower costs from increased incentives to operate plants more efficiently, will come sooner. The size of the ultimate customer benefit is impossible to predict with confidence. At least initially, however, most of the savings will be from lower power production costs, costs that represent less than one third of today's typical customer's electric bill. While there may be savings in other areas, such as increases in transmission and distribution efficiency and reductions in the amount needed to pay stranded costs, /14 these other savings are not directly related to retail competition. No change as basic and extensive as the deregulation of power production and retail competition is free from risk or uncertainty. There is no qualitative or quantitative analysis that can prove retail competition will, in fact, reduce the total cost of producing and delivering power or whether all customer groups will benefit from cost reductions. For example, the cost of capital to finance new power production facilities is likely to rise because investors could no longer place the risk on ratepayers. Similarly, no tool exists to determine with certainty whether competition among generation providers will decrease the reliability of the electric grid. Nor can we predict with complete confidence whether sufficiently robust markets will develop to avoid anti-competitive behavior, or whether prices will become too volatile. It is possible, but not certain, that funding for research and development of generation technologies will decrease. /15 There is also a risk that retail competition could initially create customer confusion about pricing and new options, limiting the extent to which many customers could benefit. On balance, however, it is reasonable to conclude that retail competition will be more beneficial to consumers than regulation. c. State and local economies Expanding the power market and allowing customers to select their power supplier could improve Maine's economy. Retail competition could improve Maine's business climate by reducing electricity rates below where they would be under the current form of regulation. As importantly, retail competition and the deregulation of power suppliers should reduce the disparity between Maine's rates and those in other states. Maine's rates, like those throughout New England, are significantly higher than those in other regions. /16 Expanding the market from which retail customers can buy power and reducing the price impact from specific regulatory decisions should move Maine's rates closer to the national average. Allowing Maine companies the opportunity to purchase power at prices comparable to those elsewhere, and thus compete more effectively, would improve Maine's ability to attract and retain businesses. Deregulating power production could affect local economies as well. Clearly, municipalities would benefit from moving their own power costs closer to the national average. Their economies would also improve if local businesses and residents achieved similar savings. Deregulation would, however, have tax implications for municipalities with power production facilities in their tax base. Deregulation would change the way in which municipalities assess the value of those facilities, and thus the associated property tax assessments. Specifically, municipalities often base property tax assessments of power production facilities on book or accounting value as a proxy for market value. When power production facilities are no longer owned by a regulated utility, they will likely have a readily identifiable market value. The market values, and consequently tax assessments, could be higher or lower than those based on book value. Also, power production facility owners would have a greater incentive to pursue lower tax assessments than did regulated utilities, which passed tax increases on to ratepayers. /17 Municipalities should anticipate these property tax implications. If the competitive market creates an immediate, disproportionate and negative tax effect on some communities, the Legislature could act to mitigate the level and pace of tax consequences. /18 Deregulating the production and sale of power could affect Maine's paper and biomass industries. Because paper companies consume vast amounts of power, lower rates and diverse services and products would, over the long term, decrease their production costs and improve their financial health. Maine's paper companies' ability to compete successfully within their industry influences their ability to preserve and create Maine jobs. Besides consuming power, paper companies generate power from cogeneration and hydro facilities and sell it into the wholesale market. Maine also has a substantial biomass industry that produces renewable power and provides a market for the waste from Maine's wood products sector. Many paper companies and biomass generators have contracts to sell to utilities that power at prices well above the market rate. Nothing inherent to restructuring justifies abrogation or involuntary modification of contracts. However, when the contracts expire, the paper companies and biomass generators would lose the guaranteed buyer for their power. This is not a result of competition; under current regulation, the contracts have little, if any, chance to be renewed at current rates. While these companies would likely have an opportunity to sell power into the regional market, market prices would probably fall below current contract rates. Some customers may, however, be willing to pay a higher price for renewable or environmentally benign power. Ultimately, the long term benefits of competition for all companies should outweigh the loss of benefits in the near term for those companies with large contracts. d. Rural electricity consumers Retail competition should offer rural and urban customers comparable benefit. Some commenters questioned whether competition would harm residents in rural Maine. The restructuring principles that guided our decisions reflect our concern about rural residents. Specifically, we believe all consumers should have a reasonable opportunity to benefit from retail competition. Price disparities between rural and urban customers are unlikely for two reasons. First, a substantial portion of each customer's bill would be for T&D services that are price regulated and location blind. Second, a customer's location is largely irrelevant to power suppliers absent significant transmission constraints; these do not disproportionately affect rural areas. 3. Timeframe for Retail Competition All customers should have the opportunity to choose a power supplier on January 1, 2000. /19 Most commenters, and the Paradigm, /20 concurred with that date. Beginning retail competition in January 2000 has several advantages. Maine would have an opportunity to observe successes and failures in other states. Several New England states currently intend to implement retail competition, for some or all customers, in 1998. /21 Waiting until 2000 should provide the opportunity to assess whether viable markets develop and whether the mechanics for retail competition will be successfully designed and implemented. A 2000 start date would also allow critical regional initiatives to be completed and tested. Such initiatives include creating an independent system operator of the transmission grid, agreeing on rules for transmission access and pricing, and reforming the New England Power Pool (NEPOOL) to include new power suppliers. /22 Without the successful execution of these regional changes, fair and effective competition is unlikely to develop in Maine. The Commission would carefully monitor regional developments and ask the Legislature to delay beginning retail competition if necessary regional mechanisms are not working successfully. The time frame for beginning retail access also provides significant benefits for addressing stranded costs. Within a few years, the amount of stranded costs in Maine will diminish significantly. This should lessen the controversy over stranded cost recovery, and, more importantly, reduce the risk of projecting and calculating such costs erroneously. The greatest calculation risk of stranded costs is estimating the market value of utility generation assets and power contracts. Valuing assets and contracts later will provide an opportunity to observe transactions in the emerging markets, such as the sale of generation assets. Moreover, because litigation over stranded costs is possible, a later start date may allow Maine to watch costly litigation in other jurisdictions before committing to a specific stranded cost treatment. /23 That experience could reduce the potential for delay and uncertainty inherent in litigation in Maine. Another advantage to beginning retail competition in 2000 is to allow customers time to become educated about their role in a restructured industry. The success or failure of retail competition will not turn on whether a few will navigate well through a proliferation of choices, options and services, but on whether the public as a whole does the same. In short, ratepayers must become effective consumers for choice to be meaningful. That will take time and considerable effort. /24 Finally, restructuring in 2000 corresponds with the conclusion of Central Maine Power Company's (CMP) Alternative Rate Plan (ARP). Coordinating the end of the ARP with the beginning of retail choice would obviate the need for complex regulatory proceedings that would arise if retail competition began later. Similarly, the year 2000 generally coincides with the end of Maine Public Service Company's (MPS) current rate plan and Bangor Hydro-Electric Company's (BHE) pricing flexibility plan. Enron Capital and Trade Resource, National Independent Energy Producers, Alliance to Benefit Consumers, and Conservation Law Foundation argued that retail competition should begin earlier. They suggested that by waiting until 2000, Maine customers will not benefit from competition for several years. We agree that deferring retail competition until 2000 creates the possibility that Maine customers will receive the benefits of retail choice, either real or perceived, later than in other jurisdictions. As noted, some New England states currently intend to allow retail competition for at least some customers in 1998. However, because the cost of power is only a portion of current electric rates, and the efficiency gains of competition will occur over time, it is unlikely that retail competition will substantially and immediately reduce total rates, absent some form of cost-shifting. /25 In any event, if there are significant immediate benefits from retail competition achieved by another means elsewhere, Maine should, and could, accelerate retail choice. MPS, Eastern Maine Electric Cooperative (EMEC), and Madison Paper Industries recommended that Maine set certain conditions before introducing retail competition, such as the existence of mechanisms to ensure regional reliability and proof of a viable competitive market. We agree in principle, but disagree with their proposed remedy. Specifically, we concur that solutions to regional issues are necessary for a robust retail market. But we believe that waiting until 2000 will afford Maine the opportunity to observe the regional solutions at work and decide then whether they suffice to protect consumers. Similarly, we concur that market power would frustrate the ability of competitive pressure to lower rates. But to identify conditions now, without the benefit of retail competition experience in any other state, would require the Commission to predict, rather than accurately evaluate, the market's development. Accordingly, the Commission would complete a market power study in December 1998. If the findings reveal a level of market power that would frustrate competition, the Commission would recommend the Legislature modify Maine's approach. MPS proposed that retail competition begin later in 2000 because stranded costs associated with its Wheelabrator-Sherman contract will be significantly lower by then. We disagree. There is no need to link retail competition to its contract. The stranded cost treatment we propose would give MPS a reasonable opportunity to recover its purchased power costs stranded by retail competition. Customers in MPS territory would pay the costs through a stranded cost charge. MPS's proposal would have the same customers pay the same costs in their bundled electricity rates. This "distinction without a difference" does not justify delaying MPS's customers' opportunity to choose a power supplier. 4. Customer Access and Options a. Simultaneous access Beginning January 1, 2000, all customers, regardless of size, type or location, would have the opportunity to choose a power supplier. Allowing all customers to choose a power supplier at the same time is fair and should bring the full benefits of competition to Maine sooner than a phase-in approach. Most commenters, and the Paradigm, agreed that all Maine customers should have choice simultaneously. The approach follows the restructuring principle that all customers should have a reasonable opportunity to benefit from a restructured industry. Several utilities suggested that allowing choice to all customers at once could present logistic problems, such as difficulties in developing and running new billing programs. The utilities did not present specific information to support that assertion. The start date of January 1, 2000, however, should provide sufficient time to resolve the logistic problems associated with simultaneous retail access for all customers. In the event experience in other jurisdictions reveals practical problems of allowing all customers choice at once, the Commission could stagger the start dates. MPS and EMEC proposed to phase-in retail competition and require small commercial and residential customers to take service from the standard offer as a means to reduce customer confusion. Specifically, MPS proposed that these customers take standard offer service until 2006. We reject the proposal and disagree with the rationale. We do not share the assumption that all residential and small commercial customers will be "confused" by the opportunity to choose suppliers. Consumers who may be confused by the market should not prevent consumers who are not from choosing a supplier. Moreover, a phase-in approach could increase customer confusion and complicate public education efforts. In any event, standard offer service, as an option, would be available to counter any customer confusion. b. Available options The Commission would not proscribe or limit market options. For example, customers and power suppliers could enter bilateral contracts of any duration and on any terms. Customers could also purchase on a shorter term "spot market," using a power exchange. Customers could aggregate at will. "Aggregation" is the organization of customers into groups to purchase power at more attractive prices and terms than an individual customer could get alone. Aggregation will likely be an important means for small customers to obtain more attractive prices in the near term; larger demand generally increases buying power, and provides opportunities to create attractive load characteristics. Therefore, aggregation may give residential customers and small businesses who might not fall in the marketing mainstream prices comparable to those offered to large users. Customer aggregation may occur in many ways. For example, municipalities could aggregate residents' load. /26 Trade organizations could aggregate their members' load. Customers could organize into buyer cooperatives. Finally, electricity marketers could combine individual loads and offer lower cost power. As part of the public education before retail competition, the Commission would inform customers, customer groups and municipalities about aggregation. Customers who understand their options are a critical component of effective competition. c. Special meters Special meters should not be a precondition for allowing retail competition. Some commenters suggested special meters, which measure customer demand and usage in small time increments, may be necessary for bilateral arrangements and other benefits of retail competition. However, there is no evidence that this is a necessary precondition to successful retail competition. The use of average load curves or other estimated usage data should be a workable alternative to special meters. Such an approach should allow generation providers to market services that do not require special meters. Other states' experience should reveal any issues about special meters that are not apparent at this time. Some power suppliers may require that their customers have particular meters or may provide them as part of their service. /27 Alternatively, some customers may find that certain meters minimize power costs by, for example, targeting purchases to low cost hours. Ultimately, the market would decide if customers need special meters. 5. Reciprocity The Commission would not require that other states or Canadian provinces allow retail competition in their jurisdictions as a condition to permitting suppliers from those states or provinces to enter Maine's market. Maine customers should have the opportunity to purchase diverse products and services from any supplier in any location. The number of suppliers in the market directly affects the level of competitive pressure on rates. Utilities have proposed a reciprocity requirement to prevent power suppliers from states that have not authorized retail competition from competing in Maine. They rest their proposals on the need to mitigate revenue losses, and possibly reduce stranded costs. We disagree that reciprocity should be required. Retail competition should begin in Maine when there is a viable, functioning electricity market. The utilities (or, more precisely, the companies who acquire the generation now owned by Maine's utilities) will continue to be able to sell into the wholesale market and the retail market at prevailing prices. That we reject a reciprocity requirement does not diminish those opportunities. The independent power producers (IPPs) suggested a reciprocity requirement to prohibit out of state power suppliers from selling subsidized power in Maine. An example of such power is that available from the quasi-governmental utility structure in Canadian provinces or from states that do not allow retail competition. The IPPs claimed such a requirement is necessary to ensure fair competition among power suppliers. We disagree. To the extent other states or the Canadian provinces allow their ratepayers to subsidize power sold in Maine, consumers here will pay less, at least in the near term. The use of such subsidies in a way that develops market power and forecloses competition is not likely to be sustainable. Moreover, the Commission could not identify with any confidence which power suppliers selling in Maine are subsidized in other jurisdictions. Finally, to the extent any generation provider believes a subsidy exists that is anti-competitive, it may seek a remedy in the courts. /28 Moreover, reciprocity requirements have legal implications for interstate and international transactions between Maine's customers and providers in other states or the Canadian provinces. Attempts to condition entry into the Maine market upon reciprocal treatment by other states would likely be subject to court challenge on constitutional commerce clause or other bases. A reciprocity requirement could be considered economic protectionism of in-state power producers. Such a requirement would burden interstate commerce and discriminate against competitors located in states that have not adopted an electric industry model acceptable to Maine. In cases where states have attempted to limit or burden interstate commerce for the purpose of "simple economic protectionism," the Supreme Court has established "a virtually per se rule of invalidity." Philadelphia v. New Jersey, 437 U.S. 617, 624 (1978). Even if it were determined that the purpose of the reciprocity requirement were not simply the protection of private in-state economic interests, such a requirement would still need to pass muster under the balancing test enunciated in Pike v. Bruce Church, Inc., 397 U.S. 137 (1970). This test requires that a legitimate local purpose outweigh the burden on interstate commerce. Id. at 142. The Court, however, views state reciprocity requirements for trade in other commodities unfavorably. See Sporhase v. Nebraska ex rel. Douglas, 458 U.S. 941 (1982); Great Atlantic and Pacific Tea Co., v. Catrel, 424 U.S. 366 (1970). /29 C. Further Proceedings The Commission would implement retail competition and deregulate power suppliers with caution and flexibility. The Commission would watch closely restructuring in other states and participate in processes on the regional and Federal levels to inform its implementation proceedings. If it appears that retail competition should be delayed or accelerated, or that other modifications are warranted, the Commission would, on its own motion or at the request of an interested party, initiate an investigation. All interested parties would have an opportunity to be heard. If the Commission finds that any provision of the restructuring legislation is not in public interest, the Commission would report to the Joint Standing Committee on Utilities and Energy explaining the basis for the conclusion so that the Legislature could consider modifying Maine's approach. The Commission would establish the revenue requirements that the T&D utilities would be allowed to recover from ratepayers for their services. The Commission would also determine the appropriate design of rates for each T&D utility. While the Commission has traditionally set rates for vertically integrated utilities, these proceedings would also require that the T&D costs and rates be separated from the generation-related costs of the utility. Once the T&D utility's revenue requirement and rate design are determined, a price-cap plan or some other form of incentive regulation could be adopted to provide the T&D utilities with efficiency incentives and to provide ratepayers with stable and predictable rates. Significant issues to be determined in these proceedings are likely to include cost of capital, the value of any assets transferred to the generation subsidiary or other entity, rate design and marginal cost of service, and the proper form of regulation for T&D utilities. III. CORPORATE STRUCTURE AND DIVESTITURE A. Recommendation By January 1, 2000, Maine's investor-owned utilities (IOUs) /30 would transfer all generation-related assets and activities, including all electric energy sales activities, to corporations distinct from their transmission and distribution (T&D) businesses. After this date, investor-owned T&D utilities could engage in generation-related businesses only through a separate corporation. Maine's consumer-owned utilities (COUs) /31 would not separate generation from T&D. Contractual obligations between qualifying facilities (QFs) and electric utilities would remain with the T&D utilities; however, by January 1, 2000, Central Maine Power Company (CMP) and Bangor Hydro-Electric Company (BHE) would sell the rights to the capacity and energy associated with their QF contracts. Maine Public Service Company (MPS) would transfer these rights to its generation affiliate. By January 2006, CMP and BHE /32 would divest their generation assets and related functions. The remaining T&D utilities would not be affiliated with any company that owns generating facilities or sells power. T&D utilities would maintain their contracts with QFs and could own small, distributed generation facilities installed to minimize distribution costs. MPS could maintain an affiliated generation company after 2005, but only to provide retail service in its territory. MPS's affiliate would not be permitted to construct or acquire ownership interest in generating facilities, and would be permitted to make only wholesale sales incidental to reducing costs of its retail service. Maine's utilities would not be required to divest their ownership in Maine Yankee unless the plant's operating life extends significantly past 2008. To the extent they retain ownership after 2005, CMP and BHE would be required to sell the rights to power associated with that ownership. MPS's Maine Yankee entitlement would remain with its generation affiliate. T&D utilities would retain the liability for nuclear plant decommissioning costs. After December 1999, T&D utilities could modify QF contracts but could not extend the term of any contract or increase purchases pursuant to any contract. Consistent with the prohibitions of T&D utility power production and sales, T&D utilities could not enter new contracts with QFs after December 1999. CMP and BHE would transfer the rights to power they now hold under contracts with QFs through competitive bidding. CMP and BHE would complete the bidding in time to transfer all such power effective January 2000. To protect against the risk of changing market prices, CMP and BHE would periodically resell these rights. COUs would not be required to divest, or structurally separate, generation from T&D and could continue to construct and own generation facilities, and purchase and sell electric power. After 2005, COUs could market electric power only within their franchise territories, and could make only wholesale sales incidental to reducing costs of their retail service. The Commission would limit the investments in and purchases of power to those necessary to serve the COUs' own customers. B. Discussion 1. Need for Divestiture a. Power production and sales BHE and CMP would be required to divest their generation assets, except Maine Yankee, by 2006. After divestiture, companies that own generation facilities would have no affiliation with BHE and CMP. BHE and CMP would also be prohibited from selling power. These requirements would ensure effective competition in the retail market by reducing the T&D utilities' opportunities to exercise market power. Market power exists when one company can gain an advantage over competitors through its affiliation with the provider of a related service. If a T&D utility is affiliated with a power provider, the T&D utility would have the incentive and the ability to use its monopoly position in the T&D market to favor its affiliate. Favoritism could take the form of "self-dealing" (i.e., favoring the affiliate when purchasing services), steering customers toward the affiliate, or giving the affiliate preferential access to information or T&D services. Common ownership of power production facilities and T&D is an impediment to effective competition. Removing the impediment through divestiture, however, has costs. First, divestiture would impose transaction costs including fees for investment bankers, attorneys, accountants and other expenses. Next, divestiture creates the risk that T&D utilities, and their ratepayers, will not realize the full value of the assets because many generation assets could be on the market simultaneously, or because the divestiture occurs when market values for power production facilities are low. Accordingly, utilities would have flexibility to plan and carry out divestiture over several years, and the responsibility to minimize divestiture-related costs and risks. Despite the costs and risks, the benefits of CMP's and BHE's divestiture of their generating assets predominate. Effective competition among generation providers is critical for consumers to benefit from a right to choose suppliers. Effective competition depends, in large part, upon the T&D utility being a neutral link between power providers and customers. Ordering divestiture and prohibiting the T&D utility from selling power into the retail market are necessary to ensure the T&D utility serves as that neutral link. Non-utility commenters, including the Office of the Public Advocate (OPA), Conservation Law Foundation (CLF), independent power producers (IPPs), and marketers agreed divestiture is needed to ensure the market works effectively and efficiently. The Paradigm recommended divestiture for Maine's IOUs. In addition, CMP has stated its intent to divest before 2000. BHE, MPS and Eastern Maine Electric Cooperative (EMEC), however, believe divestiture is unnecessary. They argued that functionally separating generation from T&D, and creating separate subsidiaries or affiliates under a holding company structure would suffice. They suggested that regulatory oversight of affiliate transactions would prevent market abuse. For several reasons, we believe structural separation alone is inadequate. First, structural separation would require continued regulatory oversight, which would depart from the restructuring principle that, where viable markets exist, market mechanisms should be preferred over regulation. Ensuring arms-length transactions in a competitive market would protect customers more effectively than regulating affiliate conduct. Reviewing, in the regulatory process, the details of multiple and complex affiliate transactions would be cumbersome, litigious, and expensive. Ultimately, it would protect consumers less effectively than the direct price discipline of a competitive market. Divestiture would allow competitive forces to replace regulation as the guarantor of arms-length dealing. Second, affiliated companies' incentives to take advantage of joint ownership of power-producing and T&D facilities are identical to the incentives in a vertically integrated utility. In fact, the incentive for abuse in the affiliate model may be greater than the incentive in the vertically integrated utility model under traditional regulation because there would be no limit on the profit from power sales. At the same time, regulators' ability to detect and remedy such conduct would diminish. Specifically, under a subsidiary structure, there are schemes that favor the unregulated generation company at the expense of the T&D utilities' customers. These include using capital structures to subsidize higher risk, non-regulated enterprises; "creative" accounting for shared costs; preferential access to T&D customer information and records; insufficient reimbursement to the regulated T&D utility for personnel transferred to the unregulated subsidiary; expansion, or refusal to expand, the transmission and distribution systems to the benefit of affiliated generation companies over other competitors; and preferential bundling of ancillary services. Such activities are difficult and expensive to detect and correct through regulation or anti-trust litigation. The utilities argued that even if T&D utilities are prohibited from owning generation, they should be allowed to sell power to retail customers. We disagree. Permitting T&D utilities to sell power would create the same problems as allowing them to own assets or companies that produce power. A T&D utility would have the same incentive and ability to favor its sales affiliate or partner. To support its argument that T&D utilities should be allowed to sell power to retail customers, BHE described the benefits it could give customers by virtue of its knowledge of customers' needs. BHE's comments, however, merely emphasize the risk of allowing the T&D utility to sell retail power. BHE's knowledge of, and relationship with, customers results from its public utility status; using those to advantage its own power sales is precisely the kind of unfair advantage in the market that no seller should have. Whatever useful customer information the utility developed by virtue of its public utility status should be available to all competitors in the market. T&D utilities should continue to develop services, information and customer expertise to deliver energy most efficiently to customers of all energy providers. But transmission, distribution, voltage regulation maintenance, and other core services /33 must be available without undue discrimination to all customers and to all energy providers to create and maintain an effective competitive energy market. BHE and others suggested that regulation could resolve issues arising from T&D utility involvement in selling energy to retail customers. Again, we disagree. Regulation would not work any better over a T&D utility retail power sales operation than it would over a T&D utility power generation operation. Also, creating the need for more regulatory oversight contradicts the principle that, where viable markets exist, market mechanisms should be preferred over regulation. The Commission would retain authority to allow T&D utilities to acquire or continue to own small, distributed generation facilities when that ownership would minimize distribution system costs. The Commission would consider approving acquisitions case by case. The T&D utilities would not be allowed to sell power at retail from a distributed facility, and all revenue from sales at wholesale would flow to the T&D utility. b. Other services There would be no blanket proscriptions of T&D utility involvement in unregulated businesses. Except for power-related operations, the issue of unregulated activities is separate from retail competition. Questions about the range of services T&D utilities should be allowed to provide and the types of subsidiaries and affiliates they should be permitted to form cannot generally be answered in the abstract. The Commission would, for the most part, consider those issues as they arise in the same manner as it does today. 2. Authority to Order Divestiture Historically, the generation, transmission and distribution of electricity were considered natural monopolies requiring comprehensive regulation to protect customers. Public utility regulation thus covered the range of utility actions, including the purchase or construction of major generation or transmission projects; the creation or dissolution of subsidiaries and affiliated interests; oversight of affiliated and insider transactions; bond issues, share offerings and other financial transactions; and rates. In addition, the State determined utilities' service territories. Restructuring rests on the premise that electric generation is not a natural monopoly and should not be provided and regulated as such. However, T&D remains a natural monopoly service and would be regulated accordingly. Under current law, the Commission must approve utility proposals to build, purchase or invest in new generating sources, or to enter into significant contracts for power. In Public Utilities Commission, Re: Investigation of Seabrook Involvement's by Maine Utilities, 67 PUR 4th 161 (MPUC, 1985), the Commission found it had the authority to order Maine utilities to divest their interests in a nuclear power plant. The Commission has also denied utility proposals to purchase or construct power plants. Whether or not the Commission has current statutory authority to order complete divestiture, however, it is clear that the State, through the Legislature, may order divestiture or delegate that authority to the Commission. /34 Some commenters suggested that mandatory divestiture may violate the takings clause of the United States Constitution. On the contrary, the United States Supreme Court found mandatory divestiture of utility assets under the Public Utility Holding Company Act (PUHCA) SS 11(b)(1) does not violate that clause. See North America Company v. SEC, 327 U.S. 686 (1946). State-ordered divestiture raises no constitutional issues different from those addressed by the Court in North America. Moreover, although the takings clause could be implicated if forced divestiture resulted in a substantial reduction in the value of investors' holdings in the utility, the Commission would allow investors the same opportunity as they have now to recoup the value of their holdings though the stranded cost charge and the fair determination of the value of divested assets. 3. Process for Divestiture CMP and BHE should have the flexibility to complete divesture over several years. Therefore, the Commission would permit a two-step process. First, by January 2000, CMP and BHE would transfer their generation assets, entitlements, and related activities to companies structurally separate from their transmission and distribution businesses. The Commission would determine, prior to retail competition, the degree of separation necessary to protect T&D ratepayers and the competitive market. Second, by January 2006, CMP and BHE would divest these assets, entitlements and activities. CMP and BHE could propose to divest some or all generation earlier. This flexible, two-step process would reduce the risk of the T&D utilities, and ratepayers, receiving too little value for these assets, and thus help reduce stranded costs. The OPA, the IPPs, and the Industrial Energy Consumers Group (IECG) argued for divestiture to occur sooner, on the grounds that T&D utilities could behave, before 2006, in a way that would hinder the development of a healthy competitive market. The IPPs and IECG proposed no phase-in period; the OPA proposed divestiture by 2004. We are persuaded that the likely benefits, in the form of lower stranded costs, of a longer period with flexibility outweigh the likely harm to competition during the transition. The concerns raised by these commenters, however, underscore the need for Commission oversight of utility affiliate transactions during the pre-divestiture period. 4. Separation of Qualifying Facilities and Maine Yankee Power a. Qualifying facility contracts Contracts between IOUs and QFs would remain with the T&D utilities. BHE and CMP would periodically sell their output to the QF power to the highest bidders. This periodic bidding would help reduce errors in estimating stranded costs. MPS would transfer the output of its QF contract to its generation affiliate. The nature of the contracts between QFs and utilities distinguishes them from other generating assets. The parties entered the contracts pursuant to Federal and state policies. That the payment obligations rest with utilities is a material term of the contracts. Nothing inherent to restructuring requires abrogating that term. QF investors would continue to have the opportunity to obtain their revenues from a regulated utility. Placing the QF contracts with the T&D utility, coupled with periodic bidding for the power, also reduces the risk that stranded costs relating to these contracts would be estimated incorrectly. If the T&D utility divested the QF contracts, they would be held by entities not linked to the T&D utility by common shareholders. This means that if market conditions increase the value of power it would be difficult to recover additional value from the unregulated company holding the contract. If the estimate of value is made at the time of divestiture, therefore, and market conditions change, the T&D utility would be unlikely to be able to adjust its rates to reflect those changes. /35 By keeping QF contracts with the T&D utility, the Commission could periodically adjust the stranded cost rates to reflect changing market conditions. Likewise, continuing opportunities for renegotiation and mitigation would remain available to benefit ratepayers; these could be lost if QF contracts move to another entity. The IECG, the IPPs, and the OPA supported this treatment of QF contracts. CMP opposed it and argued that QF contracts ought to reside with the unregulated generation company. According to CMP, QF contracts should be subject to the same risks as other generation assets. The flaw in CMP's argument is that QF contracts are not like other generation assets. CMP's shareowners now own the full economic value of its power plants, together with the right to any associated stranded cost recovery. Divestiture will not change that shareowner value. If the plant is sold, shareowners will obtain the full economic value (as proceeds of the sale) plus the right to associated stranded cost recovery (if any) as shareowners of the T&D utility. If divestiture is accomplished through a stock spin-off or similar transaction, the sum of the value held by the deregulated owner of the plant and the value of the stranded cost recovery allowed the T&D utility should be no less than the value they hold today. For QF contracts, however, there is another set of shareowners, namely those now owning the right to the revenues. If CMP's proposal is intended to reduce the certainty of those shareowners' recovery, by exposing them to additional market risk, the proposal is inconsistent with our conclusion that restructuring is not sufficient reason to change the contracts. Under CMP's proposal, the stranded cost revenues needed to pay the QFs and recovered by the T&D utility would flow to the generation company. If those revenues are sent directly to the QF owners, CMP's proposal is in all substantial respects identical to the Commission's. If they are not, the increase in risk to the QFs cannot be squared with law or equity. b. Maine Yankee The T&D utilities would retain nuclear plant decommissioning obligations. The utilities would not be required to divest their ownership interests in Maine Yankee, but would be required to transfer the rights to the output to an affiliated generation company. After 2005, BHE and CMP would be required to sell the rights to the output to the highest bidder. Maine Yankee entitlements present unique issues when evaluating the value and practicality of divestiture. Maine Yankee's operating license is currently scheduled to expire in 2008, two years after the date by which CMP and BHE would be required to divest other generation assets. CMP believes that divestiture's transaction costs and other risks would not be justified given Maine Yankee's remaining license life. CMP's arguments are persuasive. If Maine Yankee's operating license is extended significantly beyond 2008, the Commission would reassess whether divestiture should be required. Some commenters expressed concern that leaving decommissioning obligations with the T&D utility places the risk of decommissioning cost overruns on ratepayers rather than investors. They argued that if past amounts collected for decommissioning prove inadequate, ratepayers will be responsible for shortfalls. Under Federal law, however, divestiture cannot alter ratepayer exposure to this risk. FERC establishes decommissioning rates. Under the "filed rate" doctrine, state commissions cannot adjust them. The State has limited authority to place the risk of decommissioning cost overruns on investors or to protect against such overruns by increasing current or future decommissioning funds in rates. 5. Maine Public Service Company MPS should not be required to divest its generation or be prohibited from purchasing and selling power as needed to serve customers in its service territory. MPS would, however, be required to do these activities through a separate subsidiary. After 2005, sales by MPS's affiliate outside its franchise territory would be permitted only to the extent necessary to minimize the cost of serving MPS's native load customers. Because it is small, the transaction costs for MPS to divest could outweigh the benefits to MPS's customers. First, even though customers' purchasing option may be fewer than elsewhere in Maine, even a small number of competitors should reduce the risk that MPS could use market power to its customers' disadvantage. Second, MPS's relative isolation (MPS is not part of the New England Power Pool (NEPOOL)), raises a concern about sufficient power supply. The Commission would periodically review whether divestiture should nevertheless be required. MPS agreed, arguing that forced divestiture might leave northern Maine without a reliable and economic generation supply. MPS also asserted that a forced sale would risk the loss of substantial value associated with its Canadian subsidiary. According to MPS, the assets of this subsidiary, principally a hydro-electric plant located in New Brunswick (Tinker Station), could be expropriated by the Province with reimbursement to MPS well below the assets' value. OPA, EMEC and others supported exempting MPS from divestiture. The IECG disagreed with granting MPS a blanket exemption from divestiture, but would support exempting Tinker Station. IECG noted that much of MPS's generation is located outside Aroostook County, and within NEPOOL; this generation, at least, ought to be treated similarly to that of CMP and BHE. The IECG also argued that it could be beneficial to Aroostook County if restructuring made MPS less isolated from the rest of New England. On balance, it appears that divestiture's transaction costs would likely outweigh these benefits. Moreover, it is unlikely that, absent divestiture, MPS's ownership interests in Maine Yankee and Wyman 4 would be large enough for MPS to have noticeable market influence. Finally, nothing would prevent other retail power sellers from competing in MPS territory; this will allow the market to determine the extent to which MPS becomes more integrated into the New England market. 6. Consumer-Owned Utilities COUs would not be required to divest generation assets and would be permitted to continue to purchase and sell generation to serve retail customers in their territories. COUs would have to limit power purchases to the amount necessary to serve their customers. Like MPS, after 2005, a COU would be permitted to sell outside its territory only the incidental excess power acquired to serve its native load. This limit would not modify or limit any current legal right COUs have to expand their service territories or serve new customers. COUs are smaller and serve fewer customers than most investor-owned utilities and also have a fundamental difference of purpose and governance that warrant different treatment. Specifically, an IOU is a business managed to profit investors. COUs seek to provide the best value to their members or customers, not to earn profit for investors. COUs, including municipals and cooperatives, are directly answerable to their members or customers through political or other channels not available to customers of investor-owned utilities. The absence of the incentive to maximize investor profit, combined with direct avenues of redress for customer dissatisfaction, virtually eliminates the risk that the COUs will use their power sales activity to the detriment of their customers. Finally, although COUs may have tax or other advantages over IOUs, these advantages benefit COU customers and are unlikely to harm other customer groups. The COUs agreed that they should be permitted to sell power. The OPA and the IPPs also agreed but would prohibit COUs from buying new generation. The Paradigm exempted COUs from separation and divestiture requirements. CMP, BHE, and MPS, on the other hand, disagreed. BHE and CMP asked whether allowing COUs to retain control of and continue to purchase generation would give them a competitive advantage. CMP claimed that today's small COUs could grow. The limits on COU generation purchases and their lack of profit incentive should, however, largely resolve concerns raised by these commenters. Absent extraordinary and unforeseen growth, the impact of allowing COUs to own and sell power either within their service territories or elsewhere is slight. C. Further Proceedings The Commission would conduct a proceeding, beginning in mid-1998, to establish the requirements for structural separation between the T&D utilities and their generation-related activities. The Commission would precisely define the parameters of structural separation necessary to curb market power and cross-subsidization. Issues likely to arise concerning structural separation include what codes of conduct need to be established to ensure that the separation is effective, restrictions on employee activities, accounting standards, and information and service comparability requirements. Once separation standards are established, each utility may be required to make a compliance filing. CMP and BHE would file their plans for full divestiture prior to 2006. The Commission would review the plans and ensure their consistency with the objectives of restructuring. A primary issue in these proceedings would likely be whether the plan is reasonably designed to capture the highest possible value. IV. STANDARD OFFER A. Recommendation Standard offer service would be available to all customers who do not choose a competitive power provider or who cannot obtain power in the market at reasonable terms. From the customers' perspective, the service would be comparable to that currently available from utilities. The terms of the service would be simple and understandable. The Commission would cap the standard offer rate so the cost of power and transmission and distribution (T&D) services together does not exceed the cost of electricity before retail competition. As the market matures, the Commission would reevaluate the need for the standard offer, and its structure. The T&D utility would administer a competitive bid process to select the standard offer provider for its territory. The T&D utilities would solicit and evaluate bids and recommend a provider to the Commission. The Commission would review the process, supporting documents and finally select the provider. Prior to the bidding, the Commission would establish terms and conditions for standard offer service, including eligibility criteria, requirements for entering and exiting the service, and credit, collection, and disconnection provisions. B. Discussion 1. Need for Standard Offer Service Customers would receive standard offer service if they do not elect or cannot obtain service from a competitive power supplier. Standard offer service is power supply that when packaged with T&D service would resemble service currently provided by utilities. For instance, the Commission would approve the price and service terms and the customer would receive one bill. Standard offer service departs from reliance on the market, but provides a safeguard for the public during the transition to competition. Most commenters supported some type of standard offer service. As experience in the evolving telecommunications industry suggests, many customers may not have the immediate ability or interest to elect alternative providers of services historically provided by a monopoly. Customers opting not to choose may predominate, at least initially, in the electricity market. Other customers, for financial or other reasons, may not be able to obtain service from a competitive provider on reasonable terms. The standard offer service should guarantee that all customers have access to electricity service at a reasonable price. Bangor Hydro-Electric Company (BHE) and the National Independent Energy Producers (NIEP) argued that standard offer service is unnecessary because the retail market should meet the needs of all customers. We are less confident that a fully competitive power market will develop immediately. Even if the market developed quickly, customers may be confused, at least initially, and make unfortunate, or even no, choices about suppliers. The service would give customers time to adapt to changes without the risk of immediate price increases. At some point, it may be appropriate to reduce or end government intervention in the competitive market. For example, if a robust power market develops and sufficient market intermediaries emerge, a more narrow standard offer may suffice, comparable to an "assigned risk pool" in the insurance industry. As the market matures, the Commission would reevaluate the need and structure of standard offer service. 2. Provider of Standard Offer Service a. Competitive bid The T&D utilities would administer a competitive bidding process to select the standard offer provider in each of their territories. Selecting the standard offer provider through bidding should allow standard offer customers to benefit somewhat from competitive pressure on rates. The Paradigm advanced a similar periodic bidding approach; the Maine Equal Justice Project (MEJP), Alliance to Benefit Consumers (ABC), Coalition for Sensible Energy (CSE), Enron Capital and Trade Resources (Enron), and Maine's independent power producers (IPPs) concurred. The utilities urged that T&D utilities provide the standard offer service and obtain power either through a bid process or other mechanisms. They believe that method is simple, would reduce customer confusion and would help them remain viable. More specifically, Central Maine Power Company (CMP) proposed that the T&D utility would provide the service on a "regulated basis" and get regulatory preapproval of significant purchasing decisions so that it would be insulated from major risks. The IPPs proposed that T&D utilities provide the standard offer service by getting bids for portions or "blocks" of the standard offer load. The IPPs' proposal for standard offer "blocks" is similar to the decremental avoided cost process used previously in qualifying facilities (QF) bidding. /36 The IPPs claimed that approach is essential to allow small power producers an opportunity to compete for part of the standard offer load. The issue is whether the market should decide who provides standard offer service or whether the Commission should create a scheme that follows present practice by granting the T&D utilities the right to offer the service with regulatory oversight. One principle that guided our decision making was that where viable markets exist, market mechanisms should be preferred over regulation. We believe for several reasons that the market would do a better job than regulators selecting the provider. First, the bid process would declare as the standard offer provider the entity that can best combine supply resources and offer the lowest price. There is no reason to assume that T&D utilities would necessarily outperform the market. Second, the bid process, relying on market forces, would minimize regulatory oversight of supply acquisition. If the T&D utilities were automatically declared the standard offer service provider, the Commission would have to decide whether the T&D utility secured the best possible resource portfolio. One goal of deregulation is to shift risk away from ratepayers and onto shareholders; CMP's suggestion would preserve PUC protection of investments and continue ratepayer risk. Third, industry restructuring should not, by design, guarantee local utilities competitive advantages. Designating T&D utilities as standard offer provider would almost ensure they initially retain most customers. Finally, the standard offer service would supply customers at a fixed price, without the customers' involvement in selecting the provider. Customer confusion is of real consequence when that confusion leaves them vulnerable to abusive or deceptive business practices. By design, the standard offer shields customers from that risk. b. Bidding process Each T&D utility would solicit, evaluate and rank bids, and submit their recommendation, with supporting documents, to the Commission. The Commission would review the materials and select the standard offer provider. The winner would contract with the T&D utilities to provide the service pursuant to Commission standards. Also by contract, the T&D utilities would include, but list separately, charges for the standard offer in their bills. Power providers affiliated with a T&D utility could bid to provide standard offer service in the utility's territory. Similarly, consumer-owned utilities (COUs) could bid to provide the standard offer in their territories. The IPPs argued that affiliated generation companies should not be able to bid because there is too great of a risk of self-dealing, cross-subsidization and anti-competitive tactics. We agree there are some risks. The principal risk, in our view, is not cross-subsidization, as the rates of the T&D utility and the standard offer would be capped. Instead, the risk that the generation affiliate would have an unfair advantage centers on its potential access to T&D utility information. The short term remedy, until divestiture, is for the Commission to ensure that the T&D's generation affiliate has only the same information as every other potential bidder. The Commission would decide many details of the standard offer service in proceedings prior to 2000. For example, one issue is the appropriate length of time between rebidding the standard offer service. The Paradigm proposed bids occur every five years. Enron urged the Commission to bid the standard offer every year. We decline to choose a specific interval now. To define the length of service commitment, the Commission would consider factors such as price stability, market risk, and flexibility. The standard offer proceeding would also address issues such as rate design, and customer class and voltage level differentiation. Suppliers would offer other service terms in their bids. Finally, some commenters expressed concern over situations in which the standard offer provider fails to fulfill its service obligations or if no entity submits a satisfactory bid. In the standard offer proceeding, the Commission would consider means to protect against a provider's failure to give service. For example, the Commission could require the standard offer provider to post a performance bond. Or, the Commission could direct the T&D utility to provide service through the spot market pending selection of another provider. As discussed below, if bids are above the cap, the Commission would investigate whether retail competition is appropriate for Maine at that juncture, and could recommend that the Legislature delay competition. The Commission could also reconsider allowing the T&D utility to provide the standard offer, particularly if only a few service territories have unsatisfactory bids. c. Standard offer service territories Each T&D service territory would have a standard offer service that may be supplied by different providers under terms unique to each. This approach should encourage bidders to craft creative proposals tailored to a territory's specific characteristics. That would serve customers better than a one-size-fits-all package. It would also allow the Commission to evaluate the merits of various service packages and refine subsequent bidding processes. The Office of the Public Advocate (OPA) suggested that separate standard offer bids in each T&D service territory could result in marked differences in prices due to variations in loads and customer composition. Therefore, the OPA proposed, as an alternative, that Maine be subdivided into four or six regions with about the same mix of industrial, urban and semirural, and island/remote customer loads to prevent inequitable distribution of benefits across the State. The OPA's suggestion would at least complicate and perhaps increase the cost of standard offer service without providing offsetting benefits. Geographic cost differences are primarily a function of transmission and distribution costs. Retail competition will not alter that fact. Customer location should remain largely irrelevant to power suppliers. The OPA did not couple its proposal with any persuasive rationale for the view that standard offer bids coterminous with utility service territories will cause substantial price variations. The OPA's proposal would likely create administrative and practical obstacles disproportionate to any benefit. d. Availability of information Before soliciting bids, T&D utilities would give potential bidders customer information necessary to formulate an informed bid. The Commission would decide what specific information the T&D utilities should disclose from the general categories of customer load and usage data, such as monthly demands and energy consumption, the number of customers in each customer class and possibly general credit data, including uncollectible revenue and the number of customer disconnections. If the T&D utilities incur additional costs to develop and produce the data they could recover those through rates. To uphold individual customer confidentiality, the T&D utilities would provide information in aggregate in a standard form. T&D utilities would release customer-specific data only with permission by the customer and there could be confidentiality protections. The T&D utilities' possession of confidential customer-specific information and perhaps other data may unfairly advantage their generation affiliates. The same effect would result if a COU bid in its territory. The Commission would restrict the type of information the T&D utilities may disclose to employees of their affiliated companies or COUs that bid to provide the standard offer. CMP argued that it should not have to release information it developed in its market research efforts. It claimed to have gathered that category of information at considerable expense and therefore argued it alone should use it for marketing purposes or sell it for profit. We believe information utilities hold by virtue of their status as providers of T&D services must be given to standard offer bidders. /37 Other kinds of information, such as that which private entities could obtain in other pursuits, would not be subject to mandatory disclosure. 3. Price Cap on Standard Offer Service The Commission would cap the standard offer so that its price plus the regulated rates of the T&D service, including any stranded cost charge, would not, on average, be higher than total electricity rates just before the beginning of retail competition. The Commission would consider whether the cap should escalate at an inflation-based index or by another mechanism. A cap on the standard offer service would test whether retail competition will generally benefit all customer groups. If the initial standard offer bids exceed the cap, it may be evidence that the promised benefits of industry restructuring are illusory. In that case, the Commission would investigate, with an opportunity for all to participate, whether Maine should delay retail competition until it can be certain that the new framework would not increase rates for what may be most customers. Issues such as whether all or only some territories had bids above the cap would be likely to affect the Commission's findings; if bids in all territories exceeded the cap, that would certainly argue for delay. The Commission would, of course, report the resulting recommendation to the Legislature for its consideration. The American Association of Retired Persons (AARP), MEJP, and CSE supported a cap. AARP suggested the cap reflect 1995 rates. The Paradigm proposed a cap based on the total cost of existing service. The utilities, however, argued that setting a cap and using bid prices as a litmus test for retail competition is improper and unworkable. Specifically, BHE asserted that the Commission may be designing deregulation process to fail by requiring that standard offer service be no more expensive than 1999 retail electric rates. BHE and CMP suggested that by 2000, without restructuring, rates might increase if, for example, fuel prices rise. Therefore, CMP suggested it is more appropriate to compare the standard offer bids to rates that would have been in effect under regulation. The utilities' argument has merit. The purpose of the standard offer cap is to ensure restructuring does not harm Maine's customers. Accordingly, rates that would have existed absent competition are a fair comparison. However, that comparison would require a counter-factual analysis that would be impractical or, perhaps, impossible. /38 Therefore, the rates when retail competition begins are the best proxy for what electric rates would be absent restructuring. For several reasons, a standard offer cap based on the rates in effect just before retail competition is workable and does not portend failure. First, absent retail competition, generation costs should decrease as purchased power contracts expire, generation assets depreciate, and regulatory assets are reduced. Those decreases in costs over the years make it reasonable to believe bidders could offer a rate below the cap. Second, the Commission would consider escalating the cap according to an index. Third, if all bidders exceed the cap, the Commission would not automatically delay retail competition, but would investigate whether it is in Maine's interest to wait. If there is persuasive evidence that rates would have significantly increased absent restructuring, it would be one factor to consider in deciding whether to recommend delaying competition. 4. Terms and Conditions on the Standard Offer The conditions and restrictions on the standard offer must balance its purpose with the need to keep the price as low as possible. The Commission would adopt standards governing the standard offer in the general categories of eligibility requirements, entry and exit restrictions and credit, collection and disconnection practices. As the market matures and as customers become experienced energy buyers, the Commission would amend the initial requirements accordingly. For the standard offer to be effective serving those who cannot obtain service on reasonable terms from competitive providers and to allow customers time to adjust to competitive options, customers should have flexibility to enter and exit the standard offer unimpeded by restrictive policies, at least during a transition period. However, allowing every user of electricity unfettered freedom to enter and exit the standard offer may increase its cost. On balance, we are inclined to allow few, if any, restrictions on entry or exit during the early years of retail competition to encourage customers to experiment with the market. Later, it may be appropriate to limit the number of times a customer may enter and exit, specify times of the year when a customer may change service, or charge a fee to reenter. Further, we are inclined to exclude large customers, for example those with loads over a specified amount, such as 1 MW. Large customers tend to be sophisticated energy users and would probably have competitive choices immediately. Therefore, the purpose of the standard offer option does not apply. Also, if large customers could take standard offer service, and if there were limited restrictions on entry and exit, the cost of the service would likely increase for all customers. /39 Finally, we would adopt credit, collection, and disconnection rules to govern the standard offer. The availability of standard offer service would not relieve customers of the obligation to pay for service. The standard offer provider would have authority to disconnect a customer for nonpayment, but only pursuant to Commission rules. Disconnecting customers who do not pay for service can avoid the accumulation of uncollected debt that would increase the standard offer service cost for other customers. C. Further Proceedings The Commission would, in proceedings beginning in late 1997, establish terms and conditions (including the rate design) for standard offer service, and would later (during 1999) review and approve the selection of bidders to provide standard offer services in each of the T&D utility service territories. There would be two groups of proceedings related to standard offer services. First, the Commission would conduct a proceeding to establish terms and conditions for standard offer service, including eligibility criteria, requirements for entering and exiting the service, and credit, collection, and disconnection provisions. Once the design of the terms and conditions of standard offer service has been established, the T&D utilities would request bids from power suppliers and would present the results of the bidding, together with a recommendation, to the Commission. The Commission would review the utilities' filings and would determine the winning bidders. These activities would be completed by mid-1999 so that the standard offer providers would have sufficient time to secure the necessary resources to provide the service, and to establish customer service programs. Issues in these proceedings would likely include whether the bidding process was fair, and whether the bidders met reasonable standards for reliability and financial security. The Commission would review the winning bids for standard offer service to ensure that the price of power, when added to the price for other services (e.g., T&D) and the stranded cost charge would not, on average, be higher than the electricity rates paid during 1999. In the event that bids were too high to achieve this objective, the Commission would consider whether it should recommend modifications to the process of electric restructuring to ensure that regulation in Maine remains consistent with the public interest. V. CUSTOMER PROTECTION AND LOW INCOME ASSISTANCE A. Recommendation The Commission would adopt standards to govern the relationship between customers and power suppliers. The subject matter would include the power suppliers' registration to offer service, the obligation to notify customers of price and term changes, and to file information with the Commission. The Commission would have jurisdiction to resolve some types of disputes between customers and power providers. The Commission would have authority to investigate and remedy business conduct that is abusive or anti-competitive. The transmission and distribution (T&D) utilities and the standard offer provider would have credit, collection, and disconnection obligations comparable to those that currently govern utilities, with some variation to reflect the changed marketplace. For instance, T&D utilities would not disconnect customers for failing to pay their power supplier. T&D utilities could, however, disconnect customers for failing to pay for T&D or standard offer service. The Commission strongly recommends the Legislature fund electricity- related low income assistance through tax revenues. If it elects not to, the Commission would continue to include low income assistance in T&D rates. The Commission would begin immediately to educate the public about the opportunities and obligations of retail competition. In addition to diverse education efforts, the Commission would require utilities to separate charges for power from the remainder of the utility bill beginning in January 1999. B. Discussion 1. Oversight of Generation Providers The Commission would regulate power suppliers' interactions with customers, but not the prices or services they offer. Customers' ability to select another supplier would replace regulation as the price control system. Even where customer choice controls cost, there must be some rules to govern the rights and obligations of both buyers and sellers. Specifically, in the near term, customers would have to learn to be effective consumers of a product they have never before bought in the open market. Their inexperience may cause confusion or, worse, make them vulnerable to suppliers who capitalize on that inexperience with devious business practices. Indeed, the public reaction to competitive opportunities in telecommunications suggests that the public wants, and expects, some Commission oversight of new providers of competitive services. Accordingly, as detailed below, the Commission would oversee power suppliers, including registration, business practices, filing requirements, and billing formats. Similarly, the Commission would adopt rules to govern credit, collection and disconnection issues. Finally, because information is customers' best means to protect themselves, a central role for the Commission will be to distribute accurate and timely information to the public. Giving customers rights, information and a forum for dispute resolution comports with the principles that all customers should have a reasonable opportunity to benefit from a restructured industry and that the industry structure should be understandable and fair to the public. Commenters generally supported Commission oversight of power suppliers, but disagreed as to the appropriate level for a competitive industry. Customer groups advocated extensive oversight. Utilities and independent power producers believe unnecessary or restrictive regulation would limit their ability to craft diverse service offerings. We are mindful that in a fully matured competitive market where customers are experienced buyers, the need for regulations to protect the public is minimal. For a market in its infancy, however, the public interest calls for a heightened, even if temporary, level of protection. When the market and customers become more seasoned, the level may decrease. We agree with the utilities that customer protection standards governing suppliers' conduct in Maine must respect their need to create diverse offerings. Further, we believe that the standards in Maine ought not be significantly more burdensome than those in other states. The Commission would balance the needs of competitive suppliers with consumer protection. a. Registration and reporting Power suppliers would have to register to sell to customers in Maine, and file periodic reports after that. Registration and reporting would serve several purposes. First, it would provide the Commission with information on how many suppliers are selling into the Maine market. Second, it would help the Commission monitor the market's development. Third, it would allow the Commission to be a source of information for customers. Registration requirements would allow the Commission to confirm for customers that power suppliers have the financial and technical resources to carry out their business obligations and customer commitments. Reviewing suppliers' information before they provide service may enhance reliability and increase customers' confidence to participate in the market. The registration process would include an application with information specified by the Commission, verified and filed by a corporate officer. The Commission would likely streamline registration for suppliers registered in other states. As part of registration, the Commission would consider requiring a bond. Bonding could deter providers who do not have the financial ability or the intent to stand behind customer commitments. Also, bonding could be evidence of financial ability to withstand market disturbances or fluctuations or other events that may temporarily increase the cost of providing service. Customers should have some confidence in their supplier's financial ability to withstand such market fluctuations. Central Maine Power Company suggested, and we agree, that bonding might also cover the costs to ensure uninterrupted service if a provider suddenly ceases operations or otherwise abruptly stops service. In that event, the bond could pay costs incurred by the standard offer provider and the T&D utility to continue service. Ultimately, bonding could lower the cost of those services. b. Business practices The Commission would adopt minimum standards for suppliers' conduct. The standards would include the following: minimum notice provisions for changes in rates or other service terms, conditions for service terminations, requirements governing a change in service providers, minimum requirements for information and marketing materials. The standards would make clear the responsibilities of suppliers that want to sell to Maine customers. They would also give customers confidence that the Commission would hold every supplier to uniform obligations. To be effective, the Commission should have the authority to impose fines, issue injunctions and provide other appropriate remedies for violations of consumer protection standards. In a competitive market, the Commission would turn from comprehensive economic control to more narrowly tailored consumer protection enforcement. Thus, the Commission would have the authority to investigate and prosecute possible violations of Maine's Unfair Trade Practices Act, 5 M.R.S.A. SS 205-A-214, involving the retail practices of power suppliers. The Attorney General should retain authority to sue under those statutes in court, and could assist the Commission to investigate violations of the Act. The Attorney General should have responsibility to enforce the Act for power suppliers in the wholesale market. c. Filing requirements The Commission would require power suppliers with a service generally available to the public, or a significant segment of the public, to file their rates, terms and conditions. The Commission would review the filings only to ensure that all terms and conditions comport with business practice standards established by the Commission. The filings would be part of the information resources available to the Commission to help customers or to investigate and solve customers' disputes with power suppliers. The Commission would not require suppliers to file service contracts with individual customers. d. Standard billing Whether competition benefits customers depends in large part upon their ability to make informed choices. That, in turn, depends upon the availability of accurate, clear and timely information. Therefore, the Commission would consider adopting a standard bill format for power service. A standard bill format could perform the same function for consumers as do nutrition content labels on food products: it would help the consumer understand options, allow easier comparison of different offers, and reduce the likelihood of deceptive marketing. In developing a standard bill format, the Commission would consider similar requirements in other New England states and may encourage a consistent regional bill format. That approach could reduce the administrative costs of compliance for suppliers throughout the region, including Maine. e. Dispute resolution The Commission would resolve certain customer complaints against, or disputes with, power suppliers. The Commission's authority would be similar to that it currently exercises for public utilities, modified to reflect the competitive market. Customers should have one forum to help them resolve disputes with T&D utilities and power providers. 2. Credit, Collection, and Disconnection Retail competition will not relieve the consumer of the obligation to pay for services. Nor will retail competition create the possibility that customers will be disconnected except as provided by Commission rule. The Commission would continue to govern the credit, collection, and disconnection practices for the T&D utilities much as it does currently for public utilities. /40 As discussed above, the Commission would also create credit, collection and disconnection standards for standard offer service providers. The Commission would not authorize the T&D utilities to disconnect customers for nonpayment of charges by, or other disputes with, power suppliers. T&D utilities and power suppliers would be separate services provided by different companies. If a customer fails to pay a power supplier, the T&D utility would not be allowed to disconnect the customer from its system. Power suppliers should face the same risk and employ the same methods of debt collection as other competitive businesses. Power suppliers would not be obligated to continue to provide power to nonpaying customers. If the customer cannot find another supplier, the customer would default to the standard offer service. T&D utilities would have the authority, pursuant to Commission rules, to disconnect customers who do not pay for T&D or standard offer services. Disconnection avoids the accumulation of uncollected debt that ultimately increases the costs of T&D and standard offer service. 3. Low Income Assistance Program The needs of Maine's low income citizens are independent of the structure of regulation; for that reason, retail competition should not itself reduce the availability of low income assistance. Currently, Central Maine Power Company, Bangor Hydro-Electric Company and Maine Public Service Company administer low income assistance programs paid for by customers through rates. The percent of total rates that fund low income assistance is small, about half of 1 percent of total revenues, or less than $7 million per year. The Commission strongly recommends that the Legislature fund low income assistance programs through general taxes or a tax or surcharge on all energy services. Most commenters supported funding low income assistance through the tax system. The Legislature should fund low income programs through the tax system for several reasons. First, the tax system is a more equitable means of collecting funds than electricity use because general taxes are based on ability to pay rather than electricity consumption. Second, government agencies created to provide social services may administer low income assistance programs more effectively than T&D utilities, resulting in greater benefits from the same amount of dollars. Third, funding low income assistance through electric rates raises electric rates relative to other energy alternatives, causing an uneven competitive environment among different energy sources. A tax or all-energy-source funded program would correct that imbalance. A system funded by general revenues would also more effectively balance income disparities among service territories. The division by service territories of low income programs may disproportionately burden customers in economically depressed areas because low income assistance is needed most in areas where residents are least able to support it. Because of the disparity between need and revenues, it could be simpler and less controversial to deliver statewide assistance under a general revenue system. The Commission, together with the State Planning Office, would develop a recommendation and proposed legislation for funding assistance to low income consumers of electricity through the general fund or through a tax on all energy sources in the State. This proposal would be provided to the Legislature by January 1, 1998. The Industrial Energy Consumer Group (IECG) indicated concern about funding low income assistance through the general fund. It argued that it would subject vulnerable citizens to the risk that the Legislature would not continue to support low income assistance. The IECG believes funding low income assistance through rates is not as regressive as other mechanisms, such as property taxes, because electricity consumption tends to vary with income. The IECG also doubted that the small amount of low income support in rates would distort the market. We concur that low income citizens ought not be harmed by restructuring. That view is reflected in the principle that restructuring should not diminish low income assistance or other customer protections. During the transition to a competitive market, however, it is appropriate to reexamine subsidies and evaluate whether they are recovered by the most equitable and efficient means. In the event the Legislature elects not to fund low income assistance through the general fund or through a tax designated for this purpose, it could preserve the Commission's authority to fund low income programs through electric rates. Then, the Commission would fund programs in an amount comparable to that in rates in 1999. The Commission would also investigate whether COUs should provide low income programs and whether there are better means to distributing funds. 4. Customer Education and Information Ratepayers must become effective consumers for choice to be meaningful. To that end, commenters supported public education programs to ensure Maine citizens understand retail competition, how choice would affect them, and what they need to know to participate in the market. The Commission would immediately begin public education, including, but not limited to, holding public forums, publishing and distributing information bulletins, and developing an information data base accessible to users of the Internet. The data consumers might find useful are information from suppliers' registration applications, terms and conditions of service filings, and power portfolio disclosure statements. Beginning retail competition in 2000 would enable the Commission to observe public education efforts in other New England states and mirror those that appear most effective. The Office of the Public Advocate proposed that separating or "unbundling" power charges from the rest of customers' utility bills before 2000 would educate customers about retail competition. According to the OPA, giving customers an opportunity to see their electricity bills divided by services before retail competition would allow them to understand the separation of costs between power and transmission and distribution services. We agree. Accordingly, beginning in January 1999, all utilities would separately identify charges for generation. C. Further Proceedings In mid-1998, the Commission would begin one or more proceedings to determine what requirements should be imposed on companies selling electric power to retail customers in Maine. The issues to be addressed in these proceedings, which would be concluded by mid-1999, would likely include what registration requirements are appropriate; what jurisdiction the Commission should have over disputes between power sellers and their customers; what penalties should the Commission impose for violations of Commission rules; and what disclosures should power sellers make to their customers concerning the characteristics (e.g., fuel mix) of their production facilities. Other issues may be examined, including performance bonding; notice requirements for rate changes, other terms, and termination; and standard billing. The Commission would also determine what credit, collection and disconnection practices would be appropriate for T&D utilities. During 1997, the Commission would begin to review Chapters 81 and 86 of its rules, dealing with its disconnection and deposit regulations for residential and nonresidential customers respectively, and would complete new rules appropriate for a restructured electricity market by the end of 1998. Issues in this proceeding would include the implications of a T&D utility providing billing service for power providers, and whether existing rules concerning credit and collection continue to be appropriate. During 1997, the Commission, together with the State Planning Office, would prepare a recommendation, including proposed legislation, for funding assistance to low income consumers of electricity through the general fund or through a tax on all energy sources ("all fuels") in Maine. If the Legislature does not fund low income assistance through tax revenues, the Commission would investigate whether ratepayer-funded low income programs should exist in all service territories, and whether the means by which utilities distribute funds should be amended. The Commission would establish a comprehensive customer education and outreach program beginning in 1997. The Commission would intensify its customer education efforts in 1999, as the January 2000 implementation date approaches, drawing on the experience in other states with electric restructuring. During January 1998, each electric utility would file a bill unbundling proposal for Commission review. The primary issue likely to be resolved is the "price" of power (i.e., energy and capacity) as distinct from other services. The Commission would complete its review by July 1998, so that utilities would have approximately six months to complete any needed computer system and procedure modifications. Utilities' bills would be unbundled beginning January 1999. VI. ENERGY POLICY AND THE ENVIRONMENT A. Recommendation All companies selling electric power to retail customers in Maine should include a specified minimum amount of renewable energy in their generation portfolio. Retail providers could fulfill this requirement with credits that they could buy and sell. The Commission would consider the market's ability to develop and sell power from renewable resources, and would establish the renewable portfolio standard. The Commission would require every retail power seller to report the mix of fuels used in its generation. The Commission would publish this information quarterly. Ratepayers would continue to fund cost effective energy efficiency programs through revenue collected through the rates of transmission and distribution (T&D) utilities. The Commission would establish funding levels, comparable to the levels in 1999 before the beginning of retail competition, and regularly reevaluate the need and level. The T&D utility, with Commission oversight, would select the energy efficiency service providers through periodic competitive bidding. When retail competition begins, the Commission would cease to review and certify the construction of generating facilities in Maine and would no longer oversee plans and planning processes intended to meet the State's future electric needs. The Commission supports and will continue to work with other states and appropriate agencies for air emission standards that minimize differences between old and new source plants. Finally, the Legislature should consider directing one or more state agencies to review the environmental impacts from electric restructuring and its implication for Maine's energy policy. B. Discussion 1. Energy Policy and Electricity The Maine Energy Policy Act (MEPA), the Small Power Production Act (SPPA), and the Electric Rate Reform Act (ERRA) embody Maine's electricity-related energy policy. These statutes promote the use of indigenous and renewable resources, encourage energy efficiency and conservation, and balance short- and long-term costs and benefits in meeting Maine's electricity needs. The Commission has carried out these policies through regulatory orders. For example, the Commission has pre-approved the utilities' power plant construction and certain types of power purchases, and has made decisions about power supply and demand-side resource planning and acquisition. The Commission's ability to carry out energy policy has largely depended on the fact that it regulated comprehensively the provision of electricity. Restructuring would substantially limit this ability. Beginning in January 2000, customers would choose among power suppliers; the Commission would not regulate these companies as public utilities. /41 Thus, the Commission's oversight of electricity-related decisions would change in both form and degree. Supplier and consumer choice would replace Commission decisions over what resources will meet electricity needs, and whether, when and where suppliers build new plants. The effect of restructuring on energy policy is significant: decisions about the production and use of electricity directly impact the environment and the economy. A fundamental restructuring principle is that it should not diminish the quality of the environment, compromise energy efficiency, or jeopardize energy security. Relying abruptly and only on the market to make electricity supply choices could conflict with that principle. Competitive markets may place more value on short-term rather than long-term cost savings. And it is uncertain how the market would value other state policy objectives. This could lead, absent some intervention, to a power supply that is, in the long run, less efficient and more costly. Energy resource decisions, thus, should not initially be completely relinquished to the market. Although a competitive power market could benefit customers by lowering prices and increasing options, its effect on the environment is uncertain. The Commission would therefore (1) ensure the use and development of generation using renewable resources; (2) require ratepayers to fund cost-effective energy efficiency; and (3) ensure the availability of accurate and timely information so customers can choose power providers based on fuel mix. Commenters generally supported Maine's energy policy. The Office of the Public Advocate (OPA), the Industrial Energy Consumer Group (IECG), Conservation Law Foundation (CLF), American Association of Retired Persons (AARP), Coalition for Sensible Energy (CSE), Maine's independent power producers (IPPs) and others supported preserving energy efficiency and renewable resources. The Paradigm concurred. Residential and small business consumers in Maine appeared to agree. In a recent Commission survey, residents and small businesses expressed concerns about the environment. In New Hampshire's retail competition pilot, companies have used the fact that their power is environmentally benign to promote sales. The utilities, by contrast, suggested the market alone should decide energy resource development and use. In their view, government involvement in the market to further energy policy goal is unnecessary and undesirable. We disagree. The market may bring price and choice benefits to customers, but its ability to yield a resource mix that balances other state objectives is unclear. Maine should ensure the use of renewables and conservation through modest market-based and market-compatible portfolio and demand-side management (DSM) requirements. When and if the market delivers a resource mix consistent with energy policy and environmental goals, the Commission would cease to place requirements on market participants. The utilities also argued that placing requirements on electricity and not on other fuel sources disadvantages electricity providers. They recommended that any requirement on electricity providers should apply to all energy sources. The Commission agrees that public policy should, to the extent possible, avoid burdening one sector of the market with requirements not imposed on competing sectors. The Commission does not agree, however, that the solution to any current imbalance is to abandon all attempts to integrate energy policy with the regulation of electricity markets. The utilities argued that Maine cease to regulate electricity supply and demand choices when retail competition begins. We disagree, at least in the early years. Restructuring provides a vehicle to reexamine electricity-related energy policies; however, it does not itself require or justify their immediate elimination. 2. Renewable Resources in Electric Power Generation a. Perspective Nature replenishes renewable energy resources. Several renewable resources can generate electricity, including biomass or wood, water, sunlight, and wind. Renewable-fueled generating plants often have high capital costs, low or zero fuel costs, intermittent output and low environmental impacts. Maine's generation mix has a substantial renewable component. In 1995, hydro-, wood-, and municipal solid waste (MSW)-generated power provided about 47% of the State's electricity need. In the same year, hydro, wood, and MSW provided about 10% of New England Power Pool's (NEPOOL) need. /42 Nationally, renewable plants comprise about 12% of electric generating capacity. Federal and state government has encouraged, in a variety of ways, generation of electricity with renewable resources. One method used in Maine and elsewhere has been to require utilities to incorporate renewable resources in their long-term supply planning. Once the Commission no longer regulates generation, however, this tool will not be available. The market may, at least initially, disfavor generation using renewable resources, in part because such facilities tend to have high start-up costs. To encourage the continued development of renewable resource generation during at least the initial period of retail competition, the Commission would require sellers to comply with a renewable portfolio standard and disclose their fuel mix to customers. b. Renewable portfolio standard All companies selling electric power in Maine should meet part of their customers' needs with renewable power. Companies could meet this renewable portfolio standard in several ways. They could generate renewable power. They could buy for resale the output of a renewable plant. Or, they could obtain renewable credits from companies that have renewable energy in excess of their portfolio requirement. /43 Companies with entitlements to renewable generation could compete to provide credits, and all power suppliers could try to minimize the cost of meeting the standard. If renewable generation becomes competitive with fossil-fuel generation, the value and the cost of the credits would decrease. Ultimately, the requirement could be eliminated as the cost of providing power using renewable resources approaches the cost of other production methods. The Commission would adopt the renewable supply requirement before January 2000. /44 In establishing the requirement, the Commission would consider renewable provisions in other New England states, /45 evaluate whether the portfolio requirement remains the best method for Maine, and identify the effect on rates and the economy. After 2000, the Commission would reevaluate periodically the requirement and its level. The renewable portfolio requirement and the credit trading will ensure the use and development of renewable generation with a flexible, market-based approach. The Commission could tailor the requirement to policy objectives, such as targeting a specific form of generation. By allowing the market, instead of regulators, to decide what renewable generation options thrive, the portfolio requirement satisfies the principle that restructuring should not diminish environmental quality and the principle that where viable markets exist, market mechanisms should be preferred over regulation. Many commenters agreed with encouraging the development and use of power generated by renewable resources and the renewable portfolio requirement. These parties include the OPA, Maine's IPPs, and the CSE. The utilities objected to the renewable portfolio requirement. They argued that the market ought to decide what resources meet consumers' electricity needs. They also emphasized that the same requirements ought to apply to electricity and other end-use fuels. As we have said, however, we believe the competitive market is unlikely, at least initially, to act in sufficient conformity to Maine's energy policy. The Maine Municipal Utilities Group (MMUG) noted that suppliers could resist disclosing their resource mix or conforming to standards. As a result, they could be reluctant to enter Maine's market. However, other states are likely to have renewable provisions; /46 thus, Maine would be no less attractive than other states. Moreover, before placing requirements on companies selling power in Maine, the Commission would ensure that those requirements do not deter competitors from the Maine market. CLF supported provisions to ensure environmental quality and renewable resources. CLF, however, asserted that the portfolio approach could be burdensome and complex and could impede the development of renewable technologies. CLF also suggested that potential litigation over Commerce Clause questions could delay execution of the portfolio requirement. /47 As an alternative, CLF proposed a wires charge. We believe a wires charge is inferior to the portfolio requirement. A wires charge would require more regulatory oversight than the portfolio requirement, which counters the principle that where viable markets exist, market mechanisms should be preferred over regulation. Specifically, as the cost difference between renewable and other forms of power generation change, the value and cost of meeting the minimum renewable portfolio standard would self-adjust, and not require regulatory intervention. Regulators would have to adjust the wires charge to reflect a changed market. For the portfolio requirement, regulatory action would be limited to adopting levels, reporting requirements and enforcing compliance. CLF also argued that the portfolio requirement would be complex and therefore a burden. It is instructive that a similar system under the Federal Clean Air Act for SO2 allowance trading works reasonably well. c. Resource mix disclosure Customers should be able to choose electric power providers based on what resources each provider uses to produce power. Customers may want to buy from suppliers based on production characteristics. For example, some customers may want to purchase energy generated with environmentally benign resources; some may want to exclude nuclear power, or power produced using coal or hydro. The Commission's survey on electricity issues suggests that more than 80% of Maine's residential customers and 75% of small businesses want to know how their electricity is generated, and a majority places a premium on clean power. Surveys in other states, such as Texas, reveal similar customer preferences. Sellers competing in New Hampshire's retail pilot have used environmental attributes as a marketing strategy. To provide customers with information to make these choices, power suppliers should disclose their generation resource mix. The Commission would publish that information quarterly. The independent system operator (ISO) could oversee compliance. The ISO would have much information about production available in the normal course of business. Commenters unanimously agreed that customers should have access to accurate information on the resource mix of potential suppliers. Except for CLF, CMP and MMUG, commenters supported a fuel disclosure requirement. CLF and CMP identified potential practical problems with the disclosure requirement and questioned the need. They asserted it could be difficult or impossible for energy suppliers to identify and report this information in a way that assists customers. We believe the benefits of disclosure outweigh the costs. Suppliers ought to know their resource mix; if they sell spot market power, they could provide system average mix data. If the market develops other means to provide credible data, the Commission would eliminate this requirement. Some commenters suggested suppliers disclose other information, such as data about emissions and the geographical location of their power plants. We disagree. Such further disclosures would not provide sufficient additional useful information to justify the increased complexity and cost. We expect, however, that additional sources of information would become available in the marketplace. 3. Efficient Use of Electricity Conservation and the efficient use of electricity can deliver value to customers at lower cost and with fewer adverse environmental impacts than producing more power. Federal and state policy has encouraged conservation and the efficient use of electricity. Utility regulators have often carried out these policies. In Maine, ratepayer-funded DSM has saved over six billion kilowatt-hours. The Commission required utilities to support DSM because it believed that customers may view the "payback" for DSM investments as too long; utilities may resist DSM because they may see their profits fall when customers save, rather than use, electricity. The Commission would, at least initially, continue to ensure that consumers fund these programs through T&D rates. The Commission would set initial funding at a level comparable to that in 1999, and regularly review the need for funds, and their level. The T&D utilities, with Commission oversight, would solicit bids periodically to provide cost-effective efficiency services, select the vendor(s), and administer the contracts. T&D utilities could bid to provide energy services, even in their own service area. Continuing to fund an appropriate level of DSM is consistent with the principles that restructuring should not diminish environmental quality, compromise energy efficiency, or jeopardize energy security. It is at best a possibility, and by no means a certainty, that markets would immediately yield an abundance of efficiency-related energy services. The OPA, CLF, CSE and the IPPs supported requiring customers to pay for efficiency programs through the T&D utilities' rates, and endorsed bidding as a way to minimize the cost. Utilities and Madison Paper Industries do not believe that continued DSM funding through regulated rates is necessary. They believe the market would deliver appropriate energy efficiency services. The utilities further argued that imposing requirements and costs on electricity and not other fuels distorts markets and unfairly disadvantages providers of electricity. The Commission agrees that differences in the burdens placed on competitors in the energy market should be eliminated to the extent possible. Nevertheless, we are unwilling to entirely abandon regulatory requirements for conservation and the efficient use of electricity without clear legislative direction. CLF and Ed Holt & Associates opined that setting initial funding at 1999 level would be inadequate. Holt also asserted that linking funding levels to a future year would give utilities an opportunity to reduce DSM spending. Holt offered no basis for the conclusion that regulatory oversight through 1999 would be inadequate to set DSM spending levels at an appropriate level; we believe that conclusion is unwarranted. 4. Long Term Resource Planning and Certification of Need The Commission has executed state energy policy by regulating the utilities' power purchases and resource planning. Through its oversight, the Commission has sought to minimize electricity costs over the long term, encourage the use of indigenous renewable resources and energy efficiency, and ensure that generation-related decisions were in the public interest. Beginning in the year 2000, the Commission would no longer review power plant construction and other power acquisition decisions. The move to competition, and the accompanying shift of risk to private investors, would largely replace, and improve upon, regulatory oversight. However, there may remain matters regarding the construction and siting of power plants that warrant continuing government oversight. The Legislature should consider whether the Department of Environmental Protection or a newly formed entity such as a siting council or energy office should oversee these issues. 5. Air Quality Impacts of Restructuring The Commission supports the application of emissions standards to minimize differences between old and new source generating plants. Because this matter extends beyond Maine's borders, the Commission could address it only through working with other states and Federal agencies. The Commission would not set up different standards for Maine generating facilities than are imposed on a regional or national basis. Older, less efficient, and more polluting coal and oil plants could have a competitive advantage. These plants tend to have lower total costs, but higher heat rates and higher emission rates than newer plants. Many older plants were grandfathered with respect to New Source Performance Standards of the Clean Air Act (CAA), because at the time Congress enacted the CAA these plants were expected to retire soon. As competition develops, these plants may find new markets for their power, further contributing to delays in their being displaced by newer plants. This creates two problems. First, it could exacerbate air quality problems. Second, the plants would have an unfair competitive advantage because they are grandfathered, and that could discourage the emergence of additional power suppliers. Thus, benefits of competition would lag, and air pollution would increase. Maine and the rest of the northeast region would be particularly disadvantaged. The low-cost coal plants in the midwest are among those most likely to have increased demand for their power. If they expand their production, levels of NOX, SO2, and CO2 would increase, potentially degrading Maine's air and water quality, increasing Maine's cost of complying with the CAA. That would occur whether or not the power from the midwestern plants is sold into the northeast market. All commenters agreed the presence of old and new source plants in the competitive market would create environmental and economic challenges for the northeast. Except for CLF and Maine's IPPs, parties agreed that regional or Federal solutions are necessary. They agreed that Maine ought not impose emission standards on its old source plants that are more stringent than standards required in other states. Maine's IPPs recommended applying emission standards to those who sell power to retail customers. This approach, however, would be similar to, and perhaps duplicative of, a renewal portfolio standard. Therefore, imposing such emission standards could discourage companies from entering the Maine market. CLF proposed Maine require the older, fossil-fueled utility-owned plants within its borders to conform to emission standards comparable to those required for new plants, regardless of what other states do. They asserted this would allow Maine to argue more effectively for similar requirements in states up wind. We are not persuaded, however, that Maine acting alone is likely to have any significant effect on the operation of power plants in the midwest. On the other hand, such a requirement would further disadvantage Maine power producers subject to the standards. We prefer, therefore, to continue to seek regional and national solutions. C. Further Proceedings The Commission would begin a proceeding, in early 1998, to determine the appropriate level of renewable energy generation to be included in the production mix of all power sellers in Maine, and to establish the guidelines necessary to implement this renewable portfolio requirement. The proceeding would be concluded in early 1999. The issues to be resolved in this proceeding would include the level of renewables to be required; the extent to which any Maine requirement should vary significantly from similar requirements (if any) elsewhere in New England; how renewable "credits" would be calculated and traded; what price impacts various renewable requirement levels would have, and the effect of those price impacts on consumers; and whether any particular level of renewable requirement would produce measurable benefits for Maine such as reducing the cost of complying with Federal Clean Air Act standards. Beginning in mid-1998, the Commission would review the framework and substance of the demand-side management programs to be administered by the T&D utilities in the new competitive environment. These reviews would be concluded by mid-1999. Issues in these proceedings would include how costs and kWh savings would be calculated; whether any costs should be deferred, and if so over what period; whether there should be a limit on the price impact of DSM programs; and how any costs should be included in rates. VII. STRANDED COST A. Recommendation Electric utilities would have a reasonable opportunity to recover legitimate, verifiable, and unmitigatable costs stranded as a result of retail access. A reasonable opportunity is not a guarantee of cost recovery. Utilities should have only the opportunity for cost recovery comparable to that under current regulation. The Commission would not allow utilities to recover costs for which obligations were incurred after March 1995, unless the associated obligations were specifically mandated by the Commission or other public authority. The Commission would require utilities to mitigate those costs aggressively, and would require utilities to obtain the highest possible value from their generation assets and contracts. The Commission would not reconcile stranded costs after-the-fact, but would review them periodically and, if warranted, adjust them on a going forward basis. Stranded costs would be collected from customers through the regulated rates of the transmission and distribution (T&D) utilities. The Commission would establish the rate design for stranded cost recovery before the beginning of retail competition. The Commission would not establish exit fees or similar charges as a part of industry restructuring. B. Discussion 1. Nature of Stranded Costs Certain costs and obligations incurred by utilities to fulfill their legal obligation to provide electricity may become unrecoverable, or stranded, when retail competition begins. These costs fall into three general categories: (1) above-market costs associated with utility-owned generation plants; (2) above-market costs associated with generation-related contracts, most notably contracts with qualifying facilities (QFs); and (3) regulatory assets related to generation such as those associated with canceled plants and QF contract buyouts. /48 For the most part, current utility rates include these costs. Traditional regulation provides utilities a reasonable opportunity to recover their costs, if prudently incurred, through the ratemaking process. In a retail market opened to competition, utilities may be able to recover only market value of their generation assets or power contracts; any remaining costs /49 associated with these assets in excess of the market value may be "stranded." A utility asset or contract could have a market value below or above the utility's remaining cost. The total stranded cost is the sum of the differences between remaining cost and market value, both positive and negative, of utility assets and contracts. Because regulatory assets represent only ratepayer obligations, they do not have a market value. The total of a utility's regulatory assets must therefore be added to other stranded costs. Not all costs that become unrecoverable are "stranded" by retail competition. Customers may reduce or even eliminate electricity usage by self-generating, fuel switching, production cutbacks, energy conservation, and bypassing the utility's system entirely. All these activities result in fewer revenues available to the utility to pay the fixed costs of operations. These customer options, however, exist under current regulation as much as they would after retail competition begins. /50 The Commission would continue to consider whether the cost-shifting that may result from these reductions in usage warrants regulatory intervention. 2. Utility Recovery of Stranded Costs a. Opportunity for recovery The Commission would allow utilities a reasonable opportunity to recover legitimate, verifiable and unmitigatable stranded costs that result from retail competition. The Commission would design the rates to recover stranded costs so that the opportunities, risks and uncertainties for cost recovery would be comparable to those under the existing regulatory system. Industry restructuring would provide no additional guarantees or enhanced certainty for stranded cost recovery. Most commenters supported or did not oppose this approach to stranded cost recovery. Historically, utilities have had a legal obligation to provide adequate and safe service at just and reasonable rates to all customers within their geographic service territories. These obligations prevented utilities from refusing to serve any customer, including those who might impose high costs on the system, and required utilities to have adequate generation capacity available to meet current and future demand. The obligation to provide service in return for the right to exclusive service territories is sometimes called the regulatory compact. The Maine Law Court has long recognized the underlying principle of this compact: The whole body of public utility law has been developed here and elsewhere upon the concept of regulated monopoly. Implicit in this concept is an acceptance of the principle that a public utility offers its facilities and services to the public without discrimination and that it is obligated to extend its service as needed within its service area unless the supervisory agency determines that it is not practicable or economically feasible to do so. A public utility yields to the sovereign with respect to approval of rates, methods of financing and other matters of policy which are ordinarily within the sole province of management in private business. In return for relinquishing the right to determine without let or hindrance whom it will serve, what it will charge, or how it will finance or invest, it is usually given relative freedom from competition in its service area on the part of public utilities similarly regulated and controlled. The monopoly thus afforded as among competing public utilities is in effect a quid pro quo for the obligation to render public service and to submit to regulation and control. Dickinson v. Maine Public Service Co., 223 A.2d 435, 438 (Me. 1966). Opening a utility's franchise area to retail competition would effectively break the existing regulatory compact. The central issue for stranded cost recovery is whether, after the franchise for power sales is opened, utilities who invested in power supply to fulfill their franchise obligations should be given, in the restructured market, a reasonable opportunity to recover those investments. The Commission believes that utilities should be given that opportunity. In essence, utilities should have the same opportunity to recover the costs in a restructured industry as they had when they incurred the obligations under an earlier regulatory framework. /51 Moreover, changing the rules for cost recovery after investments have been made to fulfill service obligations could impair government's credibility and deter long-term investment in Maine. The opportunity to recover costs after retail competition begins should be equivalent, not superior, to the opportunity under the current system. Costs incurred imprudently, or costs that are not mitigated aggressively, have no place in any stranded cost recovery charge. The Commission would permit stranded cost recovery only to the extent consistent with strictures of prudent utility management. One alternative to the recovery principles outlined above is to reduce the recovery by some specific portion, often described as "sharing" the burden among utility shareholders and customers. The Commission does not recommend that approach. Any portion selected could only be arbitrary and inevitably subject to a legal challenge that could delay the beginning of retail competition. It would also create substantial uncertainty in the electric and financial markets. If the Commission believed that curtailing the opportunity to recover prudently incurred costs were sound policy, and it does not, it could disallow recovery under current regulation without the travails of restructuring. b. Mitigation To minimize stranded costs, the Commission would require utilities to pursue all reasonable means to reduce uneconomic costs and to get the highest possible value for their generation assets and contracts. /52 The Commission would estimate a reasonable level of mitigation. Incentives might include price cap regulation, or sharing savings from cost reductions. One important opportunity to reduce stranded costs is in the sale of generation assets. The Commission would rely on the market to ensure that ratepayers receive the maximum value for those assets. As the IECG and others observed, the utility should choose the method for any sale for its ability to obtain the highest possible price. In many cases, using an auction might produce the best result. In no case would the Commission rely entirely on a value determined administratively by calculating the net present value of the cash flow from the current use of a facility. In the case of a plant currently using oil as fuel, for example, the market might identify a higher value for the same plant if that plant were converted to gas. An administrative determination (or even relying on the sale price offered by an affiliate) in that case would be likely to understate the value significantly. In addition, the Commission would continue to require that the T&D utility, as holder of the QF contracts, explore all reasonable and lawful opportunities to reduce the cost to ratepayers of those contracts. The Office of the Public Advocate (OPA) proposed a specific incentive to mitigate the costs associated with QF contracts. The allowance for stranded costs would assume that utilities can achieve a 10% saving in QF contract costs. Utility shareholders would retain savings in excess of 10%, but would not recover more than 90% of the original contract costs. We decline now to adopt the OPA's proposal. The specific incentives for cost mitigation should be addressed comprehensively in a proceeding. /53 c. Cost recovery limitation In an order issued in March, 1995, the Commission put utilities on notice that they would bear the primary market risks of costs incurred in the future. Order Commencing Rulemaking, Re: Recovery of Stranded Cost Rulemaking, Docket No. 95-055 at 10 (Feb. 27, 1995); Order Terminating Rulemaking, Docket No. 95-055 at 3-4 (April 8, 1995). To the extent generation-related costs incurred after March 1995 become uneconomic due to retail competition, the Commission would not include any recovery for those costs in the stranded cost recovery charge. This limitation does not apply to regulatory assets created after March 1995, such as amortizations of QF buyout costs, and costs deferred pursuant to existing rate plans or for conservation. These regulatory assets result from utility efforts to reduce costs or to fulfill obligations imposed by the State. Therefore, utilities should have an opportunity to recover these costs. /54 Similarly, the limitation does not apply to new obligations over which utilities have no discretion. For example, Maine Public Service Company (MPS) may have to extend its contract with Wheelabrator-Sherman. If so, recovery of costs stranded as a result of the contract extension would not be subject to the March 1995 cut-off. Bangor Hydro-Electric Company (BHE) and Eastern Maine Electric Cooperative (EMEC) opposed any recovery limitation because they still have an obligation to obtain generation resources to serve ratepayer demands. We disagree. Beginning in March 1995, utilities in Maine could no longer claim an expectation of an invulnerable franchise, and traditional opportunities for cost recovery, extending indefinitely into the future. Prudent management would, at that point, understand that potentially uneconomic burdens would be at their shareowners' risk. /55 d. Constitutional authority Central Maine Power Company (CMP) argued that, as a matter of law, states must allow utilities to recover any and all stranded costs. It rests the argument on restrictions against governmental takings of property in the United States and Maine Constitutions. We do not agree that the Constitution so rigidly constrains the Commission's discretion. A commission may decline to allow the recovery of costs, even prudently incurred costs, without exceeding constitutional limits unless the result is confiscation of the utility's property, taken as a whole. Such confiscation will be found only where the utility's financial integrity is seriously jeopardized. Duquesne Light Co. v. Barasch, 448 U.S. 299 (1989). Indeed, regulatory decisions that injure the utility's financial integrity may be lawful. For example, a state can continue to apply longstanding ratemaking principles even if it results in substantial financial harm or bankruptcy. Appeal of Public Service of New Hampshire, 547 A.2d 269 (N.H. 1988). If management imprudence compromises a utility's financial integrity, regulators are not constitutionally compelled to rescue its shareowners. The Commission's conclusion that utilities should be allowed a reasonable opportunity to recover costs stranded by retail competition does not, therefore, rest solely upon constitutional principles. It rests also on the Commission's belief that government and citizens are best served when decisions are made in a fair and consistent manner. 3. Determination of Stranded Cost Charges a. Process The Commission would estimate stranded costs for each electric utility. It would then use the estimates to develop the stranded cost rates to be charged by each T&D utility when retail competition begins. To reduce the risk of establishing rates that are grossly too high or too low, the Commission would, at a minimum, reexamine the stranded cost rates and correct for substantial inaccuracies in 2003 and again in 2006. To determine the market value of generation-related assets and contracts, the Commission would rely to the greatest extent possible on market information. The Commission would consider factors including, but not limited to: market valuations that become known as plants and the rights to power from QF contract are sold, current and likely future regional market prices for power, and stranded cost determinations in other New England states. The National Independent Energy Producers suggested that a competitive sale should determine an asset's market value. The Paradigm supported an auction approach. We agree that, to the extent possible, it is best to use market techniques to identify value. We depart only to the extent that we believe flexibility, instead of limits, on which market techniques T&D utilities use is likely to maximize the value of assets. While CMP and BHE would be required to divest their generation assets no later than January 2006, utilities could propose to divest earlier. In the event a utility divests all or a significant amount of its assets prior to 2006, the Commission would review and, if warranted, modify that utility's stranded cost rates. When the utility completes the divestiture or sale, the Commission would finally decide the stranded costs associated with the asset. When the T&D utility no longer owns a power-producing asset, fluctuations in the value of that asset cannot be readily reflected in rates charged by the T&D utility. If the value of the asset increases, which would in theory reduce stranded costs, there is little chance of persuading the new owner to raise the price it already paid for the asset. If the value decreases, neither the T&D utility nor its ratepayers should be forced to help the unlucky buyer. Any "final" stranded cost determination for divested assets creates a risk of inaccurate stranded cost charges if market values change. This risk would be reduced, to some extent, by the Commission's reexamining periodically the stranded cost associated with QF contracts and Maine Yankee. Because QF contracts and Maine Yankee ownership would remain with the T&D utilities, the Commission could review and modify associated stranded cost estimates at any time, including after 2006, until each of the contracts terminates and Maine Yankee ceases to operate. This should help to ensure stranded cost charges remain reasonable. Moreover, the total amount of stranded costs will decrease with the passage of time; mis-estimation of market value in 2005 or 2010 will necessarily have a smaller impact than mis-estimation in 1998 or 2000. The Commission would adjust stranded cost charges on a prospective basis and not reconcile or true-up amounts to reflect past "actual" values. The purpose of periodic reviews is only to correct substantial estimation inaccuracies, not to guarantee dollar-for-dollar recovery or to reflect minor fluctuations in market value. BHE and MPS supported a dollar-for-dollar reconciliation of stranded costs to account for any inaccuracy in estimates. However, such an approach could weaken incentives to mitigate stranded costs. With reconciliation, utilities would be financially indifferent with respect to mitigation. The regulatory lag created by a system of forward-looking rate adjustments has the additional benefit of giving T&D utilities a stake in the success of the competitive power market. A lower market price for power should stimulate T&D sales and, to the extent the stranded cost charge is based on usage, increase the T&D companies' revenues and profits. This stake would be lost, however, if past collections were somehow "reconciled." b. Methodology For utility-owned power plants, the Commission would estimate stranded costs by calculating the difference between net plant investment and the value of expected future profits. For purchased power contracts, it would calculate the difference between future contract payments and the market value of the power. /56 The stranded cost for each asset or contract could be positive or negative depending on whether the market value is less or greater than the remaining cost. Another approach to calculating stranded costs, sometimes called the "revenues lost" approach, simply subtracts the costs the utility saved by the departure of a customer lost to a competitor from the revenues lost. /57 This methodology may be useful in certain circumstances, such as where an entire municipality leaves the utility's system. Conceptually, however, there is a closer match between uneconomic costs of generation and the introduction of competition in the retail generation market. For that reason, the Commission prefers to focus on generation-related assets. The Commission's range of stranded cost estimates together with a more detailed discussion of methods is contained in Appendix 5. 4. Recovery Mechanisms and Rate Design The stranded cost liability associated with retail competition would lie with the T&D utilities and be recovered in regulated rates. Stranded costs result from obligations incurred by regulated utilities, and it is appropriate that they be recovered from the ratepayers of regulated entities. If stranded costs were recovered by unregulated power providers, those companies would have advantages and burdens neither available to nor imposed upon competitors. For example, if a generation company receives stranded cost payments, it would have an identifiable revenue stream that could provide cash flow advantages. The Commission would design rates to recover stranded costs for each utility prior to retail competition. All customers using the services of the T&D utility would pay stranded cost charges. Because customers that buy power in a competitive market could be expected to buy the same amount of power they did from the utility before retail competition, it may be appropriate to impose a usage-sensitive rate for stranded costs. The Paradigm favored this approach. However, stranded costs rates should also be designed to satisfy other goals, such as economic efficiency, equity, rate stability, and should encourage choice among competitors based on their economic costs. Accordingly, the Commission would explore rate designs that are less usage sensitive, such as per maximum kW charges or flat access charges. To establish rate designs, the Commission would consider the amount to be recovered, the period over which recovery will occur, and rate designs adopted in other jurisdictions. CMP proposed that the Commission allow CMP to impose limits on customers' opportunity to avoid paying their fair share of stranded costs. Non-utility commenters generally opposed exit fees. The Commission does not believe exit fees are either practical or appropriate. Proponents of exit fees claimed that the demand for electricity of particular customers has caused utilities to incur certain costs on their behalf, and that these same customers should pay these costs. This claim is doubtful. Power purchases are rarely customer-specific. Moreover, if the idea is to match cost-recovery with cost-causation, some daunting questions emerge. Should customers have to be on the system any particular length of time before any exit fee would apply? Should customers who entered the system last year be required to pay an exit fee if they leave the system next year? If so, should the amount of the exit fee be the same as for a customer that has been on the system for 30 years? Should exit fees apply to customers that enter the system in the future? None of these questions has a felicitous answer. Exit fees could also adversely affect Maine's business climate. If exit fees applied to businesses who were utility customers on a specific date, only newer businesses could switch power suppliers without paying an exit fee. If exit fees applied to new customers, it could dissuade businesses from entering the State. What business would move to Maine if its flexibility to move in the future were so constrained? Exit fees are an extraordinary remedy. That approach might be justified where its absence would result in either extreme financial stress on the utility or unacceptable rate increases for utility ratepayers. /58 An exit fee or similar rate design should not be adopted without a substantial demonstration of ratepayer harm. C. Further Proceedings The Commission would establish initial estimates of stranded costs prior to 2000, using market information to the greatest extent possible. The Commission would also establish the rates that each T&D utility would be allowed to charge to recover the stranded costs subject to recovery. These proceedings are likely to be complex, both with respect to the proper calculation of stranded costs, and the rate design appropriate for their collection. Because an important component of the calculation of stranded costs is the market price for power, the Commission would conduct further proceedings after 2000 to update the stranded cost charges based on then current market conditions. In addition, there would be a link between this case and the bidding process for QF contracts, because the results of that process would have an effect on the level of stranded costs. Some of the issues to be determined in these proceedings are whether sufficient efforts have been undertaken to mitigate stranded costs; the estimation of the future market price for power; the proper level of stranded cost recovery for each customer class; and the specific rate design for the stranded cost recovery charge. Because the factors influencing the size of stranded costs are unique to each utility, the Commission would conduct separate proceedings for each investor- and consumer-owned utility. Under the Commission's Implementation Schedule, a nine-month proceeding for CMP would begin in late 1997, with the proceedings for BHE and MPS beginning in January 1998 and April 1998, respectively. The proceedings for the consumer-owned utilities would likely be less complex and would begin in April 1998. To ensure that rates reflect the most up-to-date information and analyses available, concurrent limited reviews may be needed between April and December 1999 for each of the utilities. VIII.REGIONAL ISSUES A. Recommendation Maine cannot resolve all issues that will determine whether retail competition will succeed. Some issues must be addressed on a regional level or before the Federal Energy Regulatory Commission (FERC). Regional issues include the reliability of the bulk power and transmission systems, and the fair and efficient operation of the power market. The Commission, together with the New England Conference of Public Utility Commissioners (NECPUC), the New England Governor's Conference (NEGC) and others, would continue to work to resolve these issues. Issues that affect Maine's ability to benefit from competition include governance reform of the New England Power Pool (NEPOOL) to allow fair and meaningful representation for all market participants; the existence of an Independent System Operator (ISO) for the transmission system that would be effectively independent and have no financial interest in any market participants; the creation and operation of a voluntary power exchange, either as an independent entity or as part of a reformed NEPOOL; and rules to ensure that providers meet the North American Electric Reliability Council (NERC) reliability standards. B. Discussion 1. Perspective FERC and state regulatory commissions regulate different aspects of electric transmission. FERC has authority over rates charged for interstate transmission and limited authority over reliability. /59 State commissions have authority over transmission facility siting within the state, and jurisdiction over retail rates. /60 This jurisdictional overlap creates challenges for restructuring, particularly in regions with tightly integrated, multi-state power systems. In New England, facilities owned by many different companies and located in six different states operate as a single system. NEPOOL coordinates and operates the system. Facility owners participate voluntarily in NEPOOL, and FERC oversees its governing agreements. Thus, a single state cannot mandate changes to the New England system necessary to accommodate competition. In the New England region, power is regularly bought and sold in a wholesale market. The rules of NEPOOL, for the most part, govern this market. NEPOOL, which comprises more than 100 utilities in the region, has major responsibilities for planning and operating the region's generation and transmission facilities to ensure load is served reliably and economically. NEPOOL is organized and operates according to an agreement of the member companies, and is under FERC jurisdiction. Historically, NEPOOL's membership has been limited to utilities, and the largest utility members dominate its control. State Commissions have two formal ways to influence NEPOOL: state regulation of the member companies within each state's jurisdiction and participation in FERC proceedings either individually or with other New England Commissions. The Commission can also communicate its views about regional issues to NEPOOL in less formal ways. The Commission would continue to pursue a variety of means to help bring satisfactory resolution of regional issues. Specifically, the Commission would continue to participate through informal and, if necessary, formal intervention at FERC, to reform NEPOOL, to form an ISO, and to develop a regional transmission group (RTG). As the restructuring proceeds in New England and elsewhere, the Commission would continue to be involved in regional issues to the extent consistent with Maine's interests. 2. Reliability Maintaining the reliability of the electric power system is critically important. Restructuring should not be allowed to result in degradation of the regional power system's reliability. The current industry standard for bulk power system reliability, set by the NERC, provides that there should be no more than one day in 10 years that load cannot be served because of inadequate transmission or generation resources. Traditionally, utilities in the region have cooperated to maintain system reliability. Utilities have shared information including expected load growth, system constraints, and construction plans. The vertical monopoly structure of the industry has aided this cooperation. In a competitive environment, companies may be less forthcoming with information. This could make maintaining sufficient reliability more difficult. The Commission would work to ensure that regional structures exist and have the authority to ensure system reliability. All competitors providing power to Maine customers would conform to appropriate regional and national reliability standards. Commenters supported measures to ensure reliability of the region's power system. The Paradigm included regional reliability requirements. /61 Central Maine Power Company (CMP) suggested reliability could be more easily maintained if bilateral contracts were purely financial instruments and had no impact on system operation. Further, CMP asked the Commission to specify reliability standards that competitive providers in Maine would have to meet. The Commission should not dictate particular reliability standards. CMP's concerns are best addressed through a reformed NEPOOL and an effective ISO, and through the requirement that all power providers who sell to Maine's consumers would have to conform to appropriate regional reliability standards. 3. Governance Issues in NEPOOL Reform An essential feature for any entity that controls or coordinates regional market operation is meaningful and fair representation of all market participants. The recently expanded NEPOOL membership indicated the intent to file documents with FERC that would reform NEPOOL to accommodate a more competitive and open generation market, and to allow non-utility interests a voice within NEPOOL regarding how the market operates. The Commission has participated in and monitored the progress of NEPOOL restructuring discussions and will continue to work toward a system that provides appropriate representation for all market participants. 4. The Independent System Operator The region's integrated bulk power and transmission systems require an operator to ensure the coordination of generation and load. In New England, the system operator oversees the generation and transmission resources of all companies within NEPOOL to ensure reliability and to minimize the costs of serving the aggregate pool load. Currently, the New England Power Exchange (NEPEX), an arm of NEPOOL, performs this function. To the extent system operation is linked directly to the financial interests of market participants, as it is now, the tasks may not be performed in a competitively neutral manner. Therefore, the Commission supports creating an ISO with no financial interest in the success or failure of any particular market participant, or group of participants. It would continue to work toward that end. Commenters generally supported the ISO concept, but differed about the degree and form of independence necessary. The Paradigm included provisions for an ISO that would have no financial relationship to energy providers. The Commission would continue to work toward the creation of a truly independent ISO. 5. Transmission Pricing and Access A healthy competitive market for generation depends on the availability of transmission services at non-discriminatory terms and prices. The FERC has made clear its requirements in this regard. There are ongoing efforts to establish the framework and rules for a RTG in New England to carry out FERC's mandates. The Commission has been and will continue to participate in these efforts and, if necessary, in related FERC proceedings. Because there are separately owned transmission systems over which power flows in New England, there are difficult issues regarding how the region's transmission services should be administered and priced. As a general matter, prices for transmission should recover the transmission provider's cost of service and encourage the efficient use and expansion of the regional bulk power system. Existing pricing systems that discriminate or artificially favor the purchase of power from one generation unit above another (e.g., Pool Transmission Facility (PTF) rates) /62 should be eliminated over time. The Commission would continue to work to ensure that the rules and prices governing transmission in the region are consistent with fair and efficient market competition, and do not unduly disadvantage sellers or buyers in Maine. Commenters generally agreed that transmission access and pricing must be open, fair, and efficient. The Paradigm reflected these same principles. Bangor Hydro-Electric Company (BHE) suggested the Commission not promote eliminating the PTF rate until a new method of pricing exists that ensures open access to regional transmission facilities at reasonable rates. According to BHE, eliminating PTF rates without reasonably priced open access transmission would limit competition and create opportunities for market power. The Commission expects the elimination of PTF-type rates would occur in the context of the RTG. Thus, the pool-wide rates and terms reflected in the RTG would replace PTF rates and, in principle, ensure fair and equal access to regional transmission. It may also be appropriate to phase-out PTF arrangements gradually to facilitate agreement on an RTG and minimize near-term disruptions for BHE and similarly situated utilities. 6. The Power Exchange Certain structures can help market operations and provide participants with information to make informed and economic choices. In the emerging electric power markets, a regional power exchange could perform these functions. The power exchange would be a spot market, allowing for market transactions in real time without the need for specific contracts between individual buyers and sellers. The exchange would receive and rank power supply bids, and determine and post market clearing prices. Participation in the exchange would be voluntary. Other power exchanges or similar mechanisms could evolve and coexist with or replace this exchange. The power exchange could be part of the same organization that provides the ISO services, though some have advanced theoretical arguments supporting a fully separate organization. Enron Capital and Trade Resources (Enron) asserted there is no reason to create a power exchange. According to Enron, open transmission access and unbundled rates, together with the interplay of buyers, sellers, and merchants would achieve an effective and efficient market. In addition, Enron argued that the creation of a power exchange could hamper the development of a forward market. However, if established, Enron argued the exchange must be independent of the ISO and cease to exist by a certain date. The Commission believes a power exchange is likely to perform an important role in the development of effective competition. If, as Enron asserted, the power exchange is unnecessary or uneconomic, buyers and sellers would use it little, or not at all. Thus, if Enron is correct, the market itself would eliminate the exchange. If it is voluntary, a power exchange should not hinder other transactions nor preclude the development of forward markets if such markets are efficient. 7. Horizontal Market Power Study There is a risk that some market participants may control a large enough share of the region's power supply to allow them to exert undue influence over market prices. In that event, the benefits of restructuring would not flow to consumers. To the extent possible, opportunities for market power should be minimized before retail competition. After-the-fact anti-trust enforcement would be expensive and likely ineffective, because the unlawful exercise of market power is difficult to detect and even more difficult to prove. The Commission recommends that the Legislature direct state agencies, including the Commission, to study regional power market and recommend steps to minimize market power opportunities before the date of retail access. C. Further Proceedings The Commission would continue its efforts at the regional level and, if needed, at FERC to resolve regional restructuring issues. The Commission does not currently anticipate proceedings before the Maine Commission to resolve the matters discussed in this section. End Notes / 1 Throughout this Report, we have used the terms "generation service" and "power" as synonyms. In this document, these terms refer to the provision of electric power as distinct from transmission and distribution services (i.e., the wires and other facilities needed to transport the power, and access to those facilities). "Generation providers" refer to generators, marketers, brokers, aggregators, or any other entity producing or selling electric power. / 2 The Maine Commission was the first to adopt comprehensive price cap regulation for electric utilities. The approach is common in the telephone utility industry. / 3 Cogeneration refers to the use of excess thermal energy, generally produced as a result of manufacturing processes, to generate electricity. Small power production relies on renewable resources such as hydro and biomass as the primary source of fuel. / 4 These filings are currently under review by FERC. / 5 Regional matters are discussed in Section VII, below. / 6 NEPOOL currently projects that the regional surplus of generating capacity will end in approximately 2000. As surpluses in generating capacity diminish, the price for electric power at the wholesale level is likely to increase. / 7 There may be components of distribution service (e.g., metering) that could be unbundled and provided by competitive markets. Our plan neither proposes nor precludes any such unbundling of distribution services in the future. / 8 As a matter of physics, electricity generated by or for a retail provider is not actually consumed by its retail customer. Instead, all generators in the region place electric power on the grid that is simultaneously consumed by all end use customers on the system. As a result, retail competition only allows for financial transactions involving the obligation of providers to place specified amounts of electric power on the regional system to meet the demands of their retail customers. / 9 This matter is discussed in section VIII, below. /10 Customers that do not choose a competitive generation provider would take service under the standard offer. This service is discussed in section IV, below. /11 To the extent a separate or unbundled retail transmission rate is established, FERC has indicated that it has jurisdiction to determine the rate. FERC Order No. 888 (April 24, 1996). /12 As the industry is restructured, some amount of additional price volatility can be expected as a natural consequence of moving away from a regulated environment. Customers should, however, have tools available to them to limit that volatility, much as purchasers of home heating oil do today. /13 The introduction of retail competition will create winners and losers among generation providers. There are likely to be mergers and consolidations as companies seek the best ways to be competitive. As a result, the current mix of "local" and "regional" producers serving the Maine market is likely to change. This is a natural consequence of allowing competition in retail generation markets. /14 Stranded costs are discussed in section VII, below. /15 Traditionally, research and development (R&D) of generation technologies occurred, to a large extent, through the Electric Power Research Institute (EPRI), an organization funded by utilities and their ratepayers. With the deregulation of generation, EPRI is likely to reduce or eliminate generation R&D. The extent to which unregulated entities will devote resources to generation R&D is unknown. /16 Areas such as the South and Northwest have relatively lower rates due in part to federally subsidized hydro-electric projects (e.g., Tennessee Valley Authority, Bonneville Power Administration) and the close proximity of relatively inexpensive coal, oil, and natural gas. /17 In Maine, the change in incentives should not be dramatic, because under the regulatory method and commitments already in place for Central Maine Power Company, Maine Public Service Company, and Bangor Hydro-Electric Company, changes in tax assessments already flow almost entirely to shareowners rather than ratepayers. /18 For example, the Massachusetts Legislature considered a bill to compensate municipalities for any loss in property tax revenue that may result from a devaluation of electric generation facilities due to the restructuring of the electric industry. The Massachusetts Legislature has not taken any final action on the bill. /19 The Commission would have the authority to delay or accelerate the beginning of retail competition by up to 90 days if necessary for administrative or technological reasons. A change in the start date by more than 90 days would require legislative action. /20 In this document, the "Paradigm" refers to the "Paradigm for Restructuring Investor-Owned Electric Utilities: A New Industry Structure," a restructuring plan that was supported by eight members of the Work Group on Electric Industry Restructuring. The eight members of the Work Group that presented the Paradigm are: American Association of Retired Persons, Senator John Cleveland, Conservation Law Foundation, Independent Energy Consumers Group, Independent Energy Producers, Representative Carol Kontos, Office of the Public Advocate, and Pine Tree Legal. /21 These states are Rhode Island, New Hampshire, Massachusetts, and Vermont. /22 These matters are discussed in more detail in section VII, below. /23 Such litigation appears likely in New Hampshire. /24 Customer education efforts are discussed in section V, below. /25 The efficiencies and innovations that should result from retail competition will develop over time. The shifting of costs from ratepayers to shareholders or among ratepayer groups is in no sense an "efficiency gain" from competition. It is simply a transfer of dollars. /26 Customers in a town could choose alternate suppliers even if a municipality decides to aggregate load on behalf of its residents. A municipality would have to seek legislative authorization to restrict consumer choice. /27 The cost of special meters has been dropping in recent years and is likely to continue to do so. Applied Resources Group stated in their comments that reasonably priced load profile meters are likely to be available by 1998. BHE suggested that necessary meters entail a substantial cost, while the Maine Municipal Utilities Group (MMUG) stated that the necessary technology does not exist unless load is aggregated on a geographic basis. /28 Once generation services are no longer subject to price regulation, any currently-existing immunity from the anti-trust laws would effectively disappear. /29 Some have raised questions regarding the impact of the North American Free Trade Agreement (NAFTA) on reciprocity issues and access by Maine providers to Canadian markets. Basically, NAFTA provides for equal treatment of United States and Canadian producers. For example, if it were lawful for Maine to have a retail access reciprocity requirement, the requirement could be applied to Canadian providers. /30 Maine's IOUs are CMP, BHE and MPS. /31 COUs are municipal or quasi-municipal electric utilities and electric cooperatives. /32 When referring to the period after December 1999, the terms "CMP" and "BHE" refer to those two companies' continuing T&D utility entities. /33 T&D utilities may develop services which are largely unrelated to their core regulated activities. In such cases the T&D utility would have no obligation to offer such non-core and non- regulated services to all customers or energy providers. /34 For an analysis of the State's authority to order divestiture, see Responsive Comments of OPA, filed on September 13, 1996 in Docket No. 95-462. /35 For further discussion of this issue, see Section VII(B)(3)(a). /36 In prior years, the Commission determined electric utility avoided costs in blocks of capacity referred to as "decrements." The utilities then went out to bid for blocks of power from independent producers, primarily QFs, for each decrement capped at the avoided cost. /37 To the extent such information has value and is transferred to a utility affiliate or sold for a profit, the value should accrue to ratepayers. /38 A counter-factual analysis attempts to isolate the economic effects of a policy change during a time period and compare them to the economic effects that an alternative policy would have had during the same time period. For example, it is often impossible to separate the impact of one policy change from contemporaneous changes in other factors. Moreover, it is difficult to estimate what the status quo would have been absent the policy change. These difficulties would be especially apparent in electric restructuring due to the many policy changes embodied in the effort. /39 This could occur if customers continually take service from the market when conditions are favorable and then switched to the standard offer when market conditions change. /40 The Commission's Rules for credit, collection and disconnection are currently contained in Chapters 81 and 86. The Commission anticipates re-examining these Chapters and may modify their provisions. /41 The commission would continue to regulate standard offer service providers to some extent. /42 These numbers do not include self-generated electricity, nor NEPOOL net interchanges. /43 A market may develop for renewable credits, similar to that for trading of sulfur dioxide (SO2) allowances under the Federal Clean Air Act. /44 The Commission would also determine in the proceeding what energy sources would be considered "renewable". /45 The Vermont Public Service Board recently proposed a portfolio requirement with tradable credits as part of its recommendations for restructuring. /46 New Hampshire, Massachusetts, Vermont, and Rhode Island appear likely to include provisions to ensure renewable resource generation. California provides funding for renewable technologies. /47 The Commission's view is that a renewable portfolio standard would not violate the Commerce Clause. /48 Regulatory assets are not tangible, physical assets. They are essentially ratepayer obligations created by regulation. These assets represent costs that utilities have incurred in the past, but are recovered from ratepayers over time. /49 Under traditional ratemaking, the cost of generation assets are recovered through the utility's rate base over their depreciable lives. The remaining costs of these assets are those that have not yet been recovered. The costs of purchased power contracts have generally been recovered as an expense. The remaining costs of these contracts refer to the payments for future deliveries of power under the terms of the contracts. /50 The United States Supreme Court has recognized a Constitutional distinction between a reduction in economic value that results from governmental action as opposed to general economic forces. Market St. Ry. Co. v. Calif. R.R. Comm'n, 324 U.S. 548, 567 (1945). /51 While not directly applicable, the recent United States Supreme Court decision in United States v. Winstar Corp., ___ U.S.___, 116 S.Ct. 2432, 135 L.Ed 2nd 964 (1996) suggests, at least, that government should act responsibly in changing the "rules of the game". /52 The Commission does not, however, encourage bankruptcy, strategic or otherwise, as a tool to reduce costs. /53 Two jurisdictions, California and Pennsylvania, have enacted legislation that attempts to mitigate stranded costs, and thus reduce rates, through innovative financing mechanisms. Essentially, these jurisdictions have created a statutory right for the recovery of some types of costs through utility rates. This results in greater certainty of cost recovery that should lower the utilities' financing costs. The savings in financing cost would be passed onto ratepayers. /54 Consistent with Statement of Financial Accounting Standards No. 71, the Commission would establish rates that specifically allow for recovery of regulatory assets. /55 In fact, BHE management appears to recognize this risk in its power purchases. It has bought relatively short-term power and has also begun hedging against the risk of fuel price volatility. /56 All calculations would reflect present value where appropriate. /57 FERC has asserted jurisdiction over stranded cost recovery associated with wholesale service and the formation of new retail utilities, such as municipalizations. FERC Order No. 888 (April 24, 1996). FERC has indicated that it will use the lost revenue approach to calculating stranded costs. Because of FERC's assertion of jurisdiction, the recommended plan does not address stranded cost recovery with respect to pre-existing wholesale arrangements or the creation of new retail utilities. /58 For example, the Massachusetts Commission imposed an exit fee for a large customer to avoid a significant impact on the utility and its remaining ratepayers. Re: Cambridge Electric Light Co., 164 PUR 4th 69 (Sept. 28, 1995). The California Legislature has authorized changes to customers that bypass their utility's system as part of a comprehensive restructuring plan that includes innovative financing to obtain rate decreases for all to customers. /59 Under section 202(c) of the Federal Power Act, FERC may require utility actions related to reliability if it determines that an emergency exists. /60 FERC has indicated that it has jurisdiction to determine the rates for separated or unbundled retail transmission service. FERC Order No. 888 (April 24, 1996). /61 In a survey recently conducted for the Commission, Maine's residential and small business customers identified reliability as the most important aspect of electric power. /62 The PTF rate was established by NEPOOL members to encourage joint ownership in large generating units distributed around the region. Exhibit 99(o) Page 1 Appendix 2 Proposed Restructuring Legislation This appendix contains proposed legislation to implement the Commission's Report and Recommended Plan on Electric Utility Industry Restructuring issued on December 31, 1996. This proposed legislation is intentionally less specific than the Restructuring Report. As is discussed in detail in the Report, the full implementation of the Commission's recommendations is contingent on a variety of circumstances and developments. The proposed legislation is drafted in a way that, if enacted, would specify the limits of the Commission's authority to implement the restructuring plan while simultaneously providing sufficient flexibility to accommodate evolving circumstances that may arise during the implementation of the Plan. This proposed legislation is not the only legislation that will ultimately be needed to restructure Maine's electric utility industry. This proposed legislation would only allow the Commission to begin the transition to retail competition. Many additional changes to Title 35-A and other titles in Maine statutes will have to be made before the process can be completed. At each step of the process, the Legislature will have the opportunity to review how events are unfolding and determine the proper next steps. The Commission recognizes that the legislative role of setting the proper balance between allowing the flexibility essential to any effective regulatory process and articulating clear policy is especially complex where comprehensive change is proposed. The Commission is committed to assisting the Legislature in any way it can to find that balance for the future of electricity regulation in Maine. Page 2 Appendix 2 Proposed Restructuring Legislation AN ACT to Restructure Maine's Electric Industry Sec. 1. 35-A M.R.S.A. ch. *** is enacted to read: CHAPTER *** ELECTRIC RESTRUCTURING SS 1. Findings and purpose. 1. Findings. The Legislature finds that: A. Where viable markets exist, market mechanisms should be preferred over regulation, and the risk of business decisions should fall on investors rather than consumers; B. Customers' needs and preferences should be met with the lowest costs; C. All customers should have a reasonable opportunity to benefit from a restructured electric industry; D. Electric industry restructuring should not diminish environmental quality, compromise energy efficiency or jeopardize energy security; E. All customers should have access to reliable, safe and reasonably priced electric service; F. Electric industry restructuring should not diminish low- income assistance or other consumer protections; G. The electric industry structure should be lawful, understandable to the public, and fair and perceived to be fair; and H. Electric industry restructuring should improve the state's business climate. Page 3 Appendix 2 2. Purpose. The purposes of this chapter are: A. To promote efficient and effective competition in the market for the generation and sale of electricity in the state; B. To ensure that all consumers of electricity are able to benefit from competition; C. To provide an orderly transition from the current form of regulation to retail competition for electricity; D. To continue to provide the public with opportunities to participate in decisions concerning electric restructuring; and E. To ensure that the commission has all necessary authority to implement an electric restructuring plan consistent with the findings and purposes expressed in this chapter. SS 2. Definitions As used in this chapter, unless the context otherwise indicates, the following terms have the following meanings. 1 . Affiliated interest. "Affiliated interest" has the same meaning as provided in section 707(l)(A). 2. Competitive generation provider. "Competitive generation provider" means generators, marketers, brokers, aggregators or any other entity producing or selling electric power to meet retail customers' demand. 3. Consumer owned transmission and distribution utility. "Consumer owned transmission and distributed utility" means any transmission and distribution utility which is wholly owned by its consumers, including, but not limited to: A. The transmission and distribution portion of any rural electrification cooperative organized under chapter 37; B. The transmission and distribution portion of any electrification cooperative organized on a cooperative plan under the laws of the state; C. Any municipal or quasi-municipal transmission and distribution utility; Page 4 Appendix 2 D. The transmission and distribution portion of any municipal or quasi-municipal entity providing generation and other services; and E. Any transmission and distribution utility wholly owned by a municipality. 4. Divest. "Divest" means to legally transfer ownership and control to an entity that is not an affiliated interest. 5. Large investor owned transmission and distribution utility. "Large investor owned transmission and distribution utility" means an investor owned transmission and distribution utility serving more than 50,000 retail customers. 6. Qualifying facility. "Qualifying facility" has the same meaning as provided in section 3303. 7. Retail access. "Retail access" means the right of any retail consumer of electricity to purchase generation services from a competitive generation provider. 8. Small investor owned transmission and distribution utility. "Small investor owned transmission and distribution utility" means an investor owned transmission and distribution utility serving 50,000 or fewer retail customers. 9. Transmission and distribution plant. "Transmission and distribution plant" includes all real estate, fixtures and personal property owned, controlled, operated or managed in connection with or to facilitate the transmission, distribution or delivery of electricity for light, heat or power, for public use, and all conduits, ducts or other devices, materials, apparatus or property for containing, holding or carrying conductors used or to be used for the transmission or distribution of electricity for light, heat or power for public use. 10. Transmission and distribution utility. "Transmission and distribution utility" includes every person, its lessees, trustees, receivers or trustees appointed by any court owning, controlling, operating or managing any transmission and distribution plant. Page 5 Appendix 2 SS 3. Retail access 1. Right to purchase generation service. Beginning on January 1, 2000, all consumers of electricity have the right to purchase generation service directly from competitive generation providers. The commission may advance or delay the date for retail access by not more than 90 days if necessary to achieve the purposes of this chapter. 2. Aggregation permitted. When retail access begins, all consumers of electricity may aggregate their purchases of generation services in any manner they choose. 3. Public agency may not restrict choice. If a public agency serves as an aggregator, it may not require consumers of electricity within its jurisdiction to purchase generation services from that agency. SS 4. Deregulation of generation services Except as otherwise provided in this chapter, competitive generation providers are not subject to regulation under this Title as of January 1, 2000. SS 5. Structural separation and divestiture of generation 1. Structural separation required. On or before January 1, 2000, each investor owned electric utility shall transfer to a distinct corporate entity all generation assets and generation-related business activities, including electric energy sales activities, and generation- related contracts, except as provided in subsection 3. The commission shall determine the extent of separation between affiliates that is required under this subsection. 2. Interests in generation restricted. Except as otherwise provided in this section, on or after January 1, 2000, no investor owned transmission and distribution utility may: A. Acquire or hold any financial or ownership interest in generation assets or generation-related business activities or contracts for generation; or B. Produce, purchase, sell, market, aggregate customers, broker, or engage in any similar activity relating to generation capacity or energy. Page 6 Appendix 2 3. Sale of capacity and energy required. Investor owned utilities may not be required to transfer to a distinct corporate entity contracts with a qualifying facility. Beginning January 1, 2000, each large investor owned transmission and distribution utility shall sell all rights to capacity and energy from its contracts with qualifying facilities. Beginning January 1, 2006, each large investor owned transmission and distribution utility shall sell all the rights to capacity and energy from any contracts with the Maine Yankee Atomic Power Company. 4. Divestiture required; exception. On or before January 1, 2006, each large investor owned transmission and distribution utility shall divest all generation assets and generation-related business activities, except contracts with qualifying facilities and the Maine Yankee Atomic Power Company. After divestiture, no large investor owned transmission and distribution utility may have any affiliated interest in a competitive generation provider. 5. Commission may require divestiture of Maine Yankee interests. Notwithstanding any other provision of this chapter, the commission may, if necessary to achieve the purposes of this chapter, require any investor owned transmission and distribution utility to divest its interest in the Maine Yankee Atomic Power Company on or after January 1, 2009. 6. Commission may require exempt utilities to divest. The commission may require any small investor owned transmission and distribution utility to divest, and thereafter have no affiliated interest in a competitive generation provider, except contracts with qualifying facilities and the Maine Yankee Atomic Power Company. In order to require divestiture under this subsection, the commission must find that divestiture is necessary to achieve the purposes of this chapter. 7. Generation assets permitted. On or after January 1, 2000, notwithstanding any other provision in this chapter, the commission may allow an investor owned transmission and distribution utility to own, have a financial interest in, or otherwise control generation and generation- related assets to the extent that the commission finds such ownership, interest or control is necessary for the utility to perform its obligations as a transmission and distribution utility in an efficient manner. The transmission and distribution utility may not sell the energy or capacity from generation that it owns, has a financial interest in, or otherwise controls to any retail customer. 8. Retail marketing restricted; wholesale marketing prohibited; exception. Except as provided in subsection 6, after January 1, 2006, consumer owned transmission and distribution utilities and affiliated interests of small investor owned transmission and distribution utilities: Page 7 Appendix 2 A. May provide retail generation service only within their respective service territories; and B. May not provide wholesale generation service except that incidental wholesale sales are permitted if necessary to reduce the cost of providing retail service. SS 6. Regulation of transmission and distribution utilities Nothing in this chapter limits the commission's authority to regulate electric transmission and distribution service and to ensure that all consumers of electricity are afforded transmission and distribution service at just and reasonable rates. SS 7. Stranded cost recovery Beginning with the implementation of retail access, the commission shall provide electric utilities a reasonable opportunity to recover, through the rates of the transmission and distribution utility, legitimate, verifiable and unmitigatable costs made unrecoverable as a result of retail access. Prior to the implementation of retail access, the commission shall determine the amount of these costs for each electric utility and may subsequently adjust these costs as necessary. SS 8. Standard offer service At the time retail access begins, the commission shall ensure that standard offer service is available to all consumers of electricity, except that the Commission may establish eligibility requirements that exclude consumers of electricity with demands above a specified amount if the Commission finds that these consumers do not need standard offer service and their eligibility for the service would increase its costs. The commission shall establish terms and conditions for standard offer service. Standard offer service must be available until January 1, 2005 and may be continued after that date if the commission finds it necessary. Nothing in this section precludes the commission from permitting or requiring different terms and conditions for standard offer service in different utility service territories and for different customer classes. SS 9. Consumer protection The commission shall ensure that all retail customers are protected to the greatest extent possible from unfair trade practices, fraud, and other unreasonable practices by competitive generation providers and transmission and distribution utilities. Page 8 Appendix 2 1. Authority. In implementing this section, the commission, notwithstanding any other provision of this chapter: A. Registration. Shall impose reasonable registration requirements on competitive generation providers; B. Consumer protection standards. Shall establish consumer protection standards to protect retail consumers of electricity from fraud or other unreasonable business practices. Violations of the consumer protection standards shall be a civil violation for which the Commission may impose penalties, not exceeding $5,000 for each occurrence. C. Dispute resolution. Shall resolve disputes between competitive generation providers and retail consumers of electricity with respect to Commission established customer protection standards; D. Disconnection restricted. May forbid transmission and distribution utilities from disconnecting electric service to any consumer of electricity based on nonpayment of charges owed or alleged to be owed to any competitive generation provider. The commission may permit disconnection of electric service to consumers of electricity based on nonpayment of charges for standard offer service; E. Disclosure. May require the disclosure, to the extent necessary to achieve the purposes of this chapter, of information about the competitive generation provider's services, including, but not limited to information about the characteristics of the generation assets used by the competitive generation provider. The Commission shall provide for reasonable confidentiality protections, if necessary; F. Maine Unfair Trade Practices Act. Has concurrent authority with the Attorney General to act under the Maine Unfair Trade Practices Act with respect to retail sales activities of competitive generation providers; and G. Additional actions. May impose any additional requirements necessary to carry out the purposes of this chapter, except that this section may not be construed to permit the commission to regulate the rates of any competitive generation provider. Page 9 Appendix 2 SS 10. Energy policy The commission shall, in a manner consistent with the requirements of an efficient and effective competitive market for electricity, promote the development and use of renewable resources in producing electric power and promote the use of conservation and load management. 1. Authority. In carrying out the requirements of this section, the commission may, without limitation on other actions it considers necessary: A. Renewable resources. Require competitive generation providers to produce, or obtain credits for, a specified portion of their electric power sold to consumers of electricity in the state using renewable resources; and B. Conservation programs. Require transmission and distribution utilities to implement energy conservation programs and include the cost of any such programs in rates. SS 11. Consumer education and information The commission shall take all steps necessary to ensure that, prior to the implementation of retail access, electricity consumers are aware, to the greatest extent practicable, of the opportunities and risks of electric restructuring. 1. Authority. In implementing this section, the commission may, without limitation on other actions it considers necessary: A. Unbundled bills. Require electric utilities to issue bills which, to the extent practicable, state the current cost of electric capacity and energy separately from other charges for electric service; and B. Publish information. Publish and disseminate, through whatever means it considers appropriate, information that will enhance customers' ability to exercise their choices in a competitive electricity market effectively. SS 12. Commission proceedings and report 1. Commission proceedings. The commission shall conduct any proceedings necessary to implement this chapter. Nothing in this chapter is intended to exempt the commission from the requirements of Title 5, section 8071, to the extent the Commission adopts any major substantive rules. Page 10 Appendix 2 2. Annual restructuring report. On December 31st of each calendar year, the commission shall submit to the Joint Standing Committee on Utilities and Energy, a report describing the commission's activities in carrying out the requirements of this chapter and further describing activities relating to changes in the regulation of electric utilities in other jurisdictions. SS 13. Proposed changes If the commission determines, after providing interested parties an opportunity to be heard, that any provision in this chapter is not in the public interest, the commission shall present a report to the joint standing committee of the Legislature having jurisdiction over utility matters stating the basis for the commission's conclusion and including draft legislation designed to modify this chapter consistent with the public interest. Sec. 2. Recommendation for Low Income Program. On or before January 1, 1998, the commission and the State Planning Office shall provide to the Joint Standing Committee on Utilities and Energy, to the Joint Standing Committee on Appropriations and Financial Affairs, to the Joint Standing Committee on Taxation, and to any other committees of relevant jurisdiction, draft legislation that would fund assistance to low income consumers of electricity through the general fund or through a tax on all energy sources in the state. Sec. 3. Market power report. On or before December 1, 1998, the commission shall submit a report to the Joint Standing Committee on Utilities and Energy, on whether market power exists or is likely to arise in the generation market in New England. Sec. 4. Conforming amendments. The commission shall identify and submit to the Legislature by December 31, 1998, for enactment any amendments required to conform other statutes to the provisions of this Act. Exhibit 99(p) UNITED STATES DISTRICT COURT DISTRICT OF MAINE PEOPLES HERITAGE BANK, et al, ) ) Plaintiffs ) ) ) vs. ) ) Civil No. 95-0180-B MAINE PUBLIC SERVICE COMPANY, ) ) Defendant ) J U D G M E N T This matter having come before the Court, Honorable Eugene W. Beaulieu presiding, and the issues having been duly tried, and pursuant to the Findings of Fact and Conclusions of Law entered by the Court on December 2, 1996, JUDGEMENT is hereby entered for Defendant and against the Plaintiffs. Dated this 2nd day of December, 1996. WILLIAM S. BROWNELL, CLERK /s/ Harriett D. Jefferson Harriett D. Jefferson, Case Manager UNITED STATES DISTRICT COURT DISTRICT OF MAINE PEOPLES HERITAGE BANK, and ) APEX, INC. ) ) Plaintiffs ) ) v. ) Civil No. 95-0180-B ) MAINE PUBLIC SERVICE COMPANY, ) ) Defendant ) FINDINGS OF FACT AND CONCLUSIONS OF LAW /1 This is an action arising out of costs incurred by Plaintiffs in remediating environmental contamination at property they allege was contaminated by Defendant's electrical transformers. The matter came before the Court for bench trial beginning on July 22, 1996. Following trial, the parties were directed to submit proposed findings and conclusions for the Court's review, and those materials have been submitted. Based upon a review of the proposed findings and conclusions, as well as the evidence presented at trial, the Court hereby enters the following Findings of Fact and Conclusions of Law. FINDINGS OF FACT 1. In September, 1992, the Asset Management Department of Peoples Heritage Bank ["PEOPLES"] purchased the Mitchell Trucking property in Presque Isle, Maine ["THE SITE"] at a foreclosure auction. Peoples' bid was assigned to APEX, Inc. ["APEX"], a subsidiary of Peoples that holds, manages, and sells foreclosed properties. ______________________ 1/ Pursuant to Federal Rule of Civil Procedure 73(b), the parties have consented to allow the United States Magistrate Judge to conduct any and all proceedings in this matter. 2. Maine Public Service Company ["MPSC"] is an electric utility located in Presque Isle, Maine, which provided electrical service to the Site from 1956 to the present. 3. In October, 1992, County Environmental Engineering ["CEE"] began a Department of Environmental Protection ["DEP"] site assessment at the Site. During the assessment, CEE's excavator bucket hit cedar log cribbing material about two feet below the surface. Inside the crib was two feet of watery substance on top of two feet of a white pasty substance. 4. As directed by DEP, CEE placed the material in a dumpster located east of the crib. Some of the material spilled as it was put into the dumpster. 5. Samples taken of the soil around the area were tested, and found to be contaminated with polychlorinated biphenyls ["PCBs"] at 330 parts per million. 6. Higher concentrations (as high as 1800 parts per million) of PCBs were found in other locations at the Site. 7. There are different types of PCBs, which are identified by a number called an "Aroclor." The soil samples at the Site contained only Aroclor 1248. 8. Since 1956, MPSC has had at least six distribution transformers located at the Site. One of those transformers has been shown to contain Aroclor 1248 at concentrations perhaps as high as 7.5 parts per million. 9. Since 1956, the Site has been used by several manufacturing concerns. Plaintiff's expert concedes, while believing the transformers contaminated the Site, that there are other possibilities arising from these earlier uses of the Site. 10. From 1956 to as late as 1964, Shalek Bag Company operated a facility for the manufacture of burlap and paper bags on the Site. The manufacturing processing involved the use of inks, dyes and solvents, at least one of which is unidentified. The solvents were used to wash inks and dyes from print rolls at a sink that drained into a cesspool located at the approximate location of the crib. 11. Maine Potato Growers purchased the Site in 1965. From 1975 to 1980, the Site was leased to Converse Rubber Company. Converse used the facility for the process of stitching canvas uppers to the rubber soles of shoes. 12. The Site was sold to Mitchell Trucking Company in 1984, following which four underground storage tanks were installed on the Site, one for kerosene, one for diesel fuel, and two for No. 2 fuel oil. DEP records indicate a spill from one of No. 2 fuel tanks in 1984. 13. Also in 1984, the utility poles were relocated and fill from an unknown source was brought to the Site as part of a landscaping project. Conclusions of Law 1. Defendant concedes that Plaintiffs are entitled to the security interest exception to liability under the Comprehensive Environmental Response, Compensation, and Liability Act ["CERCLA"], 42 U.S.C. SS-SS 9601- 9675. See Northeast Doran v. Key Bank of Maine, 15 F.3d 1, 2-3 (1st Cir. 1994). Accordingly, Plaintiff's claim in Count II for contribution under section 113 of CERCLA, 42 U.S.C. SS 9613, is hereby DISMISSED. See United Tech. v. Browning-Ferris Ind., 33 F.3d 96, 103 (1st Cir. 1994). 2. Defendant concedes that its transformers are "facilities" under CERCLA, and that it is therefore a "covered person" within the meaning of CERCLA, inasmuch as it is an owner operator of a facility on the Site. 42 U.S.C. SS 9607. 3. Defendant concedes Plaintiffs have incurred necessary costs of response in remediation of the contamination found at the Site. 42 U.S.C. SS-SS 9601(25), 9607(a)(4)(B). 4. The Court finds that Plaintiffs have failed to prove by a preponderance of the evidence that there was a "release of a hazardous substance from" the distribution transformers located on the Site and owned by Defendant. 42 U.S.C. SS 9607(a); Dedham Water v. Cumberland Farms Dairy, 889 F.2d 1146, 1151 (1st Cir. 1989). Plaintiffs ask the Court to infer that the transformers must have been the source of the contamination on the basis of one expert's opinion that none of the other uses of the Site could have released Aroclor 1248. However, there were unidentified materials (including the fill used by Mitchell Trucking and the cleaning solvent used by Shalek Bag Company) present on the Site. Further, there is an absence of evidence (1) that any of the transformers contained Aroclor 1248 in anything near the concentrations discovered on the Site, and (2) that any of the transformers ever spilled onto the Site. Finally, there was credible expert testimony that the other uses could have caused the contamination. On the record before it, the court is simply unable to adopt the inference Plaintiffs propose. Accordingly, Judgment is appropriately entered for Defendant on Counts I and II of Plaintiffs' Complaint. 5. Plaintiffs dismissed their state law claims (Counts IV through VIII) with prejudice on July 24, 1996. Conclusion Accordingly, Judgment shall enter for Defendant as against Plaintiffs on all Counts of Plaintiffs' Complaint. SO ORDERED. /s/ E. W. Beaulieu Eugene W. Beaulieu U.S. Magistrate Judge Dated at Bangor, Maine on December 2, 1996 Exhibit 99(q) INDEPENDENT AUDITORS' REPORT To the Board of Directors and Shareholders of Maine Public Service Company Presque Isle, Maine We have audited the consolidated balance sheet and statement of capitalization of Maine Public Service Company and its Subsidiary, Maine and New Brunswick Electrical Power Company, Limited, as of December 31, 1995, and the related consolidated statements of operations, common shareholders' equity, and cash flows for each of the two years in the period ended December 31, 1995 listed in the Index at Item 14. Our audits also included the financial statement schedule 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 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, such consolidated financial statements present fairly, in all material respects, the financial position of Maine Public Service Company and its subsidiary at December 31, 1995, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 1995 in conformity with generally accepted accounting principles. Also, in our opinion, such financial statement schedule, for each of the two years in the period 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. DELOITTE & TOUCHE LLP Boston, Massachusetts February 14, 1996 [ARTICLE] UT [PERIOD-TYPE] 12-MOS [FISCAL-YEAR-END] DEC-31-1996 [PERIOD-END] DEC-31-1996 [BOOK-VALUE] PER-BOOK [TOTAL-NET-UTILITY-PLANT] 50015 [OTHER-PROPERTY-AND-INVEST] 3659 [TOTAL-CURRENT-ASSETS] 11270 [TOTAL-DEFERRED-CHARGES] 51813 [OTHER-ASSETS] 0 [TOTAL-ASSETS] 116757 [COMMON] 7357 [CAPITAL-SURPLUS-PAID-IN] 38 [RETAINED-EARNINGS] 30697 [TOTAL-COMMON-STOCKHOLDERS-EQ] 38092 [PREFERRED-MANDATORY] 0 [PREFERRED] 0 [LONG-TERM-DEBT-NET] 39805 [SHORT-TERM-NOTES] 1400 [LONG-TERM-NOTES-PAYABLE] 0 [COMMERCIAL-PAPER-OBLIGATIONS] 0 [LONG-TERM-DEBT-CURRENT-PORT] 1315 [PREFERRED-STOCK-CURRENT] 0 [CAPITAL-LEASE-OBLIGATIONS] 0 [LEASES-CURRENT] 0 [OTHER-ITEMS-CAPITAL-AND-LIAB] 36145 [TOT-CAPITALIZATION-AND-LIAB] 116757 [GROSS-OPERATING-REVENUE] 57264 [INCOME-TAX-EXPENSE] 1955 [OTHER-OPERATING-EXPENSES] 50021 [TOTAL-OPERATING-EXPENSES] 51976 [OPERATING-INCOME-LOSS] 5288 [OTHER-INCOME-NET] 349 [INCOME-BEFORE-INTEREST-EXPEN] 5637 [TOTAL-INTEREST-EXPENSE] 3526 [NET-INCOME] 2111 [PREFERRED-STOCK-DIVIDENDS] 0 [EARNINGS-AVAILABLE-FOR-COMM] 2111 [COMMON-STOCK-DIVIDENDS] 2976 [TOTAL-INTEREST-ON-BONDS] 3096 [CASH-FLOW-OPERATIONS] 7385 [EPS-PRIMARY] 1.305 [EPS-DILUTED] 1.305
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