-----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, NJ1gCuf85cVktp3QSQ9XDQJKgyliVExCL8bsnG9cLpFLXBaMhs3/2ZBJoJWL8+p2 9M1OFUDnJSS2gFiqIFOYsw== 0000009548-96-000009.txt : 19960328 0000009548-96-000009.hdr.sgml : 19960328 ACCESSION NUMBER: 0000009548-96-000009 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 4 CONFORMED PERIOD OF REPORT: 19951231 FILED AS OF DATE: 19960327 SROS: NYSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: BANGOR HYDRO ELECTRIC CO CENTRAL INDEX KEY: 0000009548 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 010024370 STATE OF INCORPORATION: ME FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-10922 FILM NUMBER: 96538957 BUSINESS ADDRESS: STREET 1: 33 STATE ST CITY: BANGOR STATE: ME ZIP: 04401 BUSINESS PHONE: 2079455621 MAIL ADDRESS: STREET 1: PO BOX 932 CITY: BANGOR STATE: ME ZIP: 04401 10-K 1 1995 FORM 10-K FOR BANGOR HYDRO-ELECTRIC COMPANY FORM 10-K SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the Fiscal year ended DECEMBER 31, 1995 Commission File No. 0-505 ----------------- ----- BANGOR HYDRO-ELECTRIC COMPANY ----------------------------------------------------------------- (Exact Name of Registrant as specified in its charter) MAINE 01-0024370 - --------------------------- ------------------------- (State of Incorporation) (I.R.S. Employer ID No.) 33 STATE STREET, BANGOR, MAINE 04401 ---------------------------------------- --------- (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code 207-945-5621 -------------- Securities registered pursuant to Section 12(b) of the Act: Title of each class Name of exchange on which registered COMMON STOCK, $5 PAR VALUE NEW YORK STOCK EXCHANGE - -------------------------- ----------------------- Securities registered pursuant to Section 12(g) of the Act: Common Stock, $5 Par value (7,315,099 SHARES OUTSTANDING AT MARCH 20, 1996) -------------------------------------------------- 7% PREFERRED STOCK, $100 PAR VALUE -------------------------------------------------- 4 1/4% PREFERRED STOCK, $100 PAR VALUE -------------------------------------------------- 4% PREFERRED STOCK SERIES A, $100 PAR VALUE -------------------------------------------------- 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 (Section 229.405 of this chapter) is 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] The aggregate market value on March 20, 1996 of the voting stock held by non-affiliates of the registrant was $82.0 million. The information required by Part III Items 10, 11, 12 and 13 is incorporated by reference from the registrant's proxy statement which will be filed with the Securities and Exchange Commission within 120 days of the close of the registrant's fiscal year ended December 31, 1995. PART I - ------ ITEMS 1 THROUGH 2 BUSINESS; PROPERTIES - --------------------------------------- GENERAL ------- The Company is a public utility engaged in the generation, purchase, transmission, distribution and sale of electric energy, with a service area of approximately 5,275 square miles having a population of approximately 191,000 people. The Company serves approximately 103,000 customers in portions of the counties of Penobscot, Hancock, Washington, Waldo, Piscataquis and Aroostook. The Company also sells energy to other utilities for resale. The Company has two material wholly-owned subsidiaries. Penobscot Hydro Co., Inc. ("PHC") was incorporated in 1986 to own the Company's 50% interest in a joint venture, Bangor-Pacific Hydro Associates ("Bangor-Pacific"), which redeveloped the West Enfield hydroelectric project (the "West Enfield Project"). Bangor Var Co., Inc. ("Bangor Var Co.") was incorporated in 1990 to hold the Company's 50% interest in a partnership which owns certain facilities used in the Hydro-Quebec Phase II transmission project ("HQ-II") in which the Company is a participant. See "Joint Ventures." In 1995, 29.6% of the Company's kilowatt hour ("KWH") sales were to residential customers, 29.3% were to commercial customers, 39.9% were to industrial customers and 1.2% were to other customers. For additional information concerning the Company's sales, see Item 6, "Selected Financial Data", below. The Company's KWH sales are generally higher during the winter months, with the winter peak electric demand usually 15% higher than the summer peak. The maximum peak electric demand that the Company's system experienced during the 1995-1996 winter, as of March 20, 1995, was approximately 267 megawatts ("MW") on January 3, 1996. At that time the Company had approximately 379.4 MW of generating capacity and firm purchased power, comprised of 106 MW from Company-owned generating units, 61 MW from Maine Yankee Atomic Power Company's nuclear generating facility ("Maine Yankee"), 18 MW from Hydro Quebec, 53 MW from non-utility power producers, and 140 MW from short term economy purchases. The Company holds a 7% ownership interest in Maine Yankee which entitles the Company to purchase an approximately equal amount of the output of Maine Yankee, an entitlement of approximately 61 MW. Maine Yankee, which commenced commercial operation on January 1, 1973, is the only nuclear facility in which the Company has an ownership interest. Pursuant to a power purchase contract with Maine Yankee, the Company is obligated to pay its pro rata share of Maine Yankee's operating expenses, including fuel costs and decommissioning costs. In addition, under a Capital Funds Agreement entered into by the Company and the other sponsor utilities, the Company may be required to make its pro rata share of future capital contributions to Maine Yankee if needed to finance capital expenditures. See "Maine Yankee." The Company, along with the major investor-owned utilities of New England, has been a party to the New England Power Pool Agreement ("NEPOOL") since 1971. NEPOOL provides for joint planning and operation of generating and transmission facilities in New England, and governs generating capacity reserve obligations and provisions regarding the use of major transmission lines. The Company, as a member of NEPOOL, has a capability responsibility which involves carrying an allocated share of a New England capacity requirement which is determined for each period based on certain regional reliability criteria. 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. The Company is also subject to the jurisdiction of the Federal Energy Regulatory Commission ("FERC") as to certain matters, including licensing of its hydroelectric stations and rates for wholesale purchases and sales of energy and capacity and transmission services. Maine Yankee is subject to extensive regulation by the Nuclear Regulatory Commission ("NRC"). See "Rates and Regulation." The principal executive offices of the Company are located at 33 State Street, Bangor, Maine 04401; telephone (207) 945-5621. CERTAIN ISSUES FACING THE COMPANY ---------------------------------- CHANGES IN THE ELECTRIC UTILITY INDUSTRY AND IN REGULATION - See Item 7, "Management's Discussion and Analysis of Results of Operations and Financial Condition - Recent Developments for the Company and in the Electric Utility Industry and Potential Effects on Future Sales, Earnings and Dividend Policy" for a discussion of the effect of competition and other events on future sales, earnings and dividend policy. That discussion includes a description of a pending Maine Public Utilities Commission investigation into the possible restructuring of the electric industry in the State of Maine to increase retail competition. Also included in Item 7 is a complete report on the Company's efforts to provide electric rates set at competitive levels to retain and attract customers, including a discussion of the MPUC Order in early 1995 approving substantial changes in the way the Company's prices are established. Finally, see Item 7 for an analysis the implications of those developments on the Company's future dividend policy. MAINE YANKEE - The Company, through its equity investment totalling approximately $5.0 million at December 31, 1995, owns 7% of the common stock of Maine Yankee Atomic Power Company, which owns and operates an 880 megawatt nuclear generating plant in Wiscasset, Maine, and is entitled under a cost- based power contract to an approximately equal percentage of the plant's output. The Company's total payments under its power purchase agreement with Maine Yankee were approximately $14.3 million, of which approximately $1.9 million were related to the plant's 1995 sleeving project. Maine Yankee's operating license expires in 2008. During 1995, Maine Yankee experienced an extended outage to resleeve the approximately 17,000 steam generator tubes contained in the plant. That project was concluded in late 1995 and the plant returned to operation at 90% of its rated generating capacity in January, 1996. Maine Yankee is presently taking steps to meet Nuclear Regulatory Commission requirements to return to 100% operation. The Company cannot predict when the plant will gain the authority to return to 100% operating level or when it will achieve this level once authority is granted. For a further discussion regarding these issues, see Item 7, "Management's Discussion and Analysis of Results of Operations and Financial Condition - Recent Developments for the Company and in the Electric Utility Industry and Potential Effects on Future Sales, Earnings and Dividend Policy - Maine Yankee". The Company is required to fund its pro rata share of Maine Yankee's decommissioning costs, costs of storage and disposal of spent fuel and low-level radioactive wastes. Provision for these items, based on current estimates of the eventual costs, is made as Maine Yankee's rates are established, and are included in the Company's rates to customers. To the extent Maine Yankee cannot obtain its own financing, the Company would be required to pay its pro rata share of additional capital expenditures to maintain the unit in commercial operation. The magnitude of these various costs is dependent in part upon the future resolution of several political and technological uncertainties, and may be substantial. Maine voters have rejected three referendum proposals to force the premature shutdown of Maine Yankee, the most recent being in 1987; and the State of Maine has enacted several restrictive statutes purporting to govern aspects of Maine Yankee's operations. The Company would expect that its share of the costs of the operation and decommissioning of Maine Yankee will continue to be reflected in its rates, but cannot predict whether future voter and other necessary approvals will be obtained in a timely fashion or whether all technological uncertainties can be adequately resolved. SIGNIFICANT CUSTOMER - Pursuant to a special rate contract approved by the Maine Public Utilities Commission, the rate for service provided by the Company to HoltraChem Manufacturing Company, L.L.C. ("HMC"), a significant customer, is based in part on a "revenue sharing" arrangement whereby the revenues for service vary depending on the price and volume of product sold by HMC. During 1995, revenue sharing payments from HMC totalled approximately $4.2 million. HMC's principal business is selling chlorine and caustic soda, primarily to the paper industry in the State of Maine. As of this writing, there have not been significant changes in the price or volume of product sold by HMC during 1996. However, the Company is unable to predict whether market conditions for these products will change in the future. CONSTRUCTION PROGRAM The Company's construction program consists of extensions and improvements of its transmission and distribution facilities, construction of new generating stations or capital improvements to existing generating stations, capital improvements to the Company's internal computer and information systems and other general projects within the Company's service area. The Company projects that capital expenditures will aggregate about $33 million in the period 1996 through 1998 excluding capitalized overheads. RATES AND REGULATION -------------------- RATE MATTERS - See Item 7, "Management's Discussion and Analysis of Results of Operations and Financial Condition - Recent Developments for the Company and in the Electric Utility Industry and Potential Effects on Future Sales, Earnings and Dividend Policy - Changes in the Industry and in Regulation", incorporated herein by reference, for a discussion of recent changes in the way the Company's prices will be established in the future and for a description of the ongoing involvement by the MPUC in rate matters. In addition, the MPUC is currently investigating the possibility of implementing a "rate cap" mechanism for the Company that could, if implemented, restrict the Company's opportunity to adjust rates unless its earnings varied outside certain parameters. This investigation is a continuation of the MPUC's investigation of regulatory flexibility for the Company described in Item 7. It represents an attempt to institutionalize the Company's business strategy of trying to improve its financial condition through cost reductions and increased sales rather than through increases in core electric rates, also described in Item 7. The MPUC is expected to conclude the investigation this summer. OTHER REGULATION - The MPUC regulates numerous other matters affecting the Company, including financing, construction of generation and transmission facilities, credit, collection, conservation and demand side management programs, low income rate subsidies and purchases from non-utility power producers. Maine Yankee is subject to extensive regulation by the NRC. Under its continuing jurisdiction, the NRC may, after appropriate proceedings, require modification of nuclear power generating units for which operating licenses have already been issued, or impose new conditions on such permits or licenses, and may require that the operation of nuclear power generating units be temporarily or permanently reduced. The FERC regulates rates for sales of electricity to other utilities. In addition, all the Company's hydroelectric projects are licensed by the FERC. Under the Federal Power Act, upon not less than two years' notice the United States is empowered to take over and thereafter to maintain and operate a licensed hydroelectric project at or following the time a license expires. If the United States elects this option, it must pay the licensee its net investment in the project, not to exceed fair market value. If the United States does not elect this option, the FERC may issue a new license to the existing licensee upon such terms and conditions as are authorized or required under the then-existing laws and regulations. It may also, alternatively, issue a new license to a new licensee that has filed a competing license application. In choosing between competing license applications, the FERC must issue a license to the applicant whose proposal is best adapted to serve the public interest. The following table sets forth certain information with regard to such licenses. LICENSED ISSUE DATE OF CURRENT EXPIRATION PROJECT CAPACITY ORIGINAL LICENSE DATE - -------- -------- ----------------- ------------------ Ellsworth 8,900 KW April 12, 1977 December 31, 2018 Howland 1,875 KW September 12, 1980 September 30, 2000 Medway 3,400 KW March 29, 1979 March 31, 1999 Milford 6,400 KW December 31, 1969 Original license expired December 31, 1990 currently operating on year-to-year license. Orono 2,332 KW November 10, 1977 Original license expired September 25, 1985 currently operating on year-to-year license. Stillwater 1,950 KW August 10, 1978 Original license expired December 31, 1993 currently operating on year-to-year license. Veazie 8,400 KW February 18, 1965 Original license expired September 25, 1985 currently operating on year-to-year license. West Enfield* 13,000 KW February 3, 1970 June 26, 2024 - ---------------- * Through PHC, the Company has a 50% ownership interest in Bangor-Pacific, which owns and operates the West Enfield Project. The Company is actively pursuing the relicensing of the projects listed above which are operating on year-to-year licenses. Some of those relicensing proceedings have been delayed pending completion by the FERC of an Environmental Impact Statement of sections of the Penobscot River being prepared in connection with the Company's licensing of the Basin Mills project. See Note 7 to the Company's Consolidated Financial Statements, incorporated herein by reference. The Company has not received notice that the United States will exercise its rights to take over any of the Company's hydroelectric projects, nor have any competing applications been filed. Under a Federal statute enacted by Congress in 1986, participation in relicensing proceedings by governmental agencies and other parties was allowed to increase significantly. That increased participation may result in more burdensome and costly conditions imposed upon licensees of hydroelectric projects. The Company is unable to predict what terms and conditions, if any, might be included in new licenses or license renewals granted pursuant to the Company's licensing applications, or what impact any such terms and conditions might have on the Company's ability to operate and maintain the projects economically. SEABROOK --------- GENERAL - The Company was a participant in Seabrook from 1978 to 1986, with an ownership interest of 2.17%, or 25 MW, in each of the two 1150 MW units. Unit 2 was effectively canceled in 1984. In late 1984, following a lengthy MPUC investigation, the conclusion of which cast doubt on the wisdom of the Maine utilities' continued participation in Seabrook, the Company began efforts to sell its interest in the project. An agreement for the sale of Seabrook to EUA Power Corp. was reached in mid-1985 and was consummated in November 1986. In 1985, the MPUC approved an agreement among the Company, the MPUC Staff and the Public Advocate addressing the recovery through rates of the Company's investment in Seabrook ("Seabrook Stipulation"). Although implementation of the Seabrook Stipulation significantly improved the Company's financial condition, substantial write-offs were required. In August 1989, a comprehensive settlement agreement entered into by current and former joint owners of Seabrook became effective. Under the agreement, the signatories, representing virtually all of the ownership interests in Seabrook, relinquished claims against the lead owner, Public Service Company of New Hampshire, arising out of Seabrook. As a part of the settlement, former joint owners, including the Company, were relieved of certain contingent liabilities. JOINT VENTURES -------------- WEST ENFIELD - In 1986, the Company formed PHC, a wholly-owned subsidiary, which owns the Company's 50% ownership interest in Bangor-Pacific, a joint venture with a development subsidiary of Pacific Lighting Corporation. Bangor-Pacific undertook the redevelopment of an old 3.8 MW hydroelectric plant which the Company owned on the Penobscot River in Enfield and Howland, Maine, into a 13 MW facility, the West Enfield Project, and now operates the facility. Construction costs were shared equally by the Company and the other joint venturer until Bangor-Pacific completed its financing and took over ownership of the project, which occurred in January 1987. Commercial operation of the redeveloped West Enfield Project began in April 1988. Bangor-Pacific financed the $45 million cost of the redevelopment through the private placement of $40 million of 9.45% and 10.26% fixed rate amortizing term notes due 1996 and 2008, respectively, and $5 million of floating rate amortizing term notes due 1996 (collectively, the "Notes"). The Notes are secured by a mortgage on the West Enfield Project and a security interest in a 50-year power contract between the Company and Bangor-Pacific. The holders of the Notes are without recourse to the joint venture partners or their parent companies except that each partner has agreed to make payments in an amount equal to 50% of any amounts due and unpaid on the Notes but not exceeding distributions received from Bangor-Pacific in the preceding twelve-month period. Under the power contract between the Company and Bangor-Pacific, if the West Enfield Project operates as anticipated, payments by the Company to Bangor-Pacific are estimated at $7.5 million annually (without consideration of any distributions by the joint venture to the partners). In 1995, the Company paid approximately $7.3 million to Bangor-Pacific under this power contract. The Company would be required to make payments under the contract, regardless of whether any power were delivered, of approximately $4 million per year. However, the Company has the right to terminate the contract upon thirty-days' written notice if the failure to deliver power continues for a period of 112 consecutive months. NEPOOL/HYDRO-QUEBEC - The NEPOOL member utilities and Hydro-Quebec, a utility operating within the province of Quebec, Canada ("Hydro-Quebec"), have constructed facilities required to interconnect the electric systems in New England with the electric system of Hydro-Quebec. The initial stage of the interconnection consists of a completed and operational 450 KV transmission line from the Hydro-Quebec system to a terminal having an approximate rating of 690 MW at the Comerford Generating Station ("Comerford") on the Connecticut River in New Hampshire. The subsequent stage, HQ-II, completed in 1990, increased the interconnection transfer capability to approximately 2000 MW by means of a transmission line from Comerford to a terminal facility at the Sandy Pond Substation in Massachusetts. In 1990, the Company formed Bangor Var Co., a wholly owned corporate subsidiary, the sole function of which is to own a 50% interest in Chester SVC Partnership ("Chester"), a general partnership which owns the static var compensator ("SVC"), electrical equipment which supports the HQ-II transmission line. A wholly-owned subsidiary of Central Maine Power Company ("CMP") owns the other 50% interest in Chester. Chester has financed the acquisition and construction of the SVC through the issuance of $33 million in principal amount of 10.48% senior notes due 2020, and up to $3.2 million principal amount of additional notes due 2020 (collectively, the "SVC Notes"). The holders of the SVC Notes are without recourse to the partners or their parent companies and may only look to Chester and to the collateral for payment. Bangor Var Co. accounts for its investment in Chester under the equity method. Bangor Var Co.'s financial results are included in the Company's consolidated financial statements. The New England utilities which participate in HQ-II have agreed under a FERC-approved contract to bear the cost of Chester, on a cost-of-service basis, which includes a return on and of all capital costs. EMPLOYEES ---------- At December 31, 1995, the Company had 419 full time employees approximately 43% of whom were represented by a local union affiliated with the International Brotherhood of Electrical Workers (AFL-CIO). The present contract expires December 31, 1998. The Company believes that its relations with its employees are satisfactory. POWER SUPPLY SOURCES -------------------- GENERAL - In order to meet its load growth and reserve obligations under NEPOOL, the Company, in addition to utilizing its own generating capacity, acquires capacity and energy through contracts with other utilities and independent generation facilities and through joint ownership of generating facilities. The Company estimates that it has, or can acquire, sufficient generating capacity, through a combination of wholly-owned and jointly-owned generating facilities and purchased power contracts, to meet its anticipated load growth through the 1990's. The Company's sources of generation for electric sales to its customers (net of off-system sales to other utilities) for 1995, 1994 and 1993 by type of fuel is shown below. SOURCE 1995 1994 1993 ------ ---- ---- ---- Hydroelectric (Company*)....... 14% 15% 14% Nuclear Generation (Maine Yankee) 1% 25% 20% Oil (Company)................... 3% 2% 3% Biomass/Refuse (purchased)...... 6% 8% 15% NEPOOL/other purchases.......... 76% 50% 48% ---- ---- ---- Total....................... 100% 100% 100% ----- ---- ---- - -------------- * Includes purchases from the West Enfield Project, in which the Company has a 50% ownership interest. COMPANY-OWNED GENERATION ------------------------ The Company, as a tenant in common with other utilities, owns 8.33%, or approximately 50 MW, of William F. Wyman Unit No. 4 ("Wyman 4"), a 600 MW oil-fired generating unit in Yarmouth, Maine, constructed and operated by CMP as the lead owner. The Company is entitled to 8.33% of the energy produced by Wyman 4 and pays the same percentage of the unit's operating expenses. The Company owns two oil-fired generating units located at its Graham Station in Veazie, Maine ("Graham"), currently in deactivated reserve status, having a total capacity of 47 MW, as well as eleven internal combustion generation units located at three stations having a total capacity of 21 MW. The Company also owns seven hydroelectric stations having a total capacity of about 30 MW (excluding PHC's ownership interest in the West Enfield Project). All of the Company's hydroelectric stations are licensed under the Federal Power Act. See "Rates and Regulation." In addition, the Company owns more than 600 miles of transmission lines and more than 3,600 miles of distribution lines to serve its customers. Other properties consist of office, garage and warehouse facilities at various locations in its service area. POWER PURCHASE CONTRACTS ------------------------ The following chart sets forth information concerning the Company's major power purchase contracts exclusive of Maine Yankee. CONTRACTED QUANTITY OF SELLER TERM OF CONTRACT CAPACITY OR ENERGY - ---------- ------------------- --------------------------- Bangor-Pacific* August 21, 1986 through Total output of energy (Hydroelectric). May 31, 2024, at which from facility with name time Company can either plate rating of not more purchase the facility than 16 MW. at its fair market value or extend the contract for an additional 15 years (if the West Enfield Project's FERC license is also extended). Penobscot Energy January 21, 1984 through Total output of firm Recovery Company February 28, 2018. energy; minimum annual ("PERC") (Refuse). delivery of 105,000,000 KWH up to a maximum of 166,440,000 KWH per calendar year. Great Northern September 21, 1989 Approximately 20 MW. Paper Co. through October 31, (Cogeneration). 1996. New England November 1, 1994 through 30 MW and associated energy Power Company October 31, 1999. from two designated nuclear units New England January 1, 1996 through 25 MW and associated energy Power Company October 31, 1998 from a designated system contract United Illumi- November 1, 1994 through 30 MW and associated energy nating Company October 31, 1997 from a designated oil unit New Brunswick November 1, 1994 through 45 MW system purchase of Power October 31, 1997 capacity and energy New Brunswick April 1, 1996 through 10 MW system purchase of Power October 31, 1998 capacity and energy (months of April-October only) Great Bay Power January 1,1996 through 10 MW and associated energy Corporation March 31, 1998 from a designated nuclear unit (November-March only) - -------------- * Through PHC, the Company has a 50% ownership interest in Bangor-Pacific, which owns and operates the West Enfield Project. During 1995, the Company reached agreement with Babcock-Ultrapower West Enfield and Babcock-Ultrapower Jonesboro to buy back two power contracts totalling approximately 49 MW. See Item 7, "Management's Discussion and Analysis of Results of Operations and Financial Condition - Recent Developments for the Company and in the Electric Utility Industry and Potential Effects on Future Sales, Earnings and Dividend Policy - Buyback of Purchased Power Contracts. For further details with respect to certain of these contracts, see Note 6 of the Notes to Consolidated Financial Statements. The Company purchases energy from, and sells energy to, New Brunswick Electric Power Commission utilizing the transmission facilities of Maine Electric Power Company, Inc. ("MEPCO"), in which the Company owns a 14.2% equity interest. MEPCO owns and operates a 345 KV transmission line running from Wiscasset, Maine to the Maine/New Brunswick border. The Company interconnects with this line in Orrington, Maine. Several New England utilities, including the Company and MEPCO's other stockholders (two other Maine utilities), are parties to a transmission support agreement pursuant to which such utilities have agreed to pay MEPCO's costs, based on their relative system peaks, if MEPCO's revenues from transmission services are not sufficient to meet its expenses. The Company anticipates that any liability resulting therefrom will be immaterial. The Company also purchases energy on a short-term basis from time to time when it is economical to do so to displace higher cost energy from other sources. MAINE YANKEE ------------- GENERAL - The Company holds a 7% equity ownership interest in Maine Yankee which entitles the Company to purchase an approximately equal amount of the output of Maine Yankee, an entitlement of approximately 61 MW. Maine Yankee, which commenced commercial operation on January 1, 1973, is the only nuclear facility in which the Company has an ownership interest. The Company is obligated to pay its pro rata share of Maine Yankee's operating expenses, including fuel costs and decommissioning costs. In addition, under a Capital Funds Agreement entered into by the Company and the other sponsor utilities, each sponsor has agreed to provide a like percentage of Maine Yankee's capital requirements not obtained from other sources, subject to obtaining any necessary regulatory approvals. 1995 OUTAGE - The Maine Yankee plant, like other pressurized water reactors, experienced degradation of its steam generator tubes, principally in the form of circumferential cracking, which, until early 1995, was believed to be limited to a relatively small number of tubes. During the refueling and maintenance shutdown that commenced in February 1995, Maine Yankee detected through new inspection methods increased degradation of the plant's steam generator tubes to the extent that approximately 60% of the plant's 17,000 steam generator tubes appeared to have defects to some degree. Because of the large number of affected tubes, the remedy of plugging the degraded tubes to take them out of service was no longer a viable option. Following a detailed analysis of the safety, technical and financial considerations associated with the degraded steam generator tubes, Maine Yankee elected to repair the tubes by inserting and welding short reinforcing sleeves of an improved material in substantially all of the plant's steam generator tubes. Similar repairs have been completed at other nuclear plants in the United States and abroad, but not on the scale of the Maine Yankee project. With Westinghouse Electric Corporation as the general contractor, the sleeving project started in early June of 1995, after approval of the Westinghouse sleeving process by the Nuclear Regulatory Commission (NRC), and was essentially completed in early December. The repairs were estimated to cost $40 million, but Maine Yankee now estimates the project was completed for approximately $27 million. The Company charged to operations its share of the repair costs in 1995. During 1995, the Company incurred substantial costs for replacement power, and as explained above, since the FCA was eliminated at the beginning of 1995, the replacement power costs had a material impact in reducing earnings in 1995. After Maine Yankee went off-line, the Company incurred non-reconcilable incremental replacement power costs of approximately $8.6 million for the year. Combined with the Company's share of the repair cost, the Maine Yankee outage adversely impacted the Company's earnings in 1995 by $.86 per common share, after taxes. On December 4, 1995, when the resleeving project was substantially complete, Maine Yankee received 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 former employee of Yankee Atomic Electric Company (Yankee), an affiliate of 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 NRC in seeking 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's containment peak postulated accident pressure, both under certain assumed accident conditions. The analyses were used in support of license amendments that authorized an increased rating of the plant from a level equal to approximately 90% of the maximum electrical capability of the plant to its current 100% rated level. In response to technical issues raised by the allegations, the NRC initiated a special technical review of the safety analysis performed by Yankee relating to Maine Yankee's license amendment applications for the power uprates. At the same time, Maine Yankee and Yankee initiated intensive internal investigations of the allegations and provided responsive information and documentation to the NRC. On December 18, 1995, a public meeting was held at the NRC to discuss the findings resulting from the NRC's technical review. At the meeting the NRC informed Maine Yankee that it had concerns regarding the adequacy of a proprietary computer code used in ECCS safety analyses supporting Maine Yankee's last two applications for license amendments that authorized power uprates to levels above 90% of its current maximum capacity. At the meeting the NRC also indicated that operation of the plant at a level up to 90% could be acceptable if operations were based on methods previously found acceptable by the NRC staff and not on the computer code that is currently under review by the NRC, and further informed Maine Yankee of the terms and conditions under which Maine Yankee could resume power operation of the plant. Subsequently, the NRC informed Maine Yankee that the allegations made in the anonymous letter would be the subject of investigations by the NRC's Office of Investigations and the Office of the Inspector General. 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 Confirmatory Order) confirming the conclusions of the NRC from the public meeting and follow-up communications with Maine Yankee. The Confirmatory Order limited the power output of the Maine Yankee plant to approximately 90% of its rated maximum until the NRC shall have 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 Confirmatory Order further required that prior to operating the plant at any level, Maine Yankee should submit under oath specified information relating to operating the plant at up to the 90% level and descriptions of measures taken to assure compliance with the limitations on operating level and containment pressure. With respect to subsequently returning the plant to its 100% operating level, the Confirmatory Order required Maine Yankee to submit a plant-specific analysis meeting the NRC's requirements for ECCS operation under specified conditions at plant power levels up to 100% of its maximum rated capability. The Confirmatory Order also required an integrated containment analysis demonstrating that the maximum calculated containment pressure under certain postulated accident conditions does not exceed the design-basis pressure of the plant's containment. In addition, the Confirmatory Order required Maine Yankee to submit a schedule for providing the requested analyses and related information to the NRC. As of this writing, the Maine Yankee plant is operating at the 90% level, and Maine Yankee is continuing its efforts to meet the NRC's requirements to return to the 100% operating level. The Company cannot predict when the plant will gain the authority to return to the 100% operating level or when it will achieve this level once authority is granted. As a result of Maine Yankee's operating limitation, the Company will incur replacement power costs of between $70,000 and $100,000 per month as long as that limitation is in effect. Finally, the Company cannot predict the results of the internal and external investigations of the allegations brought to Maine Yankee's attention on December 4, 1995. Maine Yankee has stated, however, that it intends to pursue its internal investigation diligently and cooperate with the governmental investigations, and that it believes that after it develops information requested by the NRC for operation of the plant at full capacity it will be able to operate the plant at that level while meeting all applicable NRC safety requirements. NUCLEAR FUEL STORAGE - Federal legislation enacted in 1987 directed the U.S. Department of Energy ("DOE") to proceed with the studies necessary to develop and operate a permanent high-level waste (spent fuel) disposal site at Yucca Mountain, Nevada. The legislation also provides for the possible development of a Monitored Retrievable Storage ("MRS") facility and abandons plans to identify and select a second permanent disposal site. An MRS facility would provide temporary storage for high-level waste prior to eventual permanent disposal. In late 1989, the DOE announced that the permanent disposal site was not expected to open before 2010, although originally scheduled to open in 1998. Additional delays due to political an technical problems are probable. On June 20, 1994, fourteen nuclear utilities filed suit against the DOE. The utilities are seeking a declaration from the United States Court of Appeals for the District of Columbia that the Nuclear Waste Policy Act requires the DOE to take responsibility for spent nuclear fuel in 1998. Maine Yankee is not participating in the lawsuit, but is monitoring developments. Under the terms of a license amendment approved by the NRC in 1984, the present storage capacity of the spent fuel pool at the Plant will be reached in 1999, and after 1996 the available capacity of the pool will not accommodate a full-core removal. After consideration of available technologies, Maine Yankee elected to provide additional capacity by replacing the fuel racks in the spent fuel pool at the Plant and, on January 25, 1993, filed with the NRC seeking authorization to implement the plan. On March 15, 1994, the NRC granted the authorization, and installation of the new racks is scheduled for 1996. Maine Yankee believes that the replacement of the fuel racks will provide adequate storage capacity through the Plant's licensed operating life, but cannot predict with certainty whether or to what extent the new level of storage capacity at the Plant will affect the operation of the Plant or the future cost of disposal. NUCLEAR INSURANCE - In accordance with the Price-Anderson Act, the limit of liability for a nuclear-related accident is approximately $8.9 billion, effective November 18, 1994. The primary layer of insurance for the liability is $200 million of coverage provided by the commercial insurance market. The secondary coverage is approximately $8.7 billion, based on 110 licensed reactors. The secondary layer is based on a retrospective premium assessment of $79.275 million per nuclear accident per licensed reactor, payable at a rate not exceeding $10 million per year per accident. In addition, the retrospective premium is subject to inflation-based indexing at five-year intervals and, if the sum of all public liability claims and legal costs arising from any nuclear accident exceeds the maximum amount of financial protection, each licensee can be assessed an additional 5% ($3.775 million) of the maximum retrospective assessment. In addition to the insurance required by the Price-Anderson Act, Maine Yankee carries all-risk nuclear property damage insurance in the amount of $500 million plus additional excess nuclear property insurance in the amount of $2.25 billion, effective January 1, 1995. The all-risk nuclear property damage insurance of $500 million is obtained from the commercial insurance market and is not subject to retrospective premium assessments. The excess insurance of $2.25 billion is provided by a nuclear electric utility industry insurance company through a combination of current premiums, retrospective assessments and reinsurance. If the insurance company experiences losses in excess of its capacity to pay them, each participating utility may be assessed a retrospective premium of up to 7.5 times its premium with respect to industry losses in any policy year, which could range up to approximately $22.7 million for the Company. This excess coverage amount is the maximum offered by the industry mutual company. LOW-LEVEL WASTE DISPOSAL - The federal Low-Level Radioactive Waste Policy Amendments Act (the "Waste Act"), enacted in 1986, required operating disposal facilities to accept low-level nuclear waste from other states until December 31, 1992. Maine did not satisfy its milestone obligation under the Waste Act requiring submission of a site license application by the end of 1991, and therefore became subject to surcharges on its waste and did not have access to regulated disposal facilities after the end of 1992. Maine Yankee then began storing all low-level waste generated at an on-site storage facility. On July 1, 1995, however, the State of South Carolina restored access to its facility and Maine Yankee has begun to ship low-level waste to the South Carolina facility for disposal. The states of Maine, Texas and Vermont have been pursuing the implementation of a compact for the disposal of low-level waste at a site in Texas. The ratification bill for the compact is before Congress for consideration at its 1996 session. The compact provides for Texas to take Maine's low-level waste over a 30-year period for disposal at a planned facility in west Texas. In return, Maine would be required to pay $25 million, assessed to Maine Yankee by the State of Maine, payable in two equal installments, the first after ratification by Congress and the second upon commencement of operation of the Texas facility. In addition, Maine Yankee would be assessed a total of $2.5 million for the benefit of the Texas county in which the facility would be located and would also be responsible for its pro-rata share of the Texas governing commission's operating expenses. The Maine Low-Level Radioactive Waste Authority suspended its search for a suitable disposal site in Maine and, as of June 30, 1994, ceased operations. In the event the required ratification by Congress is not obtained, subject to continued NRC approval, the Company will ship low-level waste off site for disposal in South Carolina or other available sites as long as the sites are available, reserving its capacity to store approximately ten to twelve years' production of low-level waste at its facility at the Plant site. Subject to obtaining necessary regulatory approval, the company could also build a second facility on the Plant site. The Company believes it is probable that it will have adequate storage capacity for such low-level waste available on-site, if needed, through the current licensed operating life of the Plant. The Company cannot predict whether the final required ratification of the Texas compact or other regulatory approvals required for on-site storage will be obtained, but Maine Yankee intends to utilize its on-site storage facility as well as dispose of low-level waste at the South Carolina site or other available sites in the interim and continue to cooperate with the State of Maine in pursuing all appropriate options. CITIZEN COMPLAINT - By letter dated January 20, 1996 a citizen group called FRIENDS OF THE COAST -OPPOSING NUCLEAR POLLUTION filed a letter with the NRC pursuant to 10 C.F.R. 2.206 alleging certain safety concerns. Specifically, the group alleges (1) that the plant's containment is inadequate for power operation in excess of its original license and may be inadequate for original power operation limits based upon the design of the plant, and (2) that the plant's emergency core cooling system may not be adequately analyzed for materials degradation to ensure integrity at power operation at levels above original license limits or under accident conditions. The group is asking that the NRC suspend Maine Yankee's operating license or, in the alternative, limit the operating license to lower generating capacity levels than presently allowed. Maine Yankee has informed the Company that it believes that these issues were resolved previously and are not of any current concern. ENVIRONMENTAL MATTERS ---------------------- The Company is regulated by the Federal Environmental Protection Agency ("EPA") as to compliance with the Federal Water Pollution Control Act, the Clean Air Act of 1970 (the "Clean Air Act"), and certain federal statutes governing the treatment and disposal of hazardous wastes, as well as by the Maine Department of Environmental Protection under Maine's hazardous waste statutes. Although the Company is actively engaged in complying with such acts and statutes, the costs of which are significant, it has not, to date, encountered material difficulties in connection with such compliance. The Clean Air Act was amended by Congress in 1990 which will result in new regulatory requirements to install more advanced pollution control equipment and to make other changes to reduce the emission of air pollutants. The amendment includes new initiatives to deal with the problem of acid rain which will impact the air emissions of fossil-fueled power plants. Under Phase I implementation, specific plants will be required to reduce their sulphur dioxide emissions in 1995. The Company does not own or operate any Phase I plants. Under Phase II implementation, essentially all fossil-fueled power plants must reduce their sulphur dioxide emission. The Company has not completed its evaluation of the concomitant capital and operating costs needed to comply with the amendment, including the provisions relating to nitrogen oxide emissions and monitoring. Wyman 4 is located in a non-attainment area for nitrogen oxide and may be subject to additional regulations for the control of nitrogen oxide emissions. The Company estimates that during 1995 it will spend approximately $450,000 in operations expenses and $700,000 in capital expenditures to comply with environmental standards for air, water and hazardous materials. EXECUTIVE OFFICERS OF THE COMPANY --------------------------------- The following are the present executive officers of the Company with all positions and offices held. There are no family relationships between any of them nor are there any arrangements pursuant to which any were selected as officers. NAME AGE OFFICE AND YEAR FIRST ELECTED - ---- --- ------------------------------ Robert S. Briggs 52 President & Chief Executive Officer since January 1991 Carroll R. Lee 46 Vice President-Operations since 1990 Frederick S. Samp 45 Vice President - Finance & Law since 1995; Treasurer since 1995; Chief Financial Officer since 1995 Each of the executive officers has for more than the last five years been an officer or employee of the Company. Mr. Briggs was Vice President and General Counsel from 1979 until 1987, Vice President-Law and Public Affairs from 1987 until 1988, Executive Vice President & Chief Operating Officer from 1988 until 1989 and President and Chief Operating Officer from 1989 until 1991. From 1983 through 1984, Mr. Lee was Vice President-Power Supply and Planning and he served as Vice President-Engineering and Operations from 1985 until 1987 and Vice President-Planning & Development from 1987 until 1990. Mr. Samp was Corporate Counsel, Corporate Secretary and Clerk from 1985 until 1988 and General Counsel, Corporate Secretary and Clerk from 1988 until 1995. Item 3 LEGAL PROCEEDINGS ------------------ See Note 8 to the Company's Financial Statements for a discussion of potential liabilities under the Comprehensive Environmental Response, Compensation, and Liability Act. ITEM 4 SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS - ------ ---------------------------------------------------- Not applicable. PART II - ------- ITEM 5 MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED - ------ ------------------------------------------------- STOCKHOLDER MATTERS ------------------- As of December 31, 1995, there were 8,250 holders of record of the Company's common stock. The Company's common stock is traded on the New York Stock Exchange ("NYSE") under the symbol "BGR". The following table sets forth the high and low prices for the Common Stock as reported by the NYSE. The prices shown do not include commissions. Dividends are declared quarterly. DIVIDENDS DECLARED FISCAL PERIOD HIGH LOW PER SHARE - ------------- ---- --- --------- 1994 - ---- First Quarter................ $19 $16 3/8 $.33 Second Quarter............... 17 13 .33 Third Quarter................ 13 1/2 11 1/4 .33 Fourth Quarter............... 12 1/4 9 3/8 .33 1995 - ---- First Quarter................ $12 7/8 $9 1/4 $.33 Second Quarter............... 12 3/8 9 1/8 .18 Third Quarter................ 12 1/2 10 1/4 .18 Fourth Quarter............... 12 3/4 11 1/8 .18 1996 - ---- First Quarter (through March 20, 1996)... $12 1/2 $10 1/2 $.18 ITEM 6 - ------ SELECTED FINANCIAL DATA - ----------------------- SIX YEAR STATISTICAL SUMMARY Bangor Hydro-Electric Company
1995 1994 1993 1992 1991 1990 - --------------------------------------------------------------------------------------------------------------------------- MEGAWATT HOURS (MWH) GENERATED AND PURCHASED Hydro Generation (Company) 275,810 271,616 275,694 305,011 313,629 350,898 Nuclear Generation (Maine Yankee) 13,606 456,871 395,665 368,641 430,879 334,343 Oil (Company) 50,706 35,759 47,115 80,770 70,681 150,074 Biomass/Refuse 177,558 190,218 281,260 307,451 338,376 435,050 NEPOOL/Other Purchases 1,540,530 958,363 937,431 767,306 702,818 674,738 - --------------------------------------------------------------------------------------------------------------------------- Total Generated & Purchased 2,058,210 1,912,827 1,937,165 1,829,179 1,856,383 1,945,103 Less Line Losses and Company Use 140,128 136,908 135,561 131,764 122,370 125,265 - --------------------------------------------------------------------------------------------------------------------------- Remainder - MWH sold 1,918,082 1,775,919 1,801,604 1,697,415 1,734,013 1,819,838 =========================================================================================================================== CLASSIFICATION OF SALES - MWH Residential 513,076 516,470 515,242 521,889 517,259 517,946 Commercial 511,720 507,285 500,488 490,861 483,376 481,301 Industrial 686,386 611,876 615,314 563,734 539,565 567,595 Lighting 9,547 9,416 9,590 9,876 10,615 11,104 Wholesale 10,961 11,705 10,311 10,462 10,880 16,930 - --------------------------------------------------------------------------------------------------------------------------- Total MWH Billed to Customers 1,731,690 1,656,752 1,650,945 1,596,822 1,561,695 1,594,876 Unbilled Sales - Net Increase (Decrease) 4,658 6,366 2,001 (11,832) 4,175 1,451 - --------------------------------------------------------------------------------------------------------------------------- Total Delivered Sales (MWH) 1,736,348 1,663,118 1,652,946 1,584,990 1,565,870 1,596,327 (Less) Non-Firm Sales 295,818 231,128 254,359 208,066 203,108 236,834 - --------------------------------------------------------------------------------------------------------------------------- Total Firm Delivered Sales (MWH) 1,440,530 1,431,990 1,398,587 1,376,924 1,362,762 1,359,493 Off-System Sales 181,734 112,801 148,658 112,425 168,143 223,511 - --------------------------------------------------------------------------------------------------------------------------- Total Energy Sales (MWH) 1,918,082 1,775,919 1,801,604 1,697,415 1,734,013 1,819,838 =========================================================================================================================== ELECTRIC OPERATING REVENUES AND EXPENSES (000'S) OPERATING REVENUES Residential $ 66,061 $ 64,008 $ 64,244 $ 66,429 $ 58,510 $ 53,090 Commercial 55,030 53,410 53,599 53,806 46,859 41,820 Industrial 39,929 37,040 39,508 39,340 34,047 35,059 Lighting 2,051 2,010 1,915 1,933 1,755 1,621 Wholesale 859 937 903 895 898 1,431 - --------------------------------------------------------------------------------------------------------------------------- Total Revenue From Customers $ 163,930 $ 157,405 $ 160,169 $ 162,403 $ 142,069 $ 133,021 Unbilled Sales-Net Increase (Decrease) 210 1,450 (237) (964) 2,642 (277) - --------------------------------------------------------------------------------------------------------------------------- Total Revenue $ 164,140 $ 158,855 $ 159,932 $ 161,439 $ 144,711 $ 132,744 (Less) Non-Firm Revenue 11,149 8,450 8,876 8,331 8,040 11,959 - --------------------------------------------------------------------------------------------------------------------------- Total Firm Revenue $ 152,991 $ 150,405 $ 151,056 $ 153,108 $ 136,671 $ 120,785 Off-System Revenue 14,098 12,750 15,326 13,857 15,736 17,746 - --------------------------------------------------------------------------------------------------------------------------- Total Operating Revenues $ 178,238 $ 171,605 $ 175,258 $ 175,296 $ 160,447 $ 150,490 =========================================================================================================================== OPERATING EXPENSES Fuel Used in Generation $ 82,301 $ 90,339 $ 102,670 $ 101,465 $ 93,687 $ 83,904 Purchased Power 16,383 13,793 13,716 13,478 13,387 11,607 Operating and Maintenance Expense 35,711 33,498 29,474 27,042 25,253 23,898 Depreciation and Amortization 20,544 10,333 6,447 6,789 6,615 7,004 Taxes 6,306 8,803 8,866 9,499 6,856 7,735 - --------------------------------------------------------------------------------------------------------------------------- Total Operating Expenses $ 161,245 $ 156,766 $ 161,173 $ 158,273 $ 145,798 $ 134,148 =========================================================================================================================== SUMMARY OF OPERATIONS (000'S) Operating Revenue $ 184,914 $ 174,098 $ 177,972 $ 176,789 $ 162,243 $ 151,673 Operating Expenses 161,245 156,766 161,173 158,273 145,798 134,148 Other Income (including equity AFDC) 760 1,308 (2,657)* 1,690 2,367 1,738 Interest Expense (net of borrowed AFDC) 20,092 11,183 8,805 9,952 10,614 10,894 - --------------------------------------------------------------------------------------------------------------------------- Net Income (Loss) $ 4,337 $ 7,457 $ 5,337 * $ 10,254 $ 8,198 $ 8,369 Less Preferred Dividends 1,702 1,652 1,646 1,613 1,613 1,613 - --------------------------------------------------------------------------------------------------------------------------- Earnings on Common Stock $ 2,635 $ 5,805 $ 3,691 * $ 8,641 $ 6,585 $ 6,756 =========================================================================================================================== SELECTED FINANCIAL DATA Total Assets (000's) $ 566,076 $ 381,250 $ 373,521 $ 288,867 $ 279,483 $ 269,735 ELECTRIC PLANT (000'S) Total Electric Plant $ 323,664 $ 303,637 $ 281,606 $ 255,601 $ 232,079 $ 209,757 Depreciation Reserve 81,934 75,667 71,184 67,645 66,111 63,330 - --------------------------------------------------------------------------------------------------------------------------- Net Electric Plant $ 241,730 $ 227,970 $ 210,422 $ 187,956 $ 165,968 $ 146,427 =========================================================================================================================== CAPITALIZATION (000'S) Short-Term Debt $ 35,000 $ 27,000 $ 36,000 $ 15,000 $ 28,500 $ 23,000 Long-Term Debt 288,075 116,367 119,126 100,685 81,515 89,565 Redeemable Preferred Stock 12,070 13,740 15,168 15,102 15,068 15,034 Preferred Stock 4,734 4,734 4,734 4,734 4,734 4,734 Common Equity 103,192 105,658 93,944 82,230 79,797 67,473 - --------------------------------------------------------------------------------------------------------------------------- Total $ 443,071 $ 267,499 $ 268,972 $ 217,751 $ 209,614 $ 199,806 - --------------------------------------------------------------------------------------------------------------------------- CAPITAL STRUCTURE RATIOS (%) Short-Term Debt 7.9% 10.1% 13.4% 6.9% 13.6% 11.5% Long-Term Debt 65.0% 43.5% 44.3% 46.2% 38.9% 44.8% Preferred Stock 3.8% 6.9% 7.4% 9.1% 9.4% 9.9% Common Stock 23.3% 39.5% 34.9% 37.8% 38.1% 33.8% - --------------------------------------------------------------------------------------------------------------------------- Total 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% =========================================================================================================================== MISCELLANEOUS STATISTICS Shares Outstanding (Average) 7,264,360 6,947,746 5,862,411 5,393,306 4,947,232 4,450,684 Shares Outstanding (Year End) 7,301,557 7,185,143 6,225,394 5,420,955 5,370,684 4,450,684 Number of Stockholders (Year End) 8,250 7,705 7,511 7,325 7,116 6,839 Earnings per Common Share $ 0.36 $ 0.84 $ 0.63 * $ 1.60 $ 1.33 $ 1.52 Dividends Declared per Common Share $ 0.87 $ 1.32 $ 1.32 $ 1.32 $ 1.29 $ 1.25 Book Value per Common Share $ 14.13 $ 14.71 $ 15.09 $ 15.17 $ 14.86 $ 15.16 Return on Common Equity 2.51% 5.55% 3.99%* 10.60% 8.81% 10.11% Ratio of AFDC to Common Stock Earnings 48% 45% 143%* 28% 29% 21% Ratio of Earnings to Fixed Charges 1.28 1.37 1.04 * 1.96 1.65 1.76 Payout Ratio 200% 157% 210%* 82.5 % 97.0 % 82.2 % Percentage of Construction Expenditures Funded Internally 100% 82% 72% 70 % 37 % 8 % =========================================================================================================================== RESIDENTIAL CUSTOMER DATA Average Number of Customers 86,194 85,041 84,211 83,305 82,568 81,151 Kilowatt-Hours per Customer 5,953 6,073 6,118 6,265 6,265 6,382 Revenue per Customer $ 766.42 $ 752.67 $ 762.89 $ 797.42 $ 708.63 $ 654.21 Revenue per Kilowatt-Hour in cents 12.88 12.39 12.47 12.73 11.31 10.25 =========================================================================================================================== MISCELLANEOUS SYSTEM DATA Net System Capability at Time of Peak (MW) Firm 330.01 340.45 341.17 342.39 337.29 323.06 System Peak Demand (MW) (Winter Peak) 267.98 275.84 267.42 253.27 264.17 251.62 Reserve Margin at Time of Peak 23.2% 23.4% 27.6% 35.2% 27.7% 28.4% System Load Factor 79.9% 73.5% 76.4% 77.2% 73.0% 79.5% =========================================================================================================================== * Includes the reserve established on certain licensing activites in 1993 ($5.6 million after taxes or $.95 per common share). (See note 6).
ITEM 7 - ------ MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION RECENT DEVELOPMENTS FOR THE COMPANY AND IN THE ELECTRIC UTILITY INDUSTRY AND POTENTIAL EFFECTS ON FUTURE SALES, EARNINGS AND DIVIDEND POLICY CHANGES IN THE INDUSTRY AND IN REGULATION - Historically, the electric utility industry has been viewed as relatively stable for common equity investors, providing a consistent level of dividends with moderate growth and presenting a comparatively low risk to equity investments. This stability developed because of public policies that treated electric utilities as natural monopolies, requiring regulation of rates and service and the protection of defined service territories. The industry has been substantially free of competition while its profits have been limited by traditional rate of return regulation. In recent years, several factors have worked together to increase competitive pressures on electric utilities in the United States and particularly in Maine. Prices charged by Maine's electric utilities have increased rapidly to cover the costs of implementing various public policy mandates including the purchase of power from high cost non-utility power producers, the subsidization of energy conservation and demand-side management measures, financial assistance for low income customers, environmental mitigation and improvement measures, and various other requirements. In addition, public and regulatory policies implemented in Maine in the 1970s and 1980s overtly discouraged the growth of electric sales, thereby tending to increase unit costs. As a consequence of these factors, electric rates in Maine have, on average, increased faster than the electric rates in New England, exclusive of Maine. In the past, Maine's rates were substantially lower, on average, than elsewhere in New England, but with the rate of increase experienced recently, the average rate in Maine is now just below the New England average. The Company's average rates are slightly less than the Maine statewide average. On an industry-wide scale, high embedded costs for many utilities have combined with certain fundamental changes in the regulation of the electric utility industry and in the economics of power generation to threaten the ability of many traditional utilities to retain existing customers and to attract new load. The Energy Policy Act of 1992 requires that the owner of transmission facilities must, under certain specified conditions, transmit power for third parties to "wholesale customers" meaning other retail distribution utilities that are purchasing power for resale in their utility business. This access to the transmission system allows existing municipal and other distribution utilities that have traditionally purchased power from neighboring utilities to purchase power in the competitive generation markets. It also provides an incentive for the existing retail customers of a utility to seek to lower their electric rates by forming a municipal utility or utility district solely to qualify for the transmission access. Although the 1992 Act does not require transmission access for retail customers, individual states may authorize such access. At the Federal level and in many of the States, various further initiatives have been underway to restructure the electric industry in such a way so as to allow for completion of the transition to a competitive market for the generation of electricity and for the implementation of "retail wheeling" to allow customers to choose their electric energy vendors. Although the State of Maine has not heretofore taken the lead in promoting these efforts, in 1995 the Maine Legislature adopted a Resolve to study restructuring the electric utility industry in the State. The objective of the study is to see what it would take to implement competition by the year 2000. The first part of the Resolve required the formation of a "Work Group" made up of representatives of a number of diverse interests including Maine electric utilities. The work of that Group was completed late in 1995. While the Group reached general agreement on the identification of issues to be resolved before effective competition can be introduced, the diverse interests of the participants prevented a consensus on a plan of implementation. The second part of the Legislature's Resolve requires the Maine Public Utilities Commission (MPUC) to conduct a study of Maine's electric utility industry and to develop at least two plans for an orderly transition to a competitive market for the retail purchase and sale of electricity. One plan must result in the achievement of full retail market competition in Maine by the year 2000, and the other plan must propose a structure of regulated and unregulated markets that maximizes the benefits of competition. The MPUC inquiry, which was formally initiated on December 12, 1995, must be completed and a report must be submitted to the Legislature no later than January 1, 1997. In accordance with the MPUC's Notice of Inquiry, interested parties, including the Company, submitted their initial comments in late January 1996. The Company cannot predict the outcome of this proceeding, or whether this proceeding or other proceedings and initiatives will lead to further restructuring activities. In addition to the increased pressures of competition from relaxed access to transmission services and the prospect of full retail wheeling in the future, technological improvements and increasing competition in the generation of electricity have in recent years lowered the cost of generation. The cost of new generation facilities today is significantly lower than the cost of facilities built only a few years ago that are now embedded in the existing cost structure of electric utilities. In addition, the cost for a large retail customer to install its own generation facilities at the point of consumption has dropped to a level that can be competitive with the prices charged by electric utilities. Finally, competition for the business of individual consumers and retail customers has increased as the price of electricity has risen and the availability of alternative methods of providing the services desired by customers has increased. This has lead to discussions of the concept of utilities having "core" and "non-core" customers, with the former being thought to have no real alternative to electricity for the particular service they need, and the latter considered as being "at risk" of loss depending on price. In order to meet these competitive pressures and achieve profitability over the long term, the Company believes that it must control its costs and increase sales in order to minimize the rates it charges for electricity, and achieve greater revenue through increased sales. Although under traditional, "cost-plus", rate-of-return regulation the Company could reasonably expect to be allowed by the MPUC to increase its retail rates in an effort to enhance its profitability, the Company believes that this approach, taken by itself, would risk further erosion in sales. While it is difficult to forecast the precise relationship among rates, energy sales and total revenues over the short term, the Company believes that significant rate increases at this time would have a negative long-term impact on the Company's competitive position and its long-term financial success. The Company also believes this strategy is consistent with the implementation of greater retail competition, whether through the restructuring activities described above or otherwise. Accordingly, although the Company has not ruled out seeking modest rate relief from the MPUC in the future, it does not believe that the present challenge of relatively low earnings can be solved solely by rate increases. Despite the challenges of meeting increasing competition, the Company believes that it can succeed in the long run because it has the experience and breadth of knowledge to meet the needs of its customers in the part of Maine it serves and because the marginal cost of providing electric service is relatively low. The Company expects that, if public and regulatory policies were adjusted to permit the active pursuit of greater sales, the price that could be charged in a competitive environment, while lower than many of the Company's current rates, would recover more than the marginal cost of providing the service. The Company believes that, at such lower prices, there is substantial potential for increased business. Moreover, the Company believes that a strategy of greater electrification would produce desirable environmental quality improvement, and the realization of this beneficial impact will tend to enhance the favorable outlook for increased sales. To the extent the Company is successful in expanding its market share with competitive rates, the increased revenue in excess of marginal cost will enhance earnings and offset the need for other rate increases. Under traditional regulatory policies, the Company has had only limited authority to adjust its prices to meet the competition. Competitive price initiatives have been evaluated and approved by the MPUC on a case-by-case basis. For example, for several years the Company has been allowed to sell interruptible energy to two major customers at significantly reduced rates, thereby retaining load that otherwise would have been lost and providing an incentive to add new load. More recently, the Company has been negotiating on an individual basis with customers that have demonstrated that, without rate relief, they will curtail their purchases from the Company. In early 1994, the MPUC authorized the Company to enter into a five-year contract (terminable by the customer with two years' notice) for the supply of power to one of the Company's largest firm industrial customers at reduced rates. At present, about 40% of the Company's commercial and industrial load is being served by such negotiated rates. Despite those successes in retaining customers, the Company realized some time ago that more flexibility was necessary in order effectively to meet the demands of competition in a timely manner. Procedural obstacles and the lack of clear standards for evaluating proposed rate reductions had hindered the Company's ability to react quickly and flexibly to competitive threats. In 1994, the Company sought additional regulatory flexibility, and in early 1995, the MPUC approved a new Alternative Marketing Plan (or AMP) permitting greater opportunities for the Company to meet the challenges of competition over the long term. Specifically, the MPUC established the following guidelines for the reduction of rates with limited regulatory oversight: 1. For existing customer classes, the Company may offer reduced rates with a price floor at the Company's long-term marginal cost plus 10% as long as the rate structure of the class is maintained within specified limits. Rates that meet the criteria take effect automatically after a 30-day notice period. If a proposed reduction does not meet the criteria, the MPUC may suspend its effectiveness but will make a decision within four months of the initial filing date. 2. The Company may develop rates for new targeted customer classes with a price floor that depends upon whether the new load is "temporary" (not expected to continue for an extended period and sensitive to rate changes that occur after the initial discount) or "permanent" (expected to continue indefinitely regardless of later rate adjustments). For temporary load, the floor is short-term marginal cost plus 1.5 cents/KWH or, under certain circumstances, short-term marginal cost plus 10%. For permanent load, the floor is long-term marginal cost plus 10%. Rates that meet the criteria take effect automatically after a 30-day notice period. 3. The Company may negotiate special rate contracts with individual customers, the criteria for which depend upon the length of the contract and whether the load is temporary or permanent. a. For short-term contracts (up to three years) to supply temporary load, the floor is short-term marginal cost plus 1.5 cents/KWH. For short-term contracts to supply permanent load, the floor is long-term marginal cost plus 10%. Short-term contracts that meet all criteria take effect automatically after a 30-day notice period. b. For contracts with terms of three to five years, the floor is long-term marginal cost plus 10%. For contracts with terms of five to ten years, the floor is long-term marginal cost plus 25%. Contracts that meet all criteria take effect automatically after a 30-day notice period. c. Contracts with terms over ten years may not be approved automatically, but the MPUC will review any such proposal within four months of filing. 4. Any rate reduction that results in permanent load will also be subjected to certain cost tests, the results of which must be presented by the Company at the time of filing. If the proposal fails any of the tests, the Commission may suspend its effectiveness and the MPUC will review it within four months of filing. 5. The Company was authorized to eliminate seasonal rate differentials (requiring higher charges during winter months than during the remainder of the year) for certain classes of customers, and did so effective March 1, 1995. 6. The total amount of price reductions (the "revenue delta") offered by the Company under the AMP is capped at 10% of the Company's revenues. If the revenue delta approaches the cap, the Company must request authority from the MPUC to offer further discounts. As part of the AMP, effective January 1, 1995 the MPUC ordered the elimination of the Fuel Cost Adjustment (FCA), a rate mechanism under which the Company has historically been permitted to adjust retroactively for changes in the cost of fuel for generation and in certain purchased power costs. The Company had itself proposed this change because, under traditional regulation, the operation of the FCA has imposed the burden of the revenue loss as a result of price reductions on existing sales on utility shareholders while the benefits have been enjoyed by other utility customers. The Company believed, therefore, that a business strategy dependent on pricing flexibility would be effective only if the FCA were eliminated. However, the FCA had allowed the Company to respond quickly to changes in fuel and purchased power costs (both increases and decreases) and reduced the volatility of earnings. The Company recognized that its elimination might result in increased or decreased earnings solely from changes in costs over which the Company has limited control. As discussed in the following pages, the unanticipated outage during most of 1995 of the Maine Yankee nuclear power plant, of which the Company is a minority owner, had a significant negative impact on 1995 earnings in part because of the elimination of the FCA. The Company purchases, rather than generates itself, a significant portion of the energy required to service its retail business. These purchased energy prices can vary with changes in the price or availability of the underlying fuel sources, and the risk of such price volatility is no longer covered by a rate mechanism like the FCA. To manage this exposure, in 1995, effective January 1, 1996, the Company entered into hedging transactions with three financial institutions. The Company determined that much of its exposure to purchased energy price volatility is closely matched to changes in residual oil prices. Accordingly, the Company entered into agreements known as "swaps", essentially in which the Company agreed to pay a fixed price for a specific quantity of a specific commodity (residual oil in this case), for a given time period. This transfers the risk (or the benefit) of commodity price fluctuations to the other party to the agreement for the given period of time. These are strictly financial transactions, and no delivery of the underlying commodity is taken. Settlements typically occur on a monthly basis and the cash receipts/payments arising from the "swap" transactions will offset corresponding increases/decreases in the Company's purchased energy costs. As a result, the Company can manage a substantial portion of the risk of energy price fluctuations, which allows the Company to more accurately predict its future purchased energy costs and cash flow requirements. To ensure the Company maintains a hedging, and not a speculative, position, the Company has established official policies, procedures and controls for its fuel hedging program. As of January 1, 1995, the Company's collections under the FCA had exceeded its costs by approximately $3.03 million. With the elimination of the FCA, the MPUC recognized that there would no longer be a mechanism for the return of that sum to customers. The MPUC allowed the Company to retain that overcollection and ordered that the amount be amortized over a period of three years. That retention and amortization positively affected 1995 earnings and will continue to have a short-term positive impact on the Company's earnings in 1996 and 1997. Also as requested by the Company, the MPUC established the recovery and accounting procedures to be followed in the event of a buyout of one or more of the Company's contracts for the purchase of power from high-cost non-utility independent power producers. Under those procedures, the Company was authorized to defer the 1995 buyback costs of the two high-cost power purchase contracts discussed below and record them as regulatory assets, to be amortized and collected over a ten-year period, beginning July 1, 1995. The cost of these contracts was being recovered through the FCA, and now with the elimination of the FCA, the revenue formerly allocated by the FCA to the recovery of the cost of these contracts became available for general corporate purposes, including the necessity to purchase replacement power and to service the financing of the buyback cost. Finally, the MPUC acknowledged with approval the Company's commitment to attempt to cap existing electric rates at current levels for an extended period and expressed a desire to formalize the details of such a commitment by agreement of the affected parties. To date, the Company has not succeeded in reaching agreement with other interested parties, and the Commission has scheduled a formal hearing process to address the issue in 1996. BUYBACK OF PURCHASED POWER CONTRACTS-The Company has been attempting to alleviate the adverse impact of the high-cost contracts for the purchase of power from independent, non-utility generators with whom the Company had been obliged to contract in the 1980s. One method for doing so has been to pay a fixed sum in return for terminating a contract. The first such transaction was accomplished in 1993, and in 1995 the Company succeeded in accomplishing two more. The 1995 transactions involved a "buyback" of the contracts for the purchase of power from two biomass-fueled generating plants in West Enfield and Jonesboro, Maine, which are identical plants under common ownership. The buyback cost was approximately $170 million, including transaction costs. The cost of the buyback was financed entirely by new debt instruments, thereby significantly increasing the Company's indebtedness. The major components of the new debt are as follows: 1. The Company has entered into a Loan Agreement with the Finance Authority of Maine (FAME), a body corporate and politic and public instrumentality of the State of Maine. Pursuant to authorizing legislation in Maine, FAME issued $126 million of notes through a private placement, the repayment of which is the responsibility of the Company under the terms of the Loan Agreement. Of that amount, approximately $105 million was made available to the Company to finance a portion of the buyback and approximately $21 million was set aside in a capital reserve fund. The notes bear interest at an annual rate of 7.03%, mature on July 1, 2005 and are subject to a schedule of annual principal payments beginning on July 1, 1998. The amount held in the capital reserve fund will be used to pay the final installments of principal and interest due in 2005. The assets in the capital reserve fund are invested in a guaranteed annuity contract, earning interest at a rate of 6.51%, and the interest earnings are utilized to offset the semiannual interest payments on the FAME notes. In order to secure the FAME notes, the Company executed a new General and Refunding Mortgage Indenture and Deed of Trust establishing a lien on the Company's property junior to the lien under the Company's First Mortgage Bonds Indenture. After the issuance of $115 million in Firs Mortgage Bonds to a group of bank lenders discussed below, the Company may not issue any additional First Mortgage Bonds in the future except to the trustee under the new General and Refunding Mortgage. The Company issued bonds to FAME under the new mortgage in the amount of $126 million. 2. The Company entered into a Credit Agreement with a group of seven banks consisting of a revolving credit facility in the initial amount of $55 million and a term loan in the amount of $60 million. The revolving credit facility replaced the Company's short-term credit facilities that existed prior to the closing, and also provided for the issuance of a letter of credit required to support $4.2 million of the Company's Pollution Control Revenue Bonds. The revolving credit facility has a term of five years. The term loan, used to finance a portion of the buyback cost, also has a five-year term and requires annual principal payments of $12 million beginning June 30, 1996. The Credit Agreement has various options for interest charges under variable rate formulas, but the Company was required to enter into a transaction to cap or fix the rate of interest on the term loan within 120 days of the execution of the Agreement. In August 1995, the Company entered into agreements with three banks to cap the interest rate at 7.25%, with the cost to cap the interest rate amounting to $624,000. These costs are being amortized over the life of the term loan. The Credit Agreement is secured by $115 million of non-interest bearing First Mortgage Bonds. In addition to the buyback costs incurred to date, the Company is committed under certain conditions to reimburse the towns of Enfield and Jonesboro for lost property tax revenues in an amount not expected to exceed $1.4 million over a two-year period. The debt instruments executed in connection with this financing contain a number of covenants and restrictions that the Company believes to be usual and customary for such a transaction, including limitations on the aggregate amount of indebtedness that the Company may incur and restrictions on the payment of dividends. The Company believes that the accomplishment of this transaction will provide substantial benefits for its customers, and should enhance the Company's prospects for improved earnings sooner than if the buyback did not occur. REDUCTION OF DIVIDEND ON COMMON STOCK In June of 1995, the quarterly dividend on common stock was reduced by $.15 from the prior quarterly level of $.33 per share that the Company had been paying since early 1992, to $.18 per share. This resulted in a reduction in the indicated annual rate from $1.32 to $.72. The Company had announced in March 1995 that a reduction in the common dividend was likely to occur during the year. The reduction had been occasioned by the continuing pressure on earnings and the necessity to avoid further rate increases as the Company, along with the rest of the electric utility industry, adjusts to a more competitive business environment. As a result of the financial impact of the Maine Yankee outage and the cost of an early retirement and severance program implemented in 1995, both discussed below, the Company's common dividends were not covered by earnings in 1995, even after taking into consideration the dividend reduction. MAINE YANKEE-The Company, through its equity investment totalling approximately $5.0 million at December 31, 1995, owns 7% of the common stock of Maine Yankee Atomic Power Company (Maine Yankee), which owns and operates an 880 megawatt nuclear generating plant in Wiscasset, Maine, and is entitled under a cost-based power contract to an approximately equal percentage of the plant's output. The Maine Yankee plant, like other pressurized water reactors, experienced degradation of its steam generator tubes, principally in the form of circumferential cracking, which, until early 1995, was believed to be limited to a relatively small number of tubes. During the refueling and maintenance shutdown that commenced in February 1995, Maine Yankee detected through new inspection methods increased degradation of the plant's steam generator tubes to the extent that approximately 60% of the plant's 17,000 steam generator tubes appeared to have defects to some degree. Because of the large number of affected tubes, the remedy of plugging the degraded tubes to take them out of service was no longer a viable option. Following a detailed analysis of the safety, technical and financial considerations associated with the degraded steam generator tubes, Maine Yankee elected to repair the tubes by inserting and welding short reinforcing sleeves of an improved material in substantially all of the plant's steam generator tubes. Similar repairs have been completed at other nuclear plants in the United States and abroad, but not on the scale of the Maine Yankee project. With Westinghouse Electric Corporation as the general contractor, the sleeving project started in early June of 1995, after approval of the Westinghouse sleeving process by the Nuclear Regulatory Commission (NRC), and was essentially completed in early December. The repairs were estimated to cost $40 million, but Maine Yankee now estimates the project was completed for approximately $27 million. The Company charged to operations its share of the repair costs in 1995. During 1995, the Company incurred substantial costs for replacement power, and as explained above, since the FCA was eliminated at the beginning of 1995, the replacement power costs had a material impact in reducing earnings in 1995. After Maine Yankee went off-line, the Company incurred non-reconcilable incremental replacement power costs of approximately $8.6 million for the year. Combined with the Company's share of the repair cost, the Maine Yankee outage adversely impacted the Company's earnings in 1995 by $.86 per common share, after taxes. On December 4, 1995, when the resleeving project was substantially complete, Maine Yankee received 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 former employee of Yankee Atomic Electric Company (Yankee), an affiliate of 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 NRC in seeking 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's containment peak postulated accident pressure, both under certain assumed accident conditions. The analyses were used in support of license amendments that authorized an increased rating of the plant from a level equal to approximately 90% of the maximum electrical capability of the plant to its current 100% rated level. In response to technical issues raised by the allegations, the NRC initiated a special technical review of the safety analysis performed by Yankee relating to Maine Yankee's license amendment applications for the power uprates. At the same time, Maine Yankee and Yankee initiated intensive internal investigations of the allegations and provided responsive information and documentation to the NRC. On December 18, 1995, a public meeting was held at the NRC to discuss the findings resulting from the NRC's technical review. At the meeting the NRC informed Maine Yankee that it had concerns regarding the adequacy of a proprietary computer code used in ECCS safety analyses supporting Maine Yankee's last two applications for license amendments that authorized power uprates to levels above 90% of its current maximum capacity. At the meeting the NRC also indicated that operation of the plant at a level up to 90% could be acceptable if operations were based on methods previously found acceptable by the NRC staff and not on the computer code that is currently under review by the NRC, and further informed Maine Yankee of the terms and conditions under which Maine Yankee could resume power operation of the plant. Subsequently, the NRC informed Maine Yankee that the allegations made in the anonymous letter would be the subject of investigations by the NRC's Office of Investigations and the Office of the Inspector General. 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 Confirmatory Order) confirming the conclusions of the NRC from the public meeting and follow-up communications with Maine Yankee. The Confirmatory Order limited the power output of the Maine Yankee plant to approximately 90% of its rated maximum until the NRC shall have 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 Confirmatory Order further required that prior to operating the plant at any level, Maine Yankee should submit under oath specified information relating to operating the plant at up to the 90% level and descriptions of measures taken to assure compliance with the limitations on operating level and containment pressure. With respect to subsequently returning the plant to its 100% operating level, the Confirmatory Order required Maine Yankee to submit a plant-specific analysis meeting the NRC's requirements for ECCS operation under specified conditions at plant power levels up to 100% of its maximum rated capability. The Confirmatory Order also required an integrated containment analysis demonstrating that the maximum calculated containment pressure under certain postulated accident conditions does not exceed the design-basis pressure of the plant's containment. In addition, the Confirmatory Order required Maine Yankee to submit a schedule for providing the requested analyses and related information to the NRC. As of this writing, the Maine Yankee plant is operating at the 90% level, and Maine Yankee is continuing its efforts to meet the NRC's requirements to return to the 100% operating level. The Company cannot predict when the plant will gain the authority to return to the 100% operating level or when it will achieve this level once authority is granted. As a result of Maine Yankee's operating limitation, the Company will incur replacement power costs of between $70,000 and $100,000 per month as long as that limitation is in effect. Finally, the Company cannot predict the results of the internal and external investigations of the allegations brought to Maine Yankee's attention on December 4, 1995. Maine Yankee has stated, however, that it intends to pursue its internal investigation diligently and cooperate with the governmental investigations, and that it believes that after it develops information requested by the NRC for operation of the plant at full capacity it will be able to operate the plant at that level while meeting all applicable NRC safety requirements. ACQUISITION OF WHOLESALE CUSTOMER-On October 26, 1995, the Company acquired the assets and service territory of its largest full requirements wholesale customer for a purchase price of approximately $2.4 million. The customer served approximately 1,800 customers. COST REDUCTIONS - In the third quarter of 1995 the Company implemented an early retirement and severance program, resulting in approximately another 10% reduction in the Company's work force, and amounting to a onetime, non-cash charge to operations of $2.3 million or $.32 per common share (net of income taxes). Although this program will result in future cost savings, accounting guidelines required that the Company record the expense of the downsizing program in the period in which it was implemented. OTHER - The Company occasionally makes forward-looking statements such as forecasts and projections of expected future performance or statements of the Company's plans and objectives. These forward-looking statements may be contained in filings with the Securities and Exchange Commission, press releases and oral statements. Actual results could potentially differ materially from these statements. Therefore, no assurances can be given that such forward-looking statements and estimates will be achieved. LIQUIDITY, CAPITAL REQUIREMENTS, AND CAPITAL RESOURCES The Consolidated Statements of Cash Flows reflect events for the years ended December 1995, 1994 and 1993 as they affect the Company's liquidity. Net cash used in operations was $164.5 million in 1995. In 1995 the Company expended approximately $197.7 million related to the purchased power contracts buyback ($168.7 million) and related financing costs ($29.0 million). These financing costs included debt issuance cots ($2.8 million), funding of the capital reserve fund ($21.2 million), collateral deposited with a third party trustee, pledged on the Company's letter of credit associated with its Pollution Control Revenue Bonds ($4.4 million), and the interest rate cap arrangements entered into as required by the financings ($.6 million). Upon establishing of a new letter of credit, the $4.4 million in collateral was released to the Company in the third quarter of 1995. The receipt of these funds is reflected in the Consolidated Statements of Cash Flows in Other, net and was utilized to pay down outstanding short-term debt. Exclusive of the costs to buy back the purchased power contracts, which were entirely debt financed (see below), cash flows provided by operations were $33.2 million in 1995 as compared to $29.3 million in 1994. With the elimination of these purchased power contracts, the Company incurred no purchased energy costs related to the contracts in the period from July 1995 through December 1995, while in the comparable 1994 period, the Company incurred approximately $13.5 million in costs under these contracts. Another component of the increase in cash flows from operations is the reduction in payroll costs in 1995 as compared to 1994. Due principally to the reduction in the work force through the early retirement plans in 1995 and 1994, labor costs were approximately $1.4 million lower in 1995 as compared to 1994. Also enhancing cash flows from operations in 1995 as compared to 1994 were Company contributions to the defined benefit pension plans. In 1994 the Company contributed approximately $1.2 million to the non-bargaining unit plan, while in 1995, with the merging of the bargaining unit and non-bargaining unit plans, no contributions were required. This was due to the overfunded status of the bargaining unit plan prior to the merger. These enhancements to cash flows from operations were offset to some extent by the additional costs incurred in 1995 to replace the Company's share of Maine Yankee output, amounting to approximately $8.6 million, as well as $1.9 million in costs associated with the resleeving project. Over the last three years, capital expenditures have been $19.5 million in 1995, $21.5 million in 1994 and $33.6 million in 1993 (including overhead costs allocated to the capital program). In 1995, approximately $2.0 million of the capital expenditures was related to the Company's power production facilities, $7.8 million was for its distribution system, $4.8 million was for its transmission system, and $3.0 related to implementing new customer and geographic information systems, with the remainder related to other general property and equipment, and costs associated with the licensing of new and the relicensing of existing hydroelectric projects. As previously discussed, the Company acquired the assets of its largest full-requirements wholesale customer in October 1995 at a cost of approximately $2.4 million. The 1993 expenditures included about $11.4 million for two major rehabilitation projects for the Company's hydroelectric system. The Company expects its capital expenditures to total about $33 million (excluding capitalized overheads) over the next three years, although it may be necessary to adjust the budget for capital expenditures on a year-to-year basis. As previously discussed, the Company reduced its quarterly dividend by $.15 from the prior quarterly level of $.33 per share, effective for the quarter ending June 30, 1995. This reduction has improved cash flows through a $2.2 million reduction in common dividend payments in 1995 as compared to 1994. Capital needs in 1995 were met through internally generated funds, and due to the 1995 buyback of purchased power contracts significantly reducing the Company's cash needs for purchased power payments, the Company expects to similarly meet all of its capital needs for the foreseeable future. Accordingly, the Company does not currently have plans to issue any new debt or equity securities. As previously discussed, the purchased power contract buyback in 1995 was financed through the issuance of $126 million of FAME Revenue Notes and $60 million of Medium Term Notes, thereby significantly increasing the Company's indebtedness. Additional short-term borrowings were also made in 1995 under the Company's revolving credit agreement to finance this transaction. In 1995 the Company raised approximately $1.2 million through the issuance of 116,414 shares of common stock under the Dividend Reinvestment Plan. Also during 1995, the Company made approximately $2.1 million of required and optional sinking fund payments on its 12.25% First Mortgage Bonds. In 1994 the Company raised approximately $14.1 million with the issuance and sale of 867,500 shares of common stock and approximately $1.3 million through the issue of 92,249 shares under the Dividend Reinvestment Plan. Also during 1994 the Company made $2.6 million in required and optional sinking fund payments on its 12.25% First Mortgage Bonds. External capital in 1993 was provided by the issuance of 745,000 shares of common stock with proceeds of $14.8 million, the issuance of 59,439 common shares raising approximately $1.2 million under the Dividend Reinvestment Plan, and the issuance of $15 million 7.3% First Mortgage Bonds. The bonds contain no provisions for sinking fund payments. The Company has $110.7 million of First Mortgage Bond and other long-term debt sinking fund requirements and maturities in the period 1996-2000. The Company also has $1.5 million of required annual sinking fund payments on its mandatory redeemable preferred stock. In addition to requiring funds for capital improvements, the Company has from time to time required funds to finance "regulatory assets" (such as the cost of buying out of the high-cost contracts). Accounting rules applicable to regulated utilities allow the establishment of regulatory assets for costs accumulated for certain items other than the usual and customary capital assets, and allow the deferral of the income statement impact of those costs if they are expected to be recovered in future rates. As of December 31, 1995, the Company has net regulatory assets of approximately $250.7 million. The effects of competition could ultimately cause the operations of the Company, or a portion thereof, to cease meeting the criteria for application of the accounting rules for regulatory assets. If this were to occur, accounting standards of enterprises in general would apply and unamortized balances of regulatory assets would be charged to operations in the year in which those criteria were no longer applicable. RESULTS OF OPERATIONS Earnings per common share were $.36, $.84 and $.63, and the earned return on average common equity was 2.5%, 5.5% and 4.0% for the years ended 1995, 1994 and 1993, respectively. In the three years presented, reported earnings reflected significant onetime charges. Negatively impacting earnings in 1995 were the previously discussed shutdown of Maine Yankee and the cost of the early retirement and severance program in 1995. The Company charged approximately $2.8 million before taxes ($.24 per common share after taxes) in 1994 to operations to reflect the cost of an early retirement program. The 1994 and 1995 work force reduction programs are now providing savings in the form of reduced labor costs. In 1993 the Company established a reserve for the full amount of licensing costs spent through 1993 on the Basin Mills and Veazie hydroelectric projects. This reserve, which amounted to $8.7 million before taxes, resulted in a $.95 reduction in earnings per common share after taxes for the year ended December 31, 1993. The Company's total revenues and consequently its earnings are influenced to a large extent by the regulation of retail rates by the MPUC. Under Maine law, the Company had historically collected revenue from its customers separately through "base rates" and through a "fuel cost adjustment" (the FCA see the discussion above of the Company's Alternative Marketing Plan approved by the MPUC). Base rates were established from time to time in order to permit the Company an opportunity to recover its costs of providing electric service that are not included in the FCA, and to recover the investment, and earn a reasonable return thereon, in plant and equipment to provide that service. The FCA had also included the cost of the contracts with the non-utility independent power producers. The FCA was a positive or negative adjustment that was reconciled after the fact to reflect changes in the cost of fuel for generation and certain costs of purchased power. With the AMP order issued by the MPUC on February 14, 1995, the FCA was eliminated effective January 1, 1995. On February 17, 1994, the MPUC issued an order allowing the Company, effective March 1, 1994, to increase its base rates by $11.1 million. This represented a 15.9% increase in base rates and an increase in average overall rates of 7.9%. More than half of the rate increase was designed to allow recovery of the costs associated with the 1993 buyout of the Beaver Wood purchased power contract, and it was offset to a large extent by a reduction in the FCA attributable directly to the buyout. The MPUC order provided an authorized return on common equity of 10.6%. However, the Company failed to earn that authorized return in 1994 primarily because the MPUC order was based upon an overly optimistic projection of energy sales, the Company made certain pricing concessions to its customers as discussed above, and because of the onetime charge for the early retirement program discussed above. The Company did not earn its authorized return in 1995, as well, due to the reasons noted for 1994, the expense associated with the 1995 early retirement and severance program, and the impact of the Maine Yankee shutdown. Electric operating revenue increased by $10.8 million in 1995 compared to 1994, or 6.2% reflecting, in part, the rate increase that took effect in March 1994 and a 4.4% increase in kilowatt-hour (KWH) sales. The majority of the KWH sales increase is related to special contracts which the Company entered into with three large industrial customers. KWH sales to these customers increased 21% in 1995, resulting in associated revenues increasing $2.7 million or 1.4%. One of the special contracts has a revenue sharing arrangement which resulted in additional revenue from that customer of $3.5 million in 1995. Revenue from off-system sales increased by $1.4 million as well. Absent the special contracts, KWH sales from other customer classes were flat in l995 as compared to 1994. The $3.9 million, or 2.2% decrease in electric operating revenues in 1994 as compared to 1993 was due to the previously discussed pricing concessions made to two large industrial customers in 1994, a $2.6 million decrease in off-system sales and the 12.9% fuel rate decrease effective November 1, 1993. These decreases were offset to some extent by the 15.9% base rate increase effective March 1, 1994. KWH sales for 1994, excluding special contract customers, were flat as compared to 1993. In conjunction with the FCA, the MPUC authorized the Company to use a deferred fuel accounting methodology under which fuel revenue essentially matched fuel expense, which was in effect for each of 1993 and 1994. With the elimination of the FCA effective January 1, 1995, deferred fuel accounting has been eliminated. This change has required the Company to record, as expense, actual fuel costs incurred. The deferred fuel revenue balance at December 31, 1995 appears on the Consolidated Balance Sheets as a liability of $2.0 million, which is being amortized over a three-year period beginning January 1, 1995 as a reduction in fuel expense and is a benefit to earnings. The significant decrease in fuel expense in 1995 is related to the buyback of the high cost non-utility generator purchased power contracts on June 30, 1995, which eliminated the purchased energy costs in the last two quarters of 1995 for this non-utility generator (1994 comparable expense was $13.5 million). Also in 1995, certain purchased power capacity costs are no longer reclassified to fuel for generation, due to the elimination of the FCA. In 1994, $2.2 million of such costs were reflected in fuel for generation. These decreases were offset to some extent by the elimination of the FCA in the first quarter of 1995, as well as $8.6 million in incremental costs in 1995 for Maine Yankee replacement power. The increase in purchased power capacity costs in 1995 was due to the Company recording its share of the costs of the Maine Yankee resleeving project, amounting to approximately $1.9 million. Also in 1995, as previously discussed, certain purchased power capacity costs are no longer reclassified to fuel for generation. These increases were offset to some extent because, with Maine Yankee off-line in 1995, there was no need to amortize Maine Yankee's refueling cost. The Company amortizes these costs over the period of operation following the refueling activity, which in this case began in January 1996. Other operation & maintenance (O&M) expense increased by $2.2 million in 1995 as compared to 1994 due principally to the previously discussed impact of the early retirement and severance program in 1995, as well as a $1.7 million increase in bad debt expense in 1995. These increases were offset by the $2.8 million charged to operations in 1994 related to the early retirement program, as well as a $1.4 million decrease in O&M payroll expense in 1995 as compared to 1994. The reduction in payroll expense was principally a function of fewer employees accomplished through the work force reduction programs in 1994 and 1995, as well as greater levels of capital labor in 1995. The $4.0 million increase in other O&M expense in 1994 as compared to 1993 was principally due to the previously mentioned early retirement program in 1994. Other major increases in 1994 expenses included a $1.4 million increase in medical costs (including the full amount of expense for postretirement benefits in accordance with Financial Accounting Standards Board Statement No. 106 "Employers' Accounting for Postretirement Benefits Other Than Pensions" which was implemented on January 1, 1993 and included in rates beginning March 1, 1994) and $745,000 in amortization of certain deferred costs for which recovery was allowed in the most recent base rate order. The Company's expenses over the period 1993-1995 have been significantly affected by amortizations authorized by the MPUC and charged annually against earnings. The MPUC has specifically authorized the inclusion of these expenses in the Company's base rates. Absent such regulatory authority, the expenses that gave rise to the amortizations would have been charged to operations when incurred. Instead, the recognition of such expenses has been deferred, and appear on the Consolidated Balance Sheets as assets on the strength of the regulatory authority to amortize them and collect from customers (thus the term "regulatory assets"). Although there are a number of such authorized amortizations, the major ones are the allowable recovery of the Company's investment in the Seabrook nuclear power units (which it sold in 1986) and the costs associated with the 1993 and 1995 purchased power contract terminations. The Company's recoverable investment in Seabrook Unit 1 is being amortized at a rate of $1.7 million per year beginning in 1986 for a period of 30 years. Effective March 1, 1994, as authorized in the base rate order from the MPUC, the Company began amortizing the deferred costs associated with the Beaver Wood contract termination at a rate of $3.9 million annually over a nine-year period. Under the AMP, the approximately $170 million of costs associated with the 1995 purchased power contract buyback have been deferred and recorded as a regulatory asset, to be amortized and collected over a ten year period, beginning July 1, 1995, at an annual expense of $16.9 million. AFDC decreased in 1995 as compared to 1994, and for 1994 relative to 1993 primarily because the Company ceased accruing carrying costs associated with the Beaver Wood purchased power contract termination when recovery was authorized by the MPUC on March 1, 1994, as well as lower levels of construction activity in each of 1995 and 1994. Also impacting the decrease in AFDC in 1994 as compared to 1993 was the cessation at the end of 1993 of accruing AFDC on costs related to the Basin Mills project. The increase in long-term debt interest expense in 1995 as compared to 1994 was a result of incurring $186 million in debt in association with financing the cost of the purchased power contract buyback on June 30, 1995. Other interest expense increased in 1995 and 1994 as a result of higher levels of borrowings under the revolving credit facility, as well as an increase in short-term interest rates in each of 1995 and 1994 compared to the prior years. Increased borrowing activity in 1995 was partly a function of additional funds necessary for the cost of the purchased power contract buyback. CONTINGENCIES In 1992, the Company received notice from the Maine Department of Environmental Protection (MDEP) that it was investigating the cleanup of several sites in Maine that were used in the past for the disposal of waste oil and other hazardous substances, and that the Company, as a generator of waste oil that was disposed at those sites, may be liable for certain cleanup costs. The Company learned in October 1995 that the United States Environmental Protection Agency placed one of the sites on the National Priorities List under the Comprehensive Environmental Response, Compensation, and Liability Act and will pursue potentially responsible parties. With respect to this site, the Company is one of a number of waste generators under investigation, and it is too early in the process to speculate on the extent of the Company's potential liability. As to the only other site which has been listed by the MDEP as an Uncontrolled Hazardous Substance Site, the Company was informed that it is considered a de minimis generator. NEW ACCOUNTING STANDARDS In March 1995 the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 121 (FAS 121), "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of", effective for financial statements for fiscal years beginning after December 15, 1995. FAS 121 establishes accounting standards for the impairment of long-lived assets, certain identifiable intangibles, and goodwill related to those assets to be held and used and for long-lived assets and certain intangibles to be disposed of. It establishes guidance for recognizing and measuring impairment losses and requires that the carrying amount of impaired assets be reduced to fair value. In addition, FAS 121 requires that all regulatory assets, which must have a high probability of recovery to be initially established, continue to meet that high probability standard or be written-off. However, if written-off, a regulatory asset can be restored if it regains a high probability of recovery. Management is currently evaluating the financial impact of this accounting standard, but as long as the cost of the Company's long-lived assets and intangibles continues being recovered through its electric rates, as is currently the case, the effect of FAS 121 on the Company's results of operations and financial position is not expected to be significant. Management cannot predict the outcome of the possibility of further competition and deregulation of the electric utility industry, or the impact thereof on the application of this accounting standard. ITEM 8 - ------ FINANCIAL STATEMENTS & SUPPLEMENTARY DATA - ----------------------------------------- BANGOR HYDRO-ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF INCOME For the Years Ended December 31, 1995 1994 1993 ELECTRIC OPERATING REVENUE (Note 1): $184,913,771 $ 174,097,860 $ 177,971,770 ----------------------------------------- OPERATING EXPENSES: Fuel for generation (Note 1) $ 82,301,027 $ 90,339,056 $ 102,670,217 Purchased power capacity (Notes 1 and 6) 16,382,964 13,793,383 13,716,436 Other operation and maintenance (Notes 1, 5 and 9) 35,711,185 33,497,912 29,474,327 Depreciation and amortization (Note 1) 6,522,019 5,395,045 4,747,491 Amortization of Seabrook Nuclear Project (Note 7) 1,699,050 1,699,050 1,699,050 Amortization of contract buyouts (Note 6) 12,322,570 3,238,630 - Taxes - Local property and other 4,884,565 5,189,324 4,102,097 Income (Note 2) 1,421,674 3,613,598 4,762,945 ----------------------------------------- $161,245,054 $ 156,765,998 $ 161,172,563 ----------------------------------------- OPERATING INCOME $ 23,668,717 $ 17,331,862 $ 16,799,207 OTHER INCOME AND (DEDUCTIONS): Provision for Basin Mills (Note 6) - - (8,695,539) Income tax benefits related to provision for Basin Mills (Note 6) - - 3,137,895 Allowance for equity funds used during construction (Note 1) 561,898 1,256,307 2,464,934 Other, net of applicable income taxes (Notes 1 and 2) 197,924 51,850 435,316 ----------------------------------------- INCOME BEFORE INTEREST EXPENSE $ 24,428,539 $ 18,640,019 $ 14,141,813 ----------------------------------------- INTEREST EXPENSE: Long-term debt (Note 4) $ 17,596,586 $ 10,767,934 $ 10,438,828 Other (Note 4) 3,201,030 1,754,391 1,164,795 Allowance for borrowed funds used during construction (Note 1) (705,552) (1,339,379) (2,798,241) ----------------------------------------- $ 20,092,064 $ 11,182,946 $ 8,805,382 ----------------------------------------- NET INCOME $ 4,336,475 $ 7,457,073 $ 5,336,431 DIVIDENDS ON PREFERRED STOCK (Note 3) 1,701,960 1,652,432 1,645,663 ----------------------------------------- EARNINGS APPLICABLE TO COMMON STOCK $ 2,634,515 $ 5,804,641 $ 3,690,768 ========================================= EARNINGS PER COMMON SHARE, based on the weighted average number of shares outstanding of 7,264,360 in 1995, 6,947,746 in 1994 and 5,862,411 in 1993 $ 0.36 0.84 0.63 ========================================= DIVIDENDS DECLARED PER COMMON SHARE $ 0.87 1.32 1.32 ========================================= The accompanying notes are an integral part of these consolidated financial statements. BANGOR HYDRO-ELECTRIC COMPANY CONSOLIDATED BALANCE SHEETS December 31, 1995 1994 ASSETS INVESTMENT IN UTILITY PLANT: Electric plant in service, at original cost (Notes 4 and 6) $300,374,078 $ 274,829,540 Less - Accumulated depreciation and amortization (Notes 1 and 6) 81,933,769 75,666,792 --------------------------- $218,440,309 $ 199,162,748 Construction work in progress (Note 1) 18,151,265 23,928,702 --------------------------- $236,591,574 $ 223,091,450 Investments in corporate joint ventures (Notes 1 and 6) - Maine Yankee Atomic Power Company $ 5,013,781 $ 4,753,548 Maine Electric Power Company, Inc. 124,900 124,900 --------------------------- $241,730,255 $ 227,969,898 --------------------------- OTHER INVESTMENTS, principally at cost (Note 6) $ 4,184,626 $ 3,481,703 --------------------------- FUNDS HELD BY TRUSTEE at cost (Notes 4 and 10) $ 21,191,940 - --------------------------- CURRENT ASSETS: Cash and cash equivalents (Note 1 and 10) $ 1,424,266 $ 1,956,159 Accounts receivable, net of reserve ($1,450,000 in 1995 and $730,000 in 1994) 18,226,453 19,129,910 Unbilled revenue receivable (Note 1) 8,821,440 8,611,479 Inventories, at average cost: Materials and supplies 3,028,911 2,992,496 Fuel oil 105,871 435,001 Prepaid expenses 1,737,507 1,680,753 Deferred Maine Yankee refueling costs (Note 12) 2,418,658 235,544 Current deferred income taxes (Note 2) - 1,094,355 --------------------------- Total current assets $ 35,763,106 $ 36,135,697 --------------------------- DEFERRED CHARGES: Investment in Seabrook Nuclear Project, net of accumulated amortization of $25,076,046 in 1995 and $23,376,996 in 1994 (Notes 7 and 12) $ 33,766,029 $ 35,465,079 Costs to terminate purchased power contracts, net of accumulated amortization of $15,561,200 in 1995 and $3,238,630 in 1994. (Notes 6 and 12) 192,140,252 36,738,549 Deferred regulatory assets (Notes 2, 5 and 12) 30,328,451 33,536,787 Prepaid pension costs (Note 5) - 2,082,047 Demand-side management costs (Note 12) 1,945,944 2,684,107 Other (Note 12) 5,025,887 3,156,178 --------------------------- Total deferred charges $263,206,563 $ 113,662,747 --------------------------- Total Assets $566,076,490 $ 381,250,045 =========================== The accompanying notes are an integral part of these consolidated financial statements. BANGOR HYDRO-ELECTRIC COMPANY CONSOLIDATED BALANCE SHEET December 31, 1995 1994 STOCKHOLDERS' INVESTMENT AND LIABILITIES CAPITALIZATION (see accompanying statement): Common stock investment (Note 3) $103,191,680 $105,657,684 Preferred stock (Note 3) 4,734,000 4,734,000 Preferred stock subject to mandatory redemption, exclusive of sinking fund requirements (Notes 3 and 10) 12,070,003 13,740,491 Long-term debt, net of current portion (Notes 4, 10 and 15) 288,074,966 116,367,155 --------------------------- Total capitalization $408,070,649 $240,499,330 --------------------------- CURRENT LIABILITIES: Notes payable - banks (Note 4) $ 35,000,000 $ 27,000,000 --------------------------- Other current liabilities - Current portion of long-term debt and sinking fund requirements on preferred stock (Notes 3, 4 and 10) $ 16,938,615 $ 2,961,253 Accounts payable 10,526,642 14,668,512 Dividends payable 1,709,209 2,766,026 Accrued interest 4,907,820 3,650,195 Deferred fuel revenue (Notes 1 and 12) 2,016,798 3,025,194 Customers' deposits 348,676 287,699 Current income taxes payable - 965,614 --------------------------- Total other current liabilities $ 36,447,760 $ 28,324,493 --------------------------- Total current liabilities $ 71,447,760 $ 55,324,493 --------------------------- COMMITMENTS AND CONTINGENCIES (Notes 6, 8 and 15) DEFERRED CREDITS AND RESERVES (Note 2): Deferred income taxes - Seabrook $ 17,546,355 $ 18,434,070 Other accumulated deferred income taxes 50,775,034 50,083,738 Deferred regulatory liability (Note 12) 8,567,904 9,221,892 Unamortized investment tax credits 2,354,052 2,415,245 Accrued pension (Note 5) 626,249 - Other (Note 5) 6,688,487 5,271,277 --------------------------- Total deferred credits and reserves $ 86,558,081 $ 85,426,222 --------------------------- Total Stockholders' Investment and Liabilities $566,076,490 $381,250,045 =========================== The accompanying notes are an integral part of these consolidated financial statements. BANGOR HYDRO-ELECTRIC COMPANY STATEMENTS OF CAPITALIZATION December 31, 1995 1994 Common Stock Investment (Notes 1 and 3): Common stock, par value $5 per share- Authorized -- 10,000,000 shares Outstanding -- 7,301,557 shares in 1995 and 7,185,143 shares in 1994 $ 36,507,785 $ 35,925,715 Amounts paid in excess of par value 56,610,548 55,974,218 Retained earnings 10,073,347 13,757,751 - -------------------------------------------------------------------------------- Total Common Stock $103,191,680 $ 105,657,684 - -------------------------------------------------------------------------------- Preferred Stock, Non-participating, cumulative, par value $100 per share, authorized 600,000 shares (Notes 3 and 10): Not redeemable or redeemable solely at the option of the issuer- 7%, Noncallable, 25,000 shares authorized and outstanding $ 2,500,000 $ 2,500,000 4-1/4%, Callable at $100, 4,840 shares authorized and outstanding 484,000 484,000 4%, Series A, Callable at $110, 17,500 shares authorized and outstanding 1,750,000 1,750,000 - -------------------------------------------------------------------------------- $ 4,734,000 $ 4,734,000 - -------------------------------------------------------------------------------- Subject to mandatory redemption requirements- 8.76%, Callable at $105.01% if called on or prior to December 27,1996, 150,000 shares authorized and outstanding $ 15,362,881 $ 15,240,491 Less-Sinking fund requirements 3,292,878 1,500,000 - -------------------------------------------------------------------------------- $ 12,070,003 $ 13,740,491 - -------------------------------------------------------------------------------- LONG-TERM DEBT (Notes 4, 10 and 15): First Mortgage Bonds- 6.75% Series due 1998 $ 2,500,000 $ 2,500,000 10.25% Series due 2019 15,000,000 15,000,000 10.25% Series due 2020 30,000,000 30,000,000 8.98% Series due 2022 20,000,000 20,000,000 7.38% Series due 2002 20,000,000 20,000,000 7.30% Series due 2003 15,000,000 15,000,000 12.25% Series due 2001 9,020,703 11,128,408 - -------------------------------------------------------------------------------- $111,520,703 $ 113,628,408 Less-Sinking fund requirements 1,645,737 1,461,253 - -------------------------------------------------------------------------------- $109,874,966 $ 112,167,155 - -------------------------------------------------------------------------------- Variable rate demand pollution control revenue bonds Series 1983 due 2009 $ 4,200,000 $ 4,200,000 - -------------------------------------------------------------------------------- Other Long-Term Debt- Finance Authority of Maine - Taxable Electric Rate Stabilization Revenue Notes, 7.03% Series 1995A, due 2005 $126,000,000 $ - - -------------------------------------------------------------------------------- Medium Term Notes, Variable interest rate- LIBOR plus 2%, due 2000 $ 60,000,000 $ - Less: Current portion of long-term debt 12,000,000 - - -------------------------------------------------------------------------------- $ 48,000,000 $ - - -------------------------------------------------------------------------------- Total long-term debt $288,074,966 $ 116,367,155 - -------------------------------------------------------------------------------- Total Capitalization $408,070,649 $ 240,499,330 ================================================================================ The accompanying notes are an integral part of these consolidated financial statements. Bangor Hydro-Electric Company CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ending December 31, 1995 1994 1993 Cash Flows From Operations: Net Income $ 4,336,475 $ 7,457,073 $ 5,336,431 Adjustments to reconcile net income to net cash (used in)provided by operations: Costs to terminate purchased power contracts (Notes 6 and 11) (197,717,853) --- (23,711,733) Depreciation and amortization (including debt issuance costs) (Note 1) 6,887,653 5,611,320 4,967,988 Amortization of Seabrook Nuclear Project (Note 7) 1,699,050 1,699,050 1,699,050 Amortization of costs to terminate purchased power contracts (Note 6) 12,322,570 3,238,630 --- Base rate case amortizations included in operation and maintenance 1,074,867 992,871 247,986 Payment received related to terminated purchased power contract (Note 6) 1,000,000 1,000,000 --- Cost of early retirement and involuntary severance plans 3,835,303 2,738,376 --- Allowance for equity funds used during construction (Note 1) (561,898) (1,256,307) (2,464,934) Deferred income tax provision (Note 2) 1,791,082 2,250,851 2,258,762 Deferred investment tax credits, net (Note 2) (61,193) 143,695 (178,176) Provision for Basin Mills Project (Note 6) --- --- 8,695,539 Changes in assets and liabilities: Deferred fuel revenue and purchased power (Note 1) (3,191,510) 7,153,733 9,039,409 Accounts receivable, net and unbilled revenue 693,496 (1,816,459) 3,023,611 Accounts payable (4,141,870) (1,292,388) (1,081,505) Accrued interest 1,257,625 (55,332) 1,109,433 Current and deferred income taxes 625,059 (517,084) 2,566,443 Accrued postretirement benefit costs 612,446 591,123 --- Other current assets and liabilities, net 296,938 36,945 139,055 Other, net (Note 4) 4,719,636 1,285,426 (1,981,721) - -------------------------------------------------------------------------------------------------------- Net Cash (Used In) Provided By Operations $ (164,522,124) $ 29,261,523 $ 9,665,638 - -------------------------------------------------------------------------------------------------------- Cash Flows From Investing: Construction expenditures $ (19,459,606) $(21,482,132) $(33,611,031) Allowance for borrowed funds used during construction (Note 1) (705,552) (1,339,379) (2,798,241) - -------------------------------------------------------------------------------------------------------- Net Cash Used In Investing $ (20,165,158)$ $(22,821,511) $(36,409,272) - -------------------------------------------------------------------------------------------------------- Cash Flows From Financing: Dividends on preferred stock $ (1,579,570) $ (1,579,570) $ (1,579,570) Dividends on common stock (7,375,736) (9,116,617) (7,678,229) Payments on long-term debt (2,107,705) (2,594,896) (15,148,118) Issuances: Common stock (Note 3) Public offering (867,500 shares in 1994 and 745,000 shares in 1993) --- 14,083,863 14,803,150 Dividend reinvestment plan (116,414 shares in 1995, 92,249 shares in 1994 and 59,439 shares in 1993) 1,218,400 1,336,211 1,245,519 Long-term debt (Note 4) 186,000,000 --- 15,000,000 Short-term debt, net (Note 4) 8,000,000 (9,000,000) 21,000,000 - -------------------------------------------------------------------------------------------------------- Net Cash Provided By (Used In) Financing $ 184,155,389 $ (6,871,009) $ 27,642,752 - -------------------------------------------------------------------------------------------------------- Net Change in Cash and Cash Equivalents $ (531,893) $ (430,997) $ 899,118 Cash and Cash Equivalents - Beginning of Year 1,956,159 2,387,156 1,488,038 - -------------------------------------------------------------------------------------------------------- Cash and Cash Equivalents - End of Year $ 1,424,266 $ 1,956,159 $ 2,387,156 - -------------------------------------------------------------------------------------------------------- Supplemental Cash Flow Information: Cash Paid During The Year For- Interest (Net of Amount Capitalized) $ 17,906,908 $ 9,677,372 $ 4,549,462 Income Taxes 345,834 2,226,290 --- ======================================================================================================== The accompanying notes are an integral part of these consolidated financial statements.
BANGOR HYDRO-ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF RETAINED EARNINGS For the Years Ended December 31, 1995 1994 1993 BALANCE AT BEGINNING OF YEAR $13,757,751 $17,386,444 $21,639,369 ADD - Net income 4,336,475 7,457,073 5,336,431 ------------------------------------ $18,094,226 $24,843,517 $26,975,800 ------------------------------------ DEDUCT: Cash dividends declared on - Preferred stock $ 1,579,570 $ 1,579,570 $ 1,579,570 Common stock - $.87 per share in 1995, and $1.32 per share in 1994 and 1993 6,318,919 9,433,334 7,943,693 Other (Note 3) 122,390 72,862 66,093 ------------------------------------ $ 8,020,879 $11,085,766 $ 9,589,356 ------------------------------------ BALANCE AT END OF YEAR $10,073,347 $13,757,751 $17,386,444 ==================================== The accompanying notes are an integral part of these consolidated financial statements. BANGOR HYDR0-ELECTRIC COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES NATURE OF OPERATIONS - The Company is a public utility engaged in the generation, purchase, transmission, distribution and sale of electric energy, with a service area of approximately 5,275 square miles having a population of approximately 191,000 people. The Company serves approximately 103,000 customers in portions of the Maine counties of Penobscot, Hancock, Washington, Waldo, Piscataquis, and Aroostook. 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 other matters. The Company is also subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC) as to certain matters, including licensing of its hydroelectric stations, rates for wholesale purchases and sales of energy and capacity and transmission services. The Company is a member of the New England Power Pool, and is interconnected with other New England utilities to the south and with New Brunswick Power Corporation to the north. BASIS OF CONSOLIDATION-The Consolidated Financial Statements of Bangor Hydro-Electric Company (the Company) include its wholly owned subsidiaries, Penobscot Hydro Co., Inc. (PHC), and Bangor Var Co., Inc. (BVC). The operations of PHC consist solely of a 50% interest in Bangor-Pacific Hydro Associates (Bangor-Pacific), the owner and operator of the redeveloped West Enfield hydroelectric station. PHC accounts for its investment in Bangor- Pacific under the equity method. BVC was incorporated in 1990 to own the Company's 50% interest in the Chester SVC Partnership (Chester), a partnership which owns certain facilities used in the Hydro-Quebec Phase II transmission project in which the Company is a participant. BVC accounts for its investment in Chester under the equity method. All significant intercompany balances and transactions have been eliminated. The accounts of the Company are maintained in accordance with the Uniform System of Accounts prescribed by the regulatory bodies having jurisdiction. EQUITY METHOD OF ACCOUNTING-The Company accounts for its investments in the common stock of Maine Yankee Atomic Power Company (Maine Yankee) and Maine Electric Power Company, Inc. (MEPCO) under the equity method of accounting, and records its proportionate share of the net earnings of these companies as a reduction of purchased power capacity costs. See Note 6 for additional information with respect to these ivestments. ELECTRIC OPERATING REVENUE-Electric Operating Revenue consists primarily of amounts charged for electricity delivered to customers during the period. The Company records unbilled revenue, based on estimates of electric service rendered and not billed at the end of an accounting period, in order to match revenue with related costs. DEFERRED FUEL AND PURCHASED POWER CAPACITY ACCOUNTING-Prior to January 1, 1995, the Company utilized deferred fuel accounting. Under this accounting method, retail fuel costs were expensed when recovered through rates and recognized as revenue. Retail fuel costs not yet expensed were classified on the Consolidated Balance Sheets (Balance Sheets) as deferred fuel costs. The fuel cost adjustment rate included a factor calculated to reimburse the Company or its customers, as appropriate, for the carrying cost of funds used to finance under- or over- collected fuel costs, respectively. Under the MPUC fuel cost adjustment (FCA) regulations effective through December 31, 1994, the Company was allowed to recover its fuel costs on a current basis. The fuel charge was based on the Company's projected cost of fuel for a twelve-month period. Under- or over- collections resulting from differences between estimated and actual fuel costs for a twelve-month period were included in the computation of the estimated fuel costs of the succeeding fuel adjustment period. As of January 1, 1995, the Company's collections under the FCA had exceeded its costs by approximately $3.03 million. With the elimination of the FCA, the MPUC recognized that there would no longer be a mechanism for the return of that sum to customers. The MPUC allowed the Company to retain that over- collection and ordered that the amount be amortized over a period of three years, effective January 1, 1995. DEPRECIATION OF ELECTRIC PLANT AND MAINTENANCE POLICY-Depreciation of electric plant is provided using the straight-line method at rates designed to allocate the original cost of the properties over their estimated service lives. The composite depreciation rate, expressed as a percentage of average depreciable plant in service, and considering the amortization of the over- accrued depreciation which is discussed below, was approximately 2.3% in 1995, 2.2% in 1994, and 2.1% in 1993. A study conducted in 1989 by an independent firm determined that, as a group, the actual lives of the Company's property, plant and equipment were longer than the lives represented by the depreciation rates that the Company had been using to compute its depreciation expense for accounting purposes. In addition, the study also determined that the reserve for depreciation was over-accumulated. The agreement on base rates with the MPUC which became effective on October 1, 1990, contained a provision to amortize the remaining balance of the over-accumulated reserve for depreciation account ($11.4 million at October 1, 1990) over a six-year period and adopted the longer depreciable lives as determined by the aforementioned study. In 1995 the Company, in accordance with the results of an updated depreciation study, adopted shorter depreciable lives, resulting in an increase in the composite depreciation rate from 3.0% to 3.2%. The Company follows the practice of charging to maintenance the cost of repairs, replacements and renewals of minor items considered to be less than a unit of property. Costs of additions, replacements and renewals of items considered to be units of property are charged to the utility plant accounts, and any items retired are emoved from such accounts. The original costs of units of property retired and removal costs, less salvage, are charged to the reserve for depreciation. Depreciation, local property taxes and other taxes not based on income, which were charged to operating expenses, are stated separately in the Consolidated Statements of Income. Rents, advertising and research and development expenses are not significant. No royalty expenses were incurred. Maintenance expense was $5.9 million in 1995, $6.2 million in 1994 and $6.5 million in 1993. EQUITY RESERVE FOR LICENSED HYDRO PROJECTS-The FERC requires that a reserve be maintained equal to one-half of the earnings in excess of a prescribed rate of return on the Company's investment in licensed hydro property, beginning with the twenty-first year of the project operation under license. The required reserve for licensed hydro projects is classified in retained earnings and had a balance of $900,542 at December 31, 1995 and $584,942 at December 31, 1994. ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFDC)-In accordance with regulatory requirements of the MPUC, the Company capitalizes as AFDC financing costs related to portions of its construction work in progress, at a rate equal to its weighted cost of capital, into utility plant with offsetting credits to other income and interest. This cost is not an item of current cash income, but is recovered over the service life of plant in the form of increased revenue collected as a result of higher depreciation expense and return. In addition, carrying costs on certain regulatory assets were also capitalized in 1994 and 1993, and included in AFDC in the Consolidated Statements of Income. The average AFDC (and carrying cost) rates computed by the Company were 9.0% in 1995, 9.2% for 1994 and 10.0% in 1993. CASH AND CASH EQUIVALENTS-The Company considers all highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents. USE OF ESTIMATES-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 liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. RECLASSIFICATIONS-Certain prior year amounts have been reclassified to conform with the presentation used in the 1995 Consolidated Financial Statements. 2. INCOME TAXES The Company adopted Statement of Financial Accounting Standards No. 109 "Accounting for Income Taxes" (FAS 109) effective January 1, 1993. FAS 109 required a change in the accounting for income taxes from the deferred method to an asset and liability approach, which requires the recognition of deferred tax liabilities and assets for the future tax effects of temporary differences between the tax basis and carrying amounts of assets and liabilities. In accordance with FAS 109, the Company recorded net additional deferred income tax liabilities of approximately $21.2 million as of December 31, 1995 and $23.7 million as of December 31, 1994. These additional deferred income tax liabilities have resulted from the accrual of deferred taxes on temporary differences on which deferred taxes had not been previously accrued ($29.8 million and $32.9 million as of December 31, 1995 and 1994, respectively), offset by the effect of the 1987 change to lower income tax rates (reduced by the 1% increase in the federal income tax rate in 1993) that will be refunded to customers over time ($7.2 million and $7.8 million as of December 31, 1995 and 1994, respectively) and the establishment of deferred tax assets on unamortized investment tax cedits ($1.4 million as of December 31, 1995 and 1994, respectively). These latter amounts have been recorded as deferred regulatory liabilities at December 31, 1995 and 1994. The accrual of the additional amount of deferred tax liabilities have been offset by regulatory assets which represent the customers' future payment of these income taxes when the taxes are, in fact, expensed. As a result of this accounting, the Consolidated Statements of Income for the years ended December 31, 1995 and 1994 are not affected by the implementation of FAS 109. The rate-making practices followed by the MPUC permit the Company to recover federal and state income taxes payable currently, and to recover some, but not all, deferred taxes that would otherwise be recorded in accordance with FAS 109 in the absence of regulatory accounting. The individual components of other accumulated deferred income taxes are as follows at December 31, 1995 and 1994: 1995 1994 ----------- ----------- Deferred income tax liabilities: Costs to terminate purchased power contracts $77,126,042 13,643,442 Excess book over tax basis of electric plant in service $47,658,824 $45,841,542 Deferred FERC licensing costs 1,361,034 3,158,378 Investment in jointly-owned companies 842,624 787,908 Deferred demand-side management costs 651,672 16,677 Deferred fuel revenue and purchased power 126,293 - Prepaid pension costs - 593,290 Other 658,459 841,344 ------------ ----------- $128,424,948 $64,882,581 ------------ ----------- Less: Deferred Income Tax Assets: Net operating loss carryforwards $64,769,384 1,915,213 Deferred income taxes provided on alternative minimum tax $ 3,898,824 $ 4,463,203 Investment in Basin Mills 2,732,550 2,719,025 Unamortized investment tax credits 1,352,104 1,387,251 Postretirement benefit costs other than pensions 1,107,808 507,033 Deferred state income tax benefit 908,722 1,301,528 Accrued pension costs 812,120 - Reserve for bad debts 807,447 649,675 Deferred fuel revenue and purchased power - 1,365,750 Other 1,260,955 490,165 ------------- ------------- $ 77,649,914 $ 14,798,843 ------------- ------------- Total other accumulated deferred income taxes $50,775,034 $ 50,083,738 ============= ============= The individual components of federal and state income taxes reflected in the Consolidated Statements of Income for 1995, 1994 and 1993 are stated in the table below: Year Ended December 31, -------------------------------------- 1995 1994 1993 ------------------------------------ Current: Federal - $1,287,485 - State - - - - -------------------------------------------------------------------- - $1,287,485 - - -------------------------------------------------------------------- Deferred Short-Term: Federal - $ (797,919) $ 114,674 State - (296,436) 68,216 - -------------------------------------------------------------------- $ - $(1,094,355) $ 182,890 Deferred Long-Term: Federal-Other $2,131,643 $ 3,003,171 $ 2,512,026 State-Other 70,424 753,782 (21,507) Federal-Seabrook (339,415) (339,620) (341,917) State-Seabrook (71,570) (72,127) (72,730) - -------------------------------------------------------------------- $1,791,082 $ 3,345,206 $ 2,075,872 - -------------------------------------------------------------------- Investment Tax Credits, Net $ (61,193) $ 143,695 $ (178,176) - -------------------------------------------------------------------- Total Provision $1,729,889 $ 3,682,031 $2,080,586 Allocated to Other Income (308,215) (68,433) 2,682,359 - -------------------------------------------------------------------- Charged to Operating Expense $1,421,674 $ 3,613,598 $4,762,945 ==================================================================== The table below reconciles an income tax provision, calculated by multiplying income before federal income taxes (as reported on the Consolidated Statements of Income) by the statutory federal income tax rate to the federal income tax expense reported on the Statements of Income. The difference is represented by the temporary differences for which deferred taxes were not originally provided. 1995 1994 1993 ----------- ----------- ---------- Amount % Amount % Amount % ------------------------------------ (Dollars in Thousands) ----------------------------------- Federal income tax provision at statutory rate $2,063 34% $3,786 34% $2,522 34% Less (Plus) temporary reductions in tax expense resulting from statutory exclusions from taxable income: Dividend received deduction related to earnings of associated companies 31 1 131 1 133 2 Equity component of AFDC 191 3 427 4 496 6 Amortization of equity component of AFDC on recoverable Seabrook investment (155) (1) (155) (1) (155) (2) Other (104) (2) 8 - (24) - ------ --- ------ ---- ----- ---- Federal income tax provision before effect of temporary differences $2,100 34% $3,375 30% $2,072 28% Less (Plus) timing differences that are flowed through for ratemaking and accounting purposes: Amortization of debt component of AFDC and capitalized overheads on recoverable Seabrook investment (146) (3) (146) (1) (146) (2) Book depreciation greater than tax depreciation on assets acquired before 1971 (292) (5) (292) (3) (292) (4) State income tax liability deducted for federal income tax purposes - - 131 1 116 2 Reversal of excess deferred income taxes 101 2 35 - 34 - Amortization of investment tax credits 676 11 178 2 178 3 Other 30 0 172 1 75 1 ------- ---- ------ --- ------ --- Federal income tax provision $1,731 29% $3,297 30% $2,107 28% ======= ==== ====== ==== ====== === Under the federal income tax laws, the Company received investment tax credits on qualified property additions through 1986. Investment tax credits utilized were deferred and are being amortized over the life of the related property. In 1995 the Company recorded the utilization of approximately $615,000 of investment tax credits, as well as amortization of deferred investment tax credits of approximately $676,000. This was related to the filing of amended federal income tax returns. Investment tax credits available of about $3.5 million ($2.6 million which is attributable to PHC and $900,000 to BVC) have not been utilized or recorded and, subject to review by the Internal Revenue Service (IRS), may be used prior to their expiration, which occurs between 2001 and 2005. At December 31, 1995, the Company had, for income tax purposes, alternative minimum tax credits of approximately $3.9 million for the reduction of future tax liabilities. At December 31, 1995, the Company had, for income tax reporting purposes, approximately $4.7 million of net operating loss carryforwards that expire in 2008, as well as, in 1995, the Company generated a net operating loss carryforward for income tax reporting purposes of approximately $153 million that expire in 2010. These net operating losses were principally due to the Company deducting for income tax reporting purposes the costs of the purchased power contract terminations in 1993 and 1995, which were deferred for financial reporting purposes (see Note 6). In 1994 the Company utilized $15.6 million of tax net operating loss carryforwards and $322,000 of investment tax credits to reduce the alternative minimum tax liability for 1994. 3. COMMON AND PREFERRED STOCK COMMON STOCK-In June of 1994 the shareholders approved a proposal to increase the number of shares the Company isauthorized to issue from 7,500,000 to 10,000,000. Prior to 1992, stockholders had been able to invest their dividends and optional cash payments in common stock of the Company acquired by an independent agent in the open market through the Company's Dividend Reinvestment and Common Stock Purchase Plan (the Plan). In 1992 the Company amended the Plan to enable it to issue original shares in return for the reinvested dividends and optional cash payments. The common stock has general voting rights of one vote per twelve shares owned. PREFERRED STOCK-In June of 1994 the shareholders approved a proposal to increase the number of shares the Company is authorized to issue from 400,000 to 600,000 shares of which there are 197,340 shares outstanding. The remaining 402,660 authorized but unissued shares (plus additional shares equal in number to such presently outstanding shares as may be retired) may be issued with such preferences, restrictions or qualifications as the Board of Directors may determine. Any new shares so issued will be required to be issued with per share voting rights no greater than that of the common stock. The callable preferred stock may be called in whole or in part upon any dividend date by appropriate resolution of the Board of Directors. Except for the holders of the 8.76% issue, which does not carry general voting rights, the currently outstanding preferred stock has general voting rights of one vote per share. With regard to payment of dividends or assets available in the event of liquidation, preferred stock ranks prior to common stock. REDEEMABLE PREFERRED SHARES-On December 27, 1989, the Company issued to an institutional investor $15 million of nonvoting preferred stock carrying an annual dividend rate of 8.76%. These shares have a maturity of fifteen years with a mandatory sinking fund of $1.5 million per year starting in 1995. The agreement to issue this series of preferred stock contains a provision whereby, if the Company pays a dividend that is considered a return of capital for federal income tax purposes, the Company is required to make a payment to the stockholder in order to restore the stockholder's after-tax yield to the level it would have been had the dividend not been considered a return of capital. Since 100% of the dividends paid in 1990, 1993 and 1995, pending any review by the IRS, were to be considered a return of capital, the Company became obligated to pay this stockholder approximately $1.5 million, on a prorata basis (10% per year) in conjunction with each sinking fund payment starting in 1995. This obligation is being recognized over the remaining life of the issue through a direct charge to retained earnings, which amounted to approximately $122,000 in 1995. In connection with financing the costs of the purchased power contract buyback accomplished in June 1995 (see Note 6), the Company entered into a Loan Agreement with the Finance Authority of Maine (FAME), a body corporate and politic and public instrumentality of the State of Maine. Pursuant to authorizing legislation in Maine, FAME issued $126 million of notes through a private placement, the repayment of which is the responsibility of the Company under the terms of the Loan Agreement. Of that amount, approximately $105 million was made avalable to the Company to finance a portion of the buyback and approximately $21 million was set aside in a capital reserve fund. The notes bear interest at an annual rate of 7.03%, mature on July 1, 2005 and are subject to a schedule of annual principal payments beginning on July 1, 1998. The amount held in the capital reserve fund will be used to pay the final installments of principal and interest due in 2005. The assets in the capital reserve fund are held by a third party trustee and invested in a guaranteed annuity contract, earning interest at an annul rate of 6.51%, and the interest earnings are utilized to offset the semiannual interest payments on the Fame notes. In order to secure the FAME notes, the Company executed a new General and Refunding Mortgage Indenture and Deed of Trust establishing a lien on the Company's property junior to the lien under the Company's First Mortgage Bonds Indenture. After the issuance of $115 million in First Mortgage Bonds to a group of bank lenders discussed below, the Company may not issue any additional First Mortgage Bonds in the future except to the trustee under the new General and Refunding Mortgage. The Company issued bonds to FAME under the new mortgage in the amount of $126 million. On June 30, 1995, the Company entered into a Credit Agreement (Agreement) with a group of seven banks consisting of a revolving credit facility in the initial amount of $55 million and a term loan in the amount of $60 million. The revolving credit facility replaces the Company's short-term credit facilities that existed prior to the closing, and also provided for the issuance of a letter of credit required to support $4.2 million of the Company's Pollution Control Revenue Bonds. To secure the existing letter of credit related to the Pollution Control Revenue Bonds, until the new letter of credit could be issued, the Company deposited approximately $4.4 million of the proceeds from this financing with a third party trustee. These funds were released to the Company upon the issuance of the new letter of credit in August 1995. The receipt of these funds is reflected in Other, net in the Consolidated Statements of Cash Flows. The Agreement is secured by $115 million of non-interest bearing First Mortgage Bonds. The revolving credit facility has a term of five years and was automatically and permanently reduced by $1 million on December 31, 1995. Borrowings under the revolving credit facility will also be reduced by $2 million on June 30, 1996 and by $3 million on December 31, 1996. The term loan, used to finance a portion of the buyback cost, also has a term of five years and requires annual principal payments of $12 million beginning June 30, 1996. The Company may borrow at rates, as defined with the Agreement, based on LIBO (London Interbank Offered) rate, or the higher of the prime rate, the three month certificate of deposit rate or the federal funds rate. A risk premium based on the Company's senior debt rating is added to the base portion of the rate, which results in the combined total interest rate for borrowings underthe Agreement. A required commitment fee, based on the Company's available revolving credit commitment, is also priced according to the Company's senior debt rating. The Company was required to enter into a transaction to cap or fix the rate of interest on the term loan within 120 days of the execution of the Agreement. In August 1995, the Company entered into agreements with three banks to cap the LIBO rate at 7.25%, with the cost to cap the interest rate amounting to $624,000. These costs are being amortized over the life of the term loan. The Agreement allows the Company to incur, outside of the revolving credit facility, additional unsecured debt of $5 million, plus 50% of the aggregate amount of mandated or optional reductions to the $55 million revolving credit facility. In connection with this provision, the Company maintains a $5 million uncommitted line of credit. The debt instruments executed in connection with the purchased power buyback financing contains a number of covenants and restrictions that the Company believes to be usual and customary for such a transaction, including limitations on the aggregate amount of indebtedness the Company may incur and restrictions on the payment of dividends. Under the provisions of the first mortgage bond indenture, substantially all of the Company's plant and property has been mortgaged to secure the Company's first mortgage bonds. Sinking fund requirements and current maturities of the first mortgage bonds for the five years subsequent to December 31, 1995 aggregate $110,739,713 as follows: Sinking Fund Current Requirement Maturities Total - ----------------------------------------------------------------------------- 1996 $1,645,737 $ 12,000,000 $ 13,645,737 1997 1,853,515 12,000,000 13,853,515 1998 1,778,554 26,800,000 28,578,554 1999 1,675,205 25,100,000 26,775,205 2000 1,886,702 26,000,000 27,886,702 - ----------------------------------------------------------------------------- $8,839,713 $101,900,000 $110,739,713 ============================================================================= Certain information related to total short-term borrowings under the Credit Agreement and the lines of credit is as follows: 1995 1994 1993 - ----------------------------------------------------------------------------- Total credit available at end of period $59,500,000 $55,000,000 $55,000,000 Unused credit at end of period $24,500,000 $28,000,000 $19,000,000 Borrowings outstanding at end of period $35,000,000 $27,000,000 $36,000,000 Effective interest rate (exclusive of fees) on borrowings outstanding at end of period 8.4% 6.0% 3.5% Average daily outstanding borrowings for the period $33,573,973 $26,035,616 $22,754,205 Weighted daily average annual interest rate 7.5% 4.6% 3.7% Highest level of borrowings outstanding at any month-end during the period $47,000,000 $38,000,000 $36,000,000 ============================================================================= The average daily borrowings outstanding for the period represent the sum of daily borrowings outstanding, divided by the number of days in the period. The weighted daily average annual interest rate is determined by dividing the annual interest expense by the average daily borrowings outstanding for the period. 5. POSTRETIREMENT AND OTHER POSTEMPLOYMENT BENEFITS POSTRETIREMENT BENEFITS-The Company has noncontributory pension plans covering substantially all of its employees. On July 17, 1987, the Company created separate union and nonunion plans from an original plan. Effective January 1, 1995, the Company merged the union and nonunion plans into one plan. Benefits under the plans are generally based on the employee's years of service and compensation during the years preceding retirement. The Company's general policy is to contribute to the funds the amounts deductible for federal income tax purposes. The following tables detail the components of pension income for 1995, 1994 and 1993, the funded status of the plans, the amounts recognized in the Company's Consolidated Financial Statements and the major assumptions used to determine these amounts. There were no employer contributions to the plan in 1995. Employer contributions to the plans amounted to $1,174,019 in 1994. In 1995 and 1994 the Company implemented early retirement programs which resulted in additional pension expense of $2,548,648 and $1,608,267, respectively. The plan's assets are composed of fixed income securities, equity securities and cash equivalents. Total pension income included the following components: 1995 1994 1993 - --------------------------------------------------------------------------- Service cost-benefits earned during the period $ 813,811 $1,060,134 $1,085,419 Interest cost on projected benefit obligation 2,458,466 2,310,455 2,244,706 Actual return on plan assets (8,505,484) 377,447 (4,633,435) Total of amortized obligations and the net gain (loss) deferred 4,889,703 (3,865,833) 1,291,310 - ---------------------------------------------------------------------------- Total pension (income) $ (343,504) $ (117,797) $ (12,000) ============================================================================ 1995 1994 1993 - --------------------------------------------------------------------- Significant assumptions used were Discount rate 7.25% 8.25% 7.0% Rate of increase in future compensation levels 5.0% 5.0% 5.0% Expected long-term rate of return on plan assets 9.0% 9.0% 9.0% The following table sets forth the plans' funded status at December 31, 1995 and 1994: 1995 1994 - ----------------------------------------------------------------------- Actuarial present value of accumulated benefit obligation Vested $ 31,528,835 $ 21,668,455 Non-vested 2,877,035 2,091,333 - ----------------------------------------------------------------------- Total $ 34,405,870 $ 23,759,788 ======================================================================= Projected benefit obligation $(39,121,538) $(31,179,979) Plan assets at fair value 41,312,595 36,397,435 - ----------------------------------------------------------------------- Excess of plan assets over projected benefit obligation $ 2,191,057 $ 5,217,456 Items not yet recognized in earnings Net (asset) at transition (5,051,800) (5,984,125) Prior service cost 5,096,783 5,653,162 Unrecognized net gain from past experience and changes in assumptions (2,862,289) (2,804,446) - ----------------------------------------------------------------------- Net pension (liability) asset recognized $ (626,249) $ 2,082,047 ======================================================================= In addition to pension benefits, the Company provides certain health care and life insurance benefits to its retired employees. Substantially all of the Company's employees may become eligible for retiree benefits if they reach normal retirement age while working for the Company. The Company adopted Statement of Financial Accounting Standards No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" (FAS 106) as of January 1, 1993. This standard required the accrual of postretirement benefits, including medical and life insurance coverage, during the years an employee provides services to the Company. Prior to 1993, the cost of health care benefits were expensed as benefits were paid. The MPUC in 1993 issued a final accounting rule in connection with FAS 106 which adopted this pronouncement for ratemaking purposes and provided the Company with the accounting and regulatory framework required to defer the excess of the net periodic postretirement benefit cost recognized under FAS 106 over the pay-as-you-go amount in 1993 through February 28, 1994, and to include such excess as a regulatory asset pending inclusion in the new base rates, effective March 1, 1994. This regulatory asset, which amounted to $705,283 at February 28, 1994, is being recovered, beginning March 1, 1994, over a ten-year period. The Company, also in accordance with the final accounting ruling, is amortizing the unrecognized transition obligation of $10,023,200 over a 20-year period. In 1995 and 1994 the Company implemented early retirement programs which resulted in $909,418 and $750,000, respectively, of expense related to additional medical and life insurance benefits provided to the early retirees. In 1994 the Company established an irrevocable external Voluntary Employee Benefit Association Trust Fund ("VEBA") to fund the payment of postretirement medical and life insurance benefits. Company contributions to the VEBA, which commenced in July 1994, amounted to $1,215,554 in 1995 and $755,000 in 1994. The plan's assets are composed of United States Treasury money market funds. The actuarially determined net periodic postretirement benefit cost for 1995, 1994 and 1993 and the major assumptions used to determine these amounts are shown in the following tables: 1995 1994 1993 - ----------------------------------------------------------------------------- Service cost of benefits earned $ 378,400 $ 379,400 $ 359,600 Interest cost on accumulated postretirement benefit obligation 948,000 724,000 683,200 Actual return on plan assets (23,300) (7,800) - Amortization of unrecognized transition obligation 501,200 501,200 Other deferrals, net 23,699 (1,800) - Early retirement plan benefits 909,418 750,000 - - ----------------------------------------------------------------------------- Net periodic postretirement benefit cost $2,737,417 $2,345,000 $1,544,000 ============================================================================= 1995 1994 1993 - ------------------------------------------------------------------------ Significant assumptions used were- Discount rate 7.25% 8.25% 7.0% Health care cost trend rate, employees less than age 65- Near-term 8.5% 9.0% 12.4% Long-term 4.5% 4.5% 6.0% Health care cost trend rate, employees greater than age 65- Near-term 6.8% 7.0% 9.7% Long-term 4.5% 4.5% 5.8% Rate of return on plan assets 5.0% 2.0% N/A - --------------------------------------------------------------------- The following table sets forth the benefit plan's funded status at December 31, 1995 and 1994: 1995 1994 - ----------------------------------------------------------------------------- Accumulated postretirement benefit obligation: Retirees $ 7,749,800 $ 7,746,800 Fully eligible active plan participants 1,374,400 446,400 Other active participants 3,248,300 3,020,900 - ----------------------------------------------------------------------------- 12,372,500 $11,214,100 Fair value of plan assets (606,800) (409,500) Unrecognized net transition obligation (8,519,600) (9,020,800) Unrecognized gain 625,986 566,423 - ----------------------------------------------------------------------------- Accrued postretirement benefit cost (included in Other Reserves) $ 3,872,086 $ 2,350,223 ============================================================================= If the health care cost trend rate was increased one percent, the accumulated postretirement benefit obligation as of January 1, 1995 would have increased by 12.3%. The effect of such change on the aggregate of service and interest cost for 1995 would be an increase of 15.6%. The estimates of the Company's accrued pension and postretirement benefit costs involve the utilization of significant assumptions. Any change in these assumptions could impact the liabilities in the near term. POSTEMPLOYMENT BENEFITS-Effective January 1, 1994 the Company adopted Statement of Financial Accounting Standards No. 112 "Employers' Accounting for Postemployment Benefits" (FAS 112). The effect of FAS 112 on the Company's consolidated results of operations, cash flows and financial position was not material. 6. JOINTLY OWNED FACILITIES AND POWER SUPPLY COMMITMENTS MAINE YANKEE-The Company, through its equity investment totalling approximately $5.0 million at December 31, 1995, owns 7% of the common stock of Maine Yankee, which owns and operates an 880 megawatt nuclear generating plant in Wiscasset, Maine, and is entitled under a cost-based power contract to an approximately equal percentage of the plant's output. The Maine Yankee plant, like other pressurized water reactors, experienced degradation of its steam generator tubes, principally in the form of circumferential cracking, which, until early 1995, was believed to be limited to a relatively small number of tubes. During the refueling and maintenance shutdown that commenced in February 1995, Maine Yankee detected through new inspection methods increased degradation of the plant's steam generator tubes to the extent that approximately 60% of the plant's 17,000 steam generator tubes appeared to have defects to some degree. Because of the large number of affected tubes, the remedy of plugging the degraded tubes to take them out of service was no longer a viable option. Following a detailed analysis of the safety, technical and financial considerations associated with the degraded steam generator tubes, Maine Yankee elected to repair the tubes by inserting and welding short reinforcing sleeves of an improved material in substantially all of the Plant's steam generator tubes. Similar repairs have been completed at other nuclear plants in the United States and abroad, but not on the scale of the Maine Yankee project. With Westinghouse Electric Corporation as the general contractor, the sleeving project started in early June of 1995, after approval of the Westinghouse sleeving process by the Nuclear Regulatory Commission (NRC), and was essentially completed in early December. The repairs were estimated to cost $40 million, but Maine Yankee now estimates the project will be completed for approximately $27 million. The Company has charged to operations its share of the repair costs in 1995. During 1995, the Company incurred substantial costs for replacement power, and as explained above, since the FCA was eliminated at the beginning of 1995, the replacement power costs had a material impact in reducing earnings in 1995. After Maine Yankee went off-line, the Company incurred nonreconcilable replacement power costs of approximately $8.6 million for the year. Combined with the Company's share of the repair cost, the Maine Yankee outage adversely impacted the Company's earnings in 1995 by $.86 per common share, after taxes. On December 4, 1995, when the resleeving project was substantially complete, Maine Yankee received a copy of a letter, from an organization with a history of opposin nuclear power development, to a State of Maine nuclear safety official based on documentation from an anonymous former employee of Yankee Atomic Electric Company (Yankee), an affiliate of 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 NRC in seeking 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's containment peak postulated accident pressure, both under certain assumed accident conditions. The analyses were used in support of license amendments that authorized an increased rating of the plant from a level equal to approximately 90% of the maximum electrical capability of the plant to its current 100% rated level. In response to technical issues raised by the allegations, the NRC initiated a special technical review of the safety analysis performed by Yankee relating to Maine Yankee's license amendment applications for the power up rates. At the same time, Maine Yankee and Yankee initiated intensive internal investigations of the allegations and provided responsive information and documentation to the NRC. On December 18, 1995, a public meeting was held at the NRC to discuss the findings resulting from the NRC's technical review. At the meeting the NRC informed Maine Yankee that it had concerns regarding the adequacy of a proprietary computer code used in ECCS safety analyses supporting Maine Yankee's last two applications for license amendments that authorized power up rates to levels above 90% of its current maximum capacity. At the meeting the NRC also indicated that operation of the plant at a level up to 90% could be acceptable if operations were based on methods previously found acceptable by the NRC staff and not on the computer code that is currently under review by the NRC, and further informed Maine Yankee of the terms and conditions under which Maine Yankee could resume power operation of the plant. Subsequently, the NRC informed Maine Yankee that the allegations made in the anonymous letter would be the subject of investigations by the NRC's Office of Investigations and the Office of the Inspector General. 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 Confirmatory Order) confirming the conclusions of the NRC from the public meeting and follow-up communications with Maine Yankee. The Confirmatory Order limited the power output of the Maine Yankee plant to approximately 90% of its rated maximum until the NRC shall have 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 Confirmatory Orer further required that prior to operating the plant at any level, Maine Yankee should submit under oath specified information relating to operating the plant at up to the 90% level and descriptions of measures taken to assure compliance with the limitations on operating level and containment pressure. With respect to subsequently returning the plant to its 100% operating level, the Confirmatory Order required Maine Yankee to submit a plant-specific analysis meeting the NRC's requirements for ECCS operation under specified conditions at plant power levels up to 100% of its maximum rated capability. The Confirmatory Order also required an integrated containment analysis demonstrating that the maximum calculated containment pressure under certain postulated accident conditions does not exceed the design-basis pressure of the plant's containment. In addition, the Confirmatory Order required Maine Yankee to submit a schedule for providing the requested analyses and related information to the NRC. As of this writing, the Maine Yankee plant is operating at the 90% level. The Company cannot predict when Maine Yankee will gain the authority to return to the 100% operating level or when it will achieve this level once authority is granted. As a result of Maine Yankee's operating limitation, the Company will incur replacement power costs of between $70,000 and $100,000 per month as long as that limitation is in effect. Finally, the Company cannot predict the results of the internal and external investigations of the allegations brought to Maine Yankee's attention on December 4, 1995, or whether any party will seek an NRC hearing or any appeal with respect to the Order. Maine Yankee has stated, however, that it intends to pursue its internal investigation diligently and cooperate with the governmental investigations, and that it believes that after it develops information requested by the NRC for operation of the plant at full capacity it will be able to operate the plant at that level while meeting all applicable NRC safety requirements. The Company is obligated to pay its pro rata share of Maine Yankee's operating expenses, fuel costs, capital costs and decommissioning costs. Estimated costs of decommissioning the Maine Yankee plant assuming dismantlement and removal is $317 million (in 1993 dollars) of which the Company's share is approximately $22.2 million. The estimated cost of decommissioning is subject to change due to evolving technology and the possibility of new legal requirements. Accumulated decommissioning funds at December 31, 1995 were $142.1 million of which the Company's share was approximately $9.9 million. MEPCO-The Company owns 14.2% of the common stock of MEPCO. MEPCO owns and operates electric transmission facilities from Wiscasset, Maine, to the Maine-New Brunswick border. Several New England utilities, including the Company and MEPCO's other stockholders (two other Maine utilities), are parties to a transmission support agreement pursuant to which such utilities have agreed to pay MEPCO's costs, based on theirrelative system peaks, if MEPCO's revenues from transmission services are not sufficient to meet its expenses. Information relating to the operations and financial position of Maine Yankee and MEPCO appears below: Maine Yankee MEPCO - ----------------------------------------------------------------------------- (Dollar in Thousands) - ----------------------------------------------------------------------------- 1995 1994 1993 1995 1994 1993 ------ ------ ------ ------ ------ ------ Operations: As reported by investee- Operating Revenue $205,977 $173,857 $193,102 $49,699 $24,746 $12,809 - ----------------------------------------------------------------------------- Depreciation $ 32,722 $ 30,823 $ 25,458 $ 1,383 $ 1,383 $ 1,395 Interest and Prefer- red Dividends 17,332 14,583 14,407 96 106 124 Other expenses, net 148,866 121,437 145,861 48,115 23,152 11,185 - ----------------------------------------------------------------------------- Operating expenses $198,920 $166,843 $185,726 $49,594 $24,641 $12,704 - ----------------------------------------------------------------------------- Earnings Applicable to Common Stock $ 7,057 $ 7,014 $ 7,376 $ 105 $ 105 $ 105 ============================================================================= Amounts Reported by the Company- Purchased power costs $14,299 $11,771 $ 11,265 $ - $ - $ - Equity in net income (498) (480) (542) (15) (15) (15) - ----------------------------------------------------------------------------- Net purchased power expense $ 13,801 $11,291 $10,723 $ (15)$ (15)$ (15) ============================================================================= Financial Position: As reported by investee- Plant in service $404,499 $401,092 $396,133 $23,135 $23,099 $23,123 Accumulated deprec- iation (208,537)(192,293)(175,996)(21,777)(20,463)(19,174) Other assets 384,996 341,111 314,680 4,561 3,927 2,414 - ----------------------------------------------------------------------------- Total assets $580,958 $549,910 $534,817 $ 5,919 $ 6,563 $ 6,363 Less- Preferred stock 18,600 19,200 19,800 - - - Long-term debt 109,999 118,666 115,333 870 1,730 2,590 Other liabilities and deferred credits 381,158 344,550 332,030 4,171 3,955 2,895 - ----------------------------------------------------------------------------- Net assets $ 71,201 $ 67,494 $ 67,654 $ 878 $ 878 $ 878 ============================================================================= Company's reported equity- Equity in net assets $ 4,984 $ 4,725 $ 4,736 $ 125 $ 125 $ 125 Adjust Company's estimate to actual 30 29 20 - - - - ----------------------------------------------------------------------------- Equity in net assets as reported $ 5,014 $ 4,754 $ 4,756 $ 125 $ 125 $ 125 ============================================================================= Wyman 4-The Company owns 8.33% (50 MW) of the oil-fired 600 MW Wyman Unit No. 4 in Yarmouth, Maine. The Company's proportionate share of the direct expenses of this unit is included in the corresponding operating expenses in the Consolidated Statements of Income. Included in the Company's utility plant are the following amounts with respect to this unit: 1995 1994 1993 - ------------------------------------------------------------------------ Electric plant in service 16,876,963 16,771,430 16,767,909 Accumulated depreciation (8,459,911) (7,996,737) (7,539,591) - ------------------------------------------------------------------------ $ 8,417,052 $8,774,693 $9,228,318 ======================================================================== NEPOOL/HYDRO-QUEBEC PROJECT - The Company is a 1.6% participant in the NEPOOL/Hydro-Quebec Phase 1 project (Phase 1), a 690 MW DC intertie between the New England utilities and Hydro-Quebec constructed by a subsidiary of another New England utility at a cost of about $140 million. The participants receive their respective share of savings from energy transactions with Hydro-Quebec, and are obliged to pay for their respective shares of the costs of ownership and operation whether or not any savings are realized. The Company is also a 1.5% participant in the NEPOOL/Hydro-Quebec Phase 2 project (Phase 2), which involves an increase to the capacity of the Phase 1 intertie to 2,000 MW. As in the Phase 1 project, the Company receives a share of the anticipated energy cost savings derived from purchases from Hydro- Quebec and capacity benefits provided by the intertie and is required to pay its share of the costs of ownership and operation whether or not any savings are obtained. In 1990, the Company formed Bangor Var Co., Inc. whose sole function is to be a 50% general partner in Chester, a partnership which owns a static var compensator (SVC), which is electrical equipment that supports the Phase 2 transmission line. A wholly-owned subsidiary of Central Maine Power Company owns the other 50% interest in Chester. Chester has financed the acquisition and construction of the SVC through the issuance of $33 million in principal amount of 10.48% senior notes due 2020, and up to $3.25 million principal amount of additional notes due 2020 (collectively, the SVC Notes). The holders of the SVC Notes are without recourse against the partners or their parent companies and may only look to Chester and to the collateral for payment. The New England utilities which participate in Phase 2 have agreed under a FERC approved contract to bear the cost of Chester, on a cost of service basis, which includes a return on and of all capital costs. Information relating to the operations and financial position of Chester appears at the top of the following page. Bangor Pacific Chester - -------------------------------------------------------------------------- (Dollar in Thousands) - -------------------------------------------------------------------------- 1995 1994 1993 1995 1994 1993 ----- ------ ------ ------ ------ ------- Operations: As reported by investee- Operating Revenue $7,277 $6,880 $7,370 $5,016 $5,173 $5,057 - --------------------------------------------------------------------------- Depreciation $ 862 $ 855 $ 856 $1,075 $1,075 $ 995 Interest Expense 3,657 3,791 3,909 3,114 3,227 3,201 Other expenses, net 707 1,134 1,037 827 871 861 - --------------------------------------------------------------------------- Operating expenses $5,226 $5,780 $5,802 $5,016 $5,173 $5,057 - --------------------------------------------------------------------------- Net Income $2,051 $1,100 $1,568 $ - $ - $ - =========================================================================== Company's reported equity in net income $1,026 $ 550 $ 784 $ - $ - $ - =========================================================================== Financial Position: As reported by investee- Plant in service $44,035 $43,977 $43,894 $31,993 $31,991 $31,991 Accumulated depreciation (6,427) (5,572) (4,717) (5,296) (4,221) (3,146) Other assets 3,399 2,978 3,696 3,351 3,555 3,632 - --------------------------------------------------------------------------- Total assets $41,007 $41,383 $42,873 $30,048 $31,325 $32,477 Less- Long-term debt 32,600 34,500 36,300 28,204 29,387 30,643 Other liabilities 2,255 2,241 2,231 1,844 1,938 1,834 - ---------------------------------------------------------------------------- Net assets $ 6,152 $ 4,642 $ 4,342 $ - $ - $ - ============================================================================ Company's reported equity in net assets $ 3,076 $ 2,321 $ 2,171 $ - $ - $ - ============================================================================ SMALL POWER PRODUCTION FACILITIES-As of the end of 1995, the Company had contracts with seven independent, non-utility power producers known as "small power production facilities." The West Enfield Project, described below, is one such facility. There are five other relatively small hydroelectric facilities, and a 20 MW facility fueled by municipal solid waste. The cost of power from the small power production facilities is more than the Company would incur from other sources if it were not obligated under these contracts, and, in the case of the solid waste plant, substantially more. The prices were negotiated at a time when oil prices wre much higher than at present, and when forecasts for the costs of the Company's long-term power supply were higher than current forecasts. In the Company's 1987 rate proceeding, the MPUC investigated the events surrounding the contract negotiations but reached no conclusion about the Company's prudence in entering into these contracts. The Company has been attempting to alleviate the adverse impact of high-cost contracts with small power production facilities. One method for doing so has been to pay a fixed sum in return for terminating the contract. The first such transaction was accomplished in 1993, and in 1995 the Company succeeded in accomplishing two more. The 1995 transactions involved a "buyback" of the contracts for the purchase of power from two biomass-fueled generating plants in West Enfield and Jonesboro, Maine, which are identical plants under common ownership. The buyback cost was approximately $170 million, including transaction costs. Under the Company's Alternative Marketing Plan (AMP), the buyback costs have been deferred and recorded as a regulatory asset, to be amortized and collected over a ten-year period, beginning July 1, 1995. The cost of the buyback was financed entirely by new debt instruments, thereby significantly increasing the Company's indebtedness. See Note 4 for discussion of these financings. In addition to the buyback costs incurred to date, the Company is committed under certain conditions to reimburse the towns of Enfield and Jonesboro for lost property tax revenues in an amount not expected to exceed $1.4 million over a two-year period. The Company believes that the accomplishment of this transaction will provide substantial long-term benefits for its customers, and should enhance the Company's prospects for improved earnings sooner than if the buyback did not occur. In the 1993 transaction, the Company negotiated an agreement to cancel its long-term purchased power agreement with one of the biomass plants, the Beaver Wood Joint Venture (Beaver Wood), in June 1993. In connection with the cancellation the Company paid Beaver Wood $24 million in cash and issued a new series of 12.25% First Mortgage Bonds due July 15, 2001 to the holders of Beaver Wood's debt in the amount of $14.3 million in substitution for Beaver Wood's previously outstanding 12.25% Secured Notes. Also, in connection with the cancellation agreement, a reconstituted Beaver Wood partnership paid the Company $1 million at the time of settling the transaction and has agreed to pay the Company $1 million annually for the next six years in return for retaining the ownership and the option of operating the plant. The payments are secured by a mortgage on the property of the Beaver Wood facility. The Company believes this contract buyout transaction will result in significant savings to its customers compared to the continuation of payments under the purchased power contract. In May 1993 the Company received an accounting order from the MPUC related to this purchased power contract buyout. The order stipulated that the Company may seek recovery of the costs associated with the buyout in a future base rate case, and could also record carrying costs on the deferred balance. Consequently, a regulatory asset of $40.3 million had been recorded as of December 31, 1993. Effective with the implementation of new base rates on March 1, 1994, the Company began recovering over a nine-year period the deferred balance, net of the additional $6 million anticipated from Beaver Wood. In each of 1994 and 1995 the Company received its $1 million payment. The Company also has a 30-year contract with the municipal solid waste facility, a 20 MW waste-to-energy plant in the Company's service territory in Orrington, completed in 1988. The Company has contracted to resell a portion of the capacity for fifteen years from this facility to another utility. The cost to the Company of the power delivered by this facility (net of revenues from the foregoing resale) is projected to be $15 million annually. WEST ENFIELD PROJECT-In 1986, the Company entered into a joint venture with a development subsidiary of Pacific Lighting Corporation for the purpose of financing and constructing the redevelopment of an old 3.8 MW hydroelectric plant which the Company owned on the Penobscot River in Enfield and Howland, Maine, into a 13 MW facility for the purpose of operating the facility once it was completed. Commercial operation of the redeveloped project began in April 1988. A wholly-owned corporate subsidiary, Penobscot Hydro Co., Inc. (PHC) was formed to own the Company's 50% interest in the joint venture, Bangor-Pacific. Bangor-Pacific financed the $45 million estimated cost of the redevelopment through the issuance in a privately placed transaction of $40 million of fixed rate term notes and a commitment for up to $5 million of floating rate notes. The notes are secured by a mortgage on the project and a security interest in a 50-year purchased power contract, and the revenues expected thereunder, between the Company and Bangor-Pacific. Except as described below, the holders of the notes issued by Bangor-Pacific are without recourse to the joint venture partners or their parent companies. In the event Bangor-Pacific fails to pay when due amounts payable pursuant to the loan agreement, each partner has agreed to make capital contributions to Bangor-Pacific in an amount equal to 50% of such amounts due and payable, but not exceeding an amount equal to distributions from Bangor-Pacific received by such partner in the preceding twelve-month period. The Company is obliged to provide funds necessary to support the foregoing limited financial commitment to the project undertaken by PHC as the partner. Under the purchased power contract, if the project operates as anticipated, payments by the Company to Bangor-Pacific are estimated to be about $7.5 million annually (without consideration of any distributions by the joint venture to the partners). It is possible that the Company would be required to make payments under the contract regardless of whether any power is delivered, in an amount of approximately $4 million per year. However, the Company has the right to terminate the contract if the failure to deliver power continues for a period of 12 consecutive months. Information relating to the operations and financial position of Bangor- Pacific appears on page 44. BASIN MILLS AND VEAZIE PROJECTS- As a result of increased uncertainty about the recoverability of amounts invested through 1993 in licensing activities for proposed additional hydroelectric facilities, the Company established a reserve against those investments in the amount of $8.7 million as of December 31, 1993. Since 1993 the Company has charged to non-operating expense all amounts related to these licensing activities. The projects for which the reserve was established are a proposed 38 megawatt generating facility located at the so-called Basin Mills site on the Penobscot River in Orono and Bradley, Maine and an 8 megawatt addition to the Company's existing dam and power station on the Penobscot River in Veazie and Eddington, Maine. The projects would require a total investment of $140 million. The Company has been pursuing the permitting of these facilities since the early 1980's. 7. RECOVERY OF SEABROOK INVESTMENT AND SALE OF SEABROOK INTEREST The Company was a participant in the Seabrook nuclear project in Seabrook, New Hampshire. On December 31, 1984, the Company had almost $87 million invested in Seabrook, but because the uncertainties arising out of the Seabrook Project were having an adverse impact on the Company's financial condition, an agreement for the sale of Seabrook was reached in mid-1985 and was finally consummated in November 1986. During 1985, a comprehensive agreement was negotiated among the Company, the MPUC staff, and the Maine Public Advocate addressing the recovery through rates of the Company's investment in Seabrook (the Seabrook Stipulation). This negotiated agreement was approved by the MPUC in late 1985. Although the implementation of the Seabrook Stipulation significantly improved the Company's financial condition, substantial write-offs were required as a result of the determination that a portion of the Company's investment in Seabrook would not be recovered. In addition to the disallowance of certain Seabrook costs, the Seabrook Stipulation also provided for the recovery through customer rates of 70% of the Company's year-end 1984 investment in Seabrook Unit 1 over 30 years, and 60% of the Company's investment in Unit 2 over seven years, with base rate treatment on the unamortized balances. As of December 31, 1992, the Company's investment in Seabrook Unit 2 was fully amortized. 8. CONTINGENCIES ENVIRONMENTAL MATTERS-In 1992, the Company received notice from the Maine Department of Environmental Protection (MDEP) that it was investigating the cleanup of several sites in Maine that were used in the past for the disposal of waste oil and other hazardous substances, and that the Company, as a generator of waste oil that was disposed at those sites, may be liable for certain cleanup costs. The Company learned in October 1995 that the United States Environmental Protection Agency placed one of the sites on the National Priorities List under the Comprehensive Environmental Response, Compensation, and Liability Act will pursue potentially responsible parties. With respect to this site, the Company is one of a number of waste generators under investigation, and it is too early in the process to speculate on the extent of the Company's potential liability. As to the only other site wich has been listed by the MDEP as an Uncontrolled Hazardous Substance Site, the Company was informed that it is considered a de minimis generator. 9. UNAUDITED QUARTERLY FINANCIAL DATA Unaudited quarterly financial data pertaining to the results of operations are shown below: QUARTER ENDED ------------------------------------------------ MAR 31 JUNE 30 SEPT 30 DEC 31 ------------------------------------------------ (DOLLARS IN THOUSANDS EXCEPT PER SHARE AMOUNTS) ------------------------------------------------ 1995 - ---- Electric Operating Revenue $48,263 $43,694 $46,025 $46,931 Operating Income 6,004 1,438 7,538 8,688* Net Income (Loss) 3,293 (1,696) 828 1,911* Earnings (Loss) Per Share of Common Stock $ .40 $ (.29) $ .05 $ .20* ======================================================================= 1994 - ---- Electric Operating Revenue $46,375 $39,664 $42,575 $45,484 Operating Income 3,037 4,550 5,589 4,157 Net Income 1,095 2,008 3,073 1,282 Earnings Per Share of Common Stock $ .11 $ .22 $ .37 $ .12 ======================================================================= 1993 - ---- Electric Operating Revenue $49,679 $40,548 $43,476 $44,269 Operating Income 4,779 4,486 4,396 3,168 Net Income (Loss) 2,908 2,766 3,244 (3,582)** Earnings (Loss) Per Share of Common Stock $ .46 $ .42 $ .46 $(.64)** ======================================================================= *Includes $498,000 of amortization of investment tax credits or $.07 per common share. **Includes the provision for Basin Mills of $5.6 million after-tax or $.95 per common share. 10. FAIR VALUE OF FINANCIAL INSTRUMENTS The following methods and assumptions were used to estimate the fair value at December 31, 1995 of each class of financial instrument for which it is practical to estimate the value: Cash and cash equivalents: the carrying amount of $1,424,266 approximates fair value. The fair values of other financial instruments at December 31, 1995 based upon similar issuances of comparable companies are as follows: In Thousands - -------------------------------------------------------------------------- Carrying Fair Amount Value ------------------------ Funds held by trustee guaranteed annuity contract $ 21,192 $ 22,739 Mandatory redeemable cumulative preferred stock 15,000 13,860 First Mortgage Bonds 111,521 109,051 Pollution Control Revenue Bonds 4,200 4,200 FAME Revenue Notes 126,000 131,477 Medium Term Notes 60,000 60,000 - -------------------------------------------------------------------------- 11. SIGNIFICANT NON-CASH ACTIVITY In connection with the termination of the purchased power agreement in 1993 with the Beaver Wood Joint Venture, the Company issued $14.3 million of First Mortgage Bonds in substitution for Beaver Wood's previously outstanding secured notes which is not reflected in the Consolidated Statements of Cash Flows. 12. REGULATORY AND LONG-LIVED ASSETS Accounting rules applicable to regulated utilities allow the establishment of regulatory assets for costs accumulated for certain items other than the usual and customary capital assets, and allow the deferral of the income statement impact of those costs if they are expected to be recovered in future rates. As of December 31, 1995, the Company has regulatory assets, net of regulatory liabilities, of approximately $250.7 million. The effects of competition could ultimately cause the operations of the Company, or a portion thereof, to cease meeting the criteria for application of the accounting rules for regulatory assets. If this were to occur, accounting standards of enterprises in general would apply and unamortized balances of regulatory assets would be charged to operations in the year in which those criteria were no longer applicable. In March 1995 the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 121 (FAS 121), "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of", effective for financial statements for fiscal years beginning after December 15, 1995. FAS 121 establishes accounting standards for the impairment of long-lived assets, certain identifiable intangibles, and goodwill related to those assets to be held and used and for long-lived assets and certain intangibles to be disposed of. It establishes guidance for recognizing and measuring impairment losses and reuires that the carrying amount of impaired assets be reduced to fair value. Management is currently evaluating the financial impact of this accounting standard, but as long as the cost of the Company's long-lived assets and intangibles continue being recovered through its electric rates, as is currently the case, the effect of FAS 121 on the Company's results of operations and financial position is not expected to be significant. Management cannot predict the outcome of the possibility of further competition and deregulation of the electric utility industry, or the application of this accounting standards. 13. ALTERNATIVE MARKETING PLAN On February 14, 1995 the MPUC issued an order approving many aspects of the Company's Alternative Marketing Plan (AMP) proposal. The AMP proposal included a plan for allowing increased flexibility to offer reduced prices and develop related marketing programs, a commitment to attempt to cap electric rates at current levels for an extended period, the elimination of fuel cost accounting and the fuel adjustment clause, the elimination of seasonal rate differentials and an understanding about the method of amortizing the cost of any future buyout of high-cost purchased power contracts. 14. ACQUISITION OF WHOLESALE CUSTOMER On October 26, 1995, the Company acquired the assets and service territory of its largest full requirements wholesale customer for a purchase price of approximately $2.4 million. The customer served approximately 1,800 customers. The acquisition was accounted for using the purchase method of accounting. The purchase price exceeded the value assigned to the assets acquired by approximately $582,000 and has been recorded as an electric plant acquisition adjustment, which is being amortized on a straight-line basis over a period of 15 years. 15. DERIVATIVE FINANCIAL INSTRUMENTS In 1995 the Company adopted Statement of Financial Accounting Standards No. 119, "Disclosure About Derivative Financial Instruments and Fair Value of Financial Instruments." As discussed in Note 4, the Company entered into interest rate cap agreements (the cap or caps) with three financial institutions related to its $60 million of Medium Term Notes to manage its exposure to interest rate fluctuations. Under the caps, the LIBO rate is capped at 7.25% over the five-year term of the Medium Term Notes for the full notional amount of $60 million. At the beginning of each calendar quarter the notional interest rate is set by the financial institutions based on the current LIBO rate. The Company will be reimbursed for incremental interest expense incurred in excess of the 7.25% cap. In 1995 the notional rate was not in excess of 7.25%. The Company purchases, rather than generates itself, a significant portion of the energy required to service its retail business. These purchased energy prices can vary with changes in the price or availability of the underlying fuel sources, and the risk of such pice volatility is no longer covered by a rate mechanism like the FCA. To manage this exposure, effective January 1, 1996, the Company entered into hedging transactions with three financial institutions. The Company determined that much of its exposure to purchased energy price volatility is closely matched to changes in residual oil prices. Accordingly, the Company entered into agreements known as "swaps", essentially in which the Company agreed to pay a fixed price for a specific quantity of a specific commodity (residual oil in this case), for a given time period. This transfers the risk (or the benefit) of commodity price fluctuations to the other party to the agreement for the given period of time. These are strictly financial transactions, and no delivery of the underlying commodity is taken. Settlements typically occur on a monthly basis and the cash receipts/payments arising from the "swap" transactions will offset corresponding increases/decreases in the Company's purchased energy costs. As a result, the Company can manage a substantial portion of the risk of energy price fluctuations, which allows the Company to more accurately predict its future purchased energy costs and cash flow requirements. To ensure the Company maintains a hedging, and not a speculative, position, the Company has established official policies, procedures and controls for its fuel hedging program. Credit risk arises from potential nonperformance of counterparties to these agreements. The Company managed credit risk related to the cap by spreading the risk amongst three financial institutions and reviewing their financial stability prior to entering into the arrangements. The Company manages the credit risk related to the fuel swaps through credit limits, collateral instruments, monitoring procedures, as well as spreading the risk amongst three financial institutions. Market risk of the fuel swaps is the risk that changes in fuel prices will result in a decrease in the value or an increase in the cost of obligations arising from derivatives. As the Company utilizes derivatives only for risk management purposes, the Company is not exposed to market risk because gains and losses arising on derivative instruments will be offset by corresponding losses and gains on the underlying transaction being hedged. There is no market risk associated with changes in interest rates since the Company paid for the cap when entering into the agreement. The Company will receive a payment if the notional interest rate exceeds 7.25%. COOPERS & LYBRAND REPORT OF INDEPENDENT ACCOUNTANTS To the Stockholders and Directors of Bangor Hydro-Electric Company: We have audited the accompanying consolidated balance sheets and statements of capitalization of Bangor Hydro-Electric Company and subsidiaries (the "Company") as of December 31, 1995 and 1994, and the related consolidated statements of income, retained earnings, and cash flows for each of the three years in the period ended December 31, 1995. These financial statements are the responsibility of the Company's management. Our responsiblity is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of the Company as of December 31, 1995 and 1994, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 1995, in conformity with generally accepted accounting principles. /s/ COOPERS & LYBRAND L.L.P. COOPERS & LYBRAND L.L.P. Boston, Massachusetts February 1, 1996 ITEM 9 CHANGES IN AND DISAGREEMENTS WITH AUDIT FIRMS ON FINANCIAL DISCLOSURE - ---------------------------------------------------------- There have been no changes in or disagreements with audit firms on financial disclosure. PART III - -------- ITEM 10 DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT - ----------------------------------------------------------- See Part I above, and see the information under "Election of Directors" in the Company's definitive proxy statement for the annual meeting of stockholders to be held on May 15, 1996, which information is incorporated herein by reference. ITEM 11 EXECUTIVE COMPENSATION - -------------------------------- See the information under "Executive Compensation" in the Company's definitive proxy statement for the annual meeting of stockholders to be held on May 15, 1996, which information is incorporated herein by reference. ITEM 12 SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT - -------------------------------------------------------- (a) Security Ownership of Certain Beneficial Owners See the Company's definitive proxy statement for the annual meeting of stockholders to be held on May 15, 1996, which information is incorporated herein by reference. (b) Security Ownership of Management See the Company's definitive proxy statement for the annual meeting of stockholders to be held on May 15, 1996, which information is incorporated herein by reference. (c) Changes in Control Not applicable. ITEM 13 CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS - -------------------------------------------------------- See the information under "Compensation Committee Interlocks and Insider Participation" in the Company's definitive proxy statement for the annual meeting of stockholders to be held on May 15, 1996, which information is incorporated herein by reference. PART IV - -------- ITEM 14 EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K - -------------------------------------------------------------- (a) Consolidated Financial Statements of the Company (See Item 8) Consolidated Statements of Income for the Years Ended December 31, 1995, 1994 and 1993 Consolidated Balance Sheets - December 31, 1995 and 1994 Consolidated Statements of Retained Earnings for the Years ended December 31, 1995, 1994 and 1993 Consolidated Statements of Capitalization - December 31, 1995 and 1994 Consolidated Statements of Cash Flows for the Years Ended December 31,1995, 1994 and 1993 Notes to Consolidated Financial Statements Report of Independent Accountants (b) Schedules Report of Independent Accountants Schedule VIII - Reserves for Doubtful Accounts and Insurance All other schedules are omitted as the required information is inapplicable or the information is presented in the Company's consolidated financial statements or related notes. (c) Exhibits See Exhibit Index, page (d) Reports on Form 8-K A Current Report on Form 8-K dated January 12, 1996 was filed in the first quarter of 1996, regarding the return to operation of the Maine Yankee nuclear generating facility. 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. Bangor Hydro-Electric Company /s/ Robert S. Briggs ------------------------------- By: Robert S. Briggs President and Chairman of the Board Pursuant to the requirements of the Securities and Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. /s/ Robert S. Briggs - --------------------------- ----------------------------- Robert S. Briggs Helen Sloane Dudman President and Director Chairman of the Board /s/ William C. Bullock, Jr. /s/ G. Clifton Eames - --------------------------- ------------------------------- William C. Bullock, Jr. G. Clifton Eames Director Director /s/ Jane J. Bush /s/ Robert H. Foster - --------------------------- ------------------------------- Jane J. Bush Robert H. Foster Director Director /s/ David M. Carlisle /c/ Carroll R. Lee - --------------------------- -------------------------------- David M. Carlisle Carroll R. Lee Director Director, Vice President- Operations /s/ Frederick S. Samp - ---------------------------- -------------------------------- Alton E. Cianchette Frederick S. Samp Director Vice President - Finance & Law (Chief Financial Officer) /s/ David R. Black ---------------------- David R. Black Controller (Chief Accounting Officer) Each of the above signatures is affixed as of March 13, 1996. COOPERS & LYBRAND REPORT OF INDEPENDENT ACCOUNTANTS To the Stockholders and Board of Directors of Bangor Hydro-Electric Company: Our report on the consolidated financial statements of Bangor Hydro-Electric Company is included in Item 8 of this Form 10-K. In connection with our audits of such financial statements, we have also audited the related financial statement schedule listed in the index in Item 14(b) of this Form 10-K. 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. /s/ Coopers & Lybrand L.L.P. ---------------------------------- COOPERS & LYBRAND L.L.P. Boston, Massachusetts February 1, 1996 SCHEDULE VIII RESERVES FOR DOUBTFUL ACCOUNTS AND INSURANCE ----------------------------------------------
Additions ----------------------------- Balance at Charged to Charged to Balance at Beginning Costs and Other End Of Period Expenses Accounts Deductions of Period ------- ------- ------- ------- ------- 1995 Reserve for Doubtful Accounts $ 730,000 $ 2,637,301 $ - $ 1,917,301 (A) $ 1,450,000 ----------- ----------- ---------- ----------- ----------- Reserve for Retirees' Life Insurance $ 848,000 $ 32,000 $ - $ 28,000 $ 852,000 ----------- ----------- ---------- ----------- ----------- 1994 Reserve for Doubtful Accounts $ 1,450,000 $ 913,841 $ - $ 1,633,841 (A) $ 730,000 ----------- ----------- ---------- ----------- ----------- Reserve for Retirees' Life Insurance $ 700,000 $ 164,000 $ - $ 16,000 $ 848,000 ----------- ----------- ---------- ----------- ----------- 1993 Reserve for Doubtful Accounts $ 1,450,000 $ 1,090,813 $ - $ 1,090,813 (A) $ 1,450,000 ----------- ----------- ---------- ----------- ----------- Reserve for Retirees' Life Insurance $ 612,000 $ 92,000 $ - $ 4,000 $ 700,000 ----------- ----------- ---------- ----------- ----------- NOTE: (A) Accounts written off, less recoveries.
EXHIBIT INDEX EXHIBITS FILED HEREWITH ----------------------- EXHIBIT NO. DESCRIPTION OF EXHIBIT ----------- ---------------------- 3. ARTICLES OF INCORPORATION ------------------------- 3(a) Articles of Amendment changing Corporate Clerk. 4. INSTRUMENTS DEFINING THE RIGHTS OF SECURITY HOLDERS --------------------------------------------------- 10(a) Supplemental Indenture Dated as of October 1, 1995 to General and Refunding Mortgage and Deed of Trust dated as of June 1, 1995 (Bangor Hydro-Electric Company to Chemical Bank). EXHIBITS INCORPORATED HEREIN BY REFERENCE ----------------------------------------- EXHIBIT NO. DESCRIPTION OF EXHIBIT INCORPORATED BY REFERENCE TO: - ----------- ---------------------- ----------------------------- 3. ARTICLES OF INCORPORATION & BY-LAWS ----------------------------------- 3.1 Company's Certificate Form S-2, Reg. No. 33-39181, of Organization, together Exhibit 3.1 with all amendments thereto 3.2 Articles of Amendment Form S-2, Reg. No. 33-63500, increasing Company's Exhibit 4.3 authorized capital stock 3.3 By-Laws of the Company Form S-2, Reg. No. 33-63500, Exhibit 4.4 4. INSTRUMENTS DEFINING THE RIGHTS OF SECURITY HOLDERS ---------------------------------------------------- 4.1 Mortgage and Deed of Form S-1, Reg. No. 2-54452, Trust dated as of Exhibit 4(b)(1) July 1, 1936, re First Mortgage Bonds 4.2 Supplemental Indenture Form S-1, Reg. No. 2-54452, dated as of December 1, Exhibit 4(b)(2) 1945, amending the Mortgage 4.3 Supplemental Indenture Form S-1, Reg. No. 2-54452 dated as of September 1, Exhibit 4(b)(4) 1969, re 8 1/4% Series Bonds, together with form of purchase agreement. (Supplemental indentures and purchase agreements with respect to prior issues are substantially identical in substantive content to the 8 1/4% Series documents). 4.4 Supplemental Indenture Form 10-K, 1975, Exhibit B dated as of November 1, 1975, re 10 1/2% Series Bonds, together with form of purchase agreement 4.5 Supplemental Indenture Form 8-K, 6/28/76, Exhibit A dated as of June 1, 1976, re 9 1/4% Series Bonds 4.6 Form of Purchase Form 10-K, 1976, Exhibit C Agreement re 9 1/4% Series Bonds 4.7 Supplemental Indenture Form S-7, Reg. No. 2-61589, dated as of January 1, Exhibit 5(a)(7) 1978, re 8.6% Series Bonds, together with form of purchase agreement 4.8 Supplemental Indenture Form 10-Q, 3rd Quarter 1979, dated as of August 1, Exhibit A 1979, re 10.25% Series Bonds, together with form of purchase agreement Common Stock Purchase Plan 4.9 Supplemental Indenture Form 10-Q, 1st Quarter, 1981, dated as of April 1, Exhibit A 1981 re 15.25% Series Bonds, together with form of purchase agreement 4.10 Supplemental Indenture Form 10-Q, 2nd Quarter 1981, dated as of July 30, Exhibit (4) 1981 re 16.50% Series Bonds, together with form of purchase agreement 4.11 Bond Purchase Agreement, Form 10-K, 1983, Exhibit 4(a) including form of supplemental indenture, with respect to First Mortgage Bonds, 12.50% Series due 1998 4.12 Loan Agreement, Indenture Form 10-K, 1983, Exhibit 4(b) of Trust and Letter of Credit Reimbursement Agreement with respect to Variable Rate Demand Pollution Control Revenue Bonds (Bangor Hydro- Electric Company Project) Series 1983 4.13 Bond Purchase Agreement, Form 10-K, 1984, Exhibit 4(a) including form of supplemental indenture, with respect to First Mortgage Bonds, 17.35% Series due 1994 4.14 Bond Purchase Agreement Form 10-Q, First Quarter, dated as of March 1, 1989 1989, Exhibit 4.1 including form of supplemental indenture, with respect to First Mortgage Bonds, 10.25% Series due 2019 4.15 Preferred Stock Purchase Form 10-K, 1990, Exhibit 4(a) Agreement, 8.76% Series dated as of December 19, 1989 4.16 Bond Purchase Agreement Form 10-K, 1990, Exhibit 4(b) dated as of June 15, 1990 including form of supplemental indenture, with respect to First Mortgage Bonds, 10.25% Series due 2020 4.17 Loan Agreement by and Form 10-Q, 3rd Quarter 1995, Finance Authority of Exhibit 4.1 Maine and Bangor Hydro- Electric Company 4.18 Credit Agreement Dated Form 10-Q, 3rd Quarter 1995, as of June 30, 1995 Exhibit 4.2 among Bangor Hydro- Electric Company, the Banks named therein, Chemical Bank as Administrative Agent and Fleet Bank of Maine and First National Bank of Boston, as Co-Agents. 4.19 Purchase Contract dated Form 10-Q, 3rd Quarter 1995, as of June 28, 1995 among Exhibit 4.3 the Finance Authority of Maine and Bangor Hydro- Electric Company and Prudential Securities Incorporated 4.20 General and Refunding Form 10-Q, 3rd Quarter 1995, Mortgage Indenture and Exhibit 4.4 Deed of Trust - Bangor Hydro-Electric Company to Chemical Bank, As Trustee, Dated as of June 1, 1995 4.21 Supplemental Indenture Form 10-Q, 3rd Quarter 1995, Dated as of June 15, 1995 Exhibit 4.5 to General and Refunding Mortgage Indenture and Deed of Trust dated as of June 1, 1995 (Bangor Hydro- Electric Company to Chemical Bank). 4.22 Supplemental Indenture as Form 10-Q, 3rd Quarter 1995, of June 29, 1995 to Mortgage and Deed of Trust dated as of July 1, 1936 (Bangor Hydro-Electric Company to Citibank, N.A. at Trustee). 10. MATERIAL CONTRACTS ------------------ 10.1 New England Power Pool Form S-7, Reg. No. 2-69904, Agreement dated as of Exhibit 10(a)(3) September 1, 1971, with all amendments through December 1980 10.2 Copy of Twelfth Amendment Form S-7, Reg. No. 2-69904, dated as of June 16, 1980 Exhibit 10(a)(4) to the Agreement for Joint Ownership, Construction and Operation of New Hampshire Nuclear Units 10.3 Participation Agreement Form S-1, Reg. No. 2-54452, dated June 20, 1969 Exhibit 13(a)(2)(a)-1 between Maine Electric Power Company, Inc. ("MEPCO") and the Company 10.4 Agreement dated June Form S-1, Reg. No. 2-54452, 29, 1969 among Maine Exhibit 13(a)(2)(a)-2 participants in MEPCO Participation Agreement 10.5 Power Contract dated Form S-1, Reg. No. 2-54452, May 20, 1968 between Exhibit 13(a)(3)(a) Maine Yankee Atomic Power Company ("Maine Yankee") and the Company and other utilities 10.6 Stockholder Agreement Form S-1, Reg. No. 2-54452, dated May 20, 1968 Exhibit 13(a)(3)(b) among stockholders of Maine Yankee, (including the Company). 10.7 Capital Funds Agreement Form S-1, Reg. No. 2-54452, dated May 29,1968 Exhibit 13(a)(3)(c) between Maine Yankee and sponsors, including the Company 10.8 Maine Yankee Transmission Form S-1, Reg. No. 2-54452, Agreement dated April 1, Exhibit 13(a)(3)(d) 1971 among the Company and other utilities 10.9 Modification of Maine Form S-1, Reg. No. 2-54452, Yankee Transmission Exhibit 13(a)(3)(f) Agreement of December 1, 1972 10.10 Agreement for Joint Form S-1, Reg. No. 2-54452, Ownership, Construction Exhibit 13(a)(4)(a) and Operation dated November 1, 1974 of Wyman Unit No. 4 among Central Maine Power Company, the Company and other utilities 10.11 Amendment No. 1 dated Form S-1, Reg. No. 2-54452, June 30, 1975 to Wyman 4 Exhibit 13(a)(4)(b) Agreement of November 1, 1974 10.12 Transmission Agreement Form S-1, Reg. No. 2-54452, dated November 1, 1974 Exhibit 13(a)(4)(c) re Wyman Unit No. 4 among Central Maine Power Company and other utilities 10.13 Form of Federal Power Form S-1, Reg. No. 2-54452, Commission license Exhibit 13(b)(4) for hydro-electric dam facility 10.14 Employee Stock Ownership Form S-7, Reg. No. 2-59747, Plan, including related Exhibit 5(a)(2) trust agreements, dated June 1, 1977 10.15 Sample of binder relating Form S-7, Reg. No. 2-59747, to contingent liability Exhibit 5(a)(4) for nuclear incidents 10.16 Agreements relating to Form S-7, Reg. No. 2-61589, Seabrook 1 and 2 Exhibit 5(a)(3) including offering letter dated September 7, 1977 and the Company's response thereto dated October 6, 1977, the Agreement to Transfer Ownership Share between the Company and The Connecticut Light and Power Co., dated November 1, 1977 and a letter amendment thereto dated January 31, 1978, and the Joint Ownership Agreement with Public Service Company of New Hampshire and other utilities as amended through January 31, 1975 10.17 Amendment No. 2 dated Form 10-K, 1976, Exhibit H(2) August 16, 1976 to Joint Ownership Agreement dated November 1, 1974 with Central Maine Power Company and others re Wyman Unit No. 4 10.18 Copies of Tenth and Form 10-K, 1979, Exhibit D Eleventh Amendments dated October 11, 1979 and December 15, 1979, respectively, to the Agreement for Joint Ownership Construction and Operation of New Hampshire Nuclear Units 10.19 Copies of Forms of Form 10-Q, 2nd Qtr. 1979, documents related to Exhibit A the Company's proposed purchase of an additional 1.80142% interest in the Seabrook Nuclear Units, consisting of PSNH's offer to sell ownership shares dated March 8, 1979, the Company's letter response thereto dated March 19, 1979, and the Sixth, Seventh, Eighth and Ninth Amendment to the Agreement for Joint Ownership, Construction and Operation of New Hampshire Nuclear Units, dated April 18, 1979, April 18, 1979, April 25, 1979, and June 8, 1979, respectively 10.20 Copy of Thirteenth Form 10-K, 1981, Exhibit Amendment dated as of 10(a) December 31, 1980 to the Agreement for Joint Ownership, Construction and Operation of New Hampshire Nuclear Units 10.21 Forms of contracts Form 10-Q, 2nd Qtr. 1982, concerning the Company's Exhibit 10 participation with other New England utilities in the proposed Quebec interconnection 10.22 Fourteenth Amendment Form 10-K, 1983, Exhibit 10.1 dated as of June 1, 1982 to the Agreement for Joint Ownership, Construction and Operation of New Hampshire Nuclear Units 10.23 Third Amendment dated Form 10-K, 1983, Exhibit 10.2 as of November 1, 1982 to Preliminary Quebec Interconnection Support Agreement 10.24 Second Amendment dated Form 10-K, 1983, Exhibit 10.3 as of November 1, 1982 to Agreement With Respect to Use of Quebec Interconnection 10.25 Amendment No. 2 dated Form 10-K, 1983, Exhibit 10.4 as of November 1, 1982, to Phase 1 Terminal Facility Support Agreement (Quebec Interconnection) 10.26 Amendment No. 2 dated Form 10-K, 1983, Exhibit 10.5 as of November 1, 1982 to Phase 1 Vermont Transmission Line Support Agreement (Quebec Interconnection) 10.27 Fourth Amendment Form 10-Q, 1st Quarter 1983, dated as of March 1, Exhibit 10.1 1983, to Preliminary Quebec Interconnection Support Agreement 10.28 Fourteenth Amendment to Form 10-Q, 2nd Quarter 1983, Agreement for Joint Exhibit 10.2 Ownership, Construction and Operation of New Hampshire Nuclear Units 10.29 Fifth Amendment to Form 10-Q, 2nd Quarter 1983, Preliminary Quebec Exhibit 10.2 Interconnection Support Agreement 10.30 Amendment dated as of Form 10-Q, 2nd Quarter 1983, September 1, 1981 Exhibit 10.3 to New England Power Pool Agreement 10.31 Amendment dated as of Form 10-Q, 2nd Quarter 1983, June 1, 1982 to New Exhibit 10.4 England Power Pool Agreement 10.32 Amendment dated as of Form 10-Q, 2nd Quarter 1983, June 15, 1983 to New Exhibit 10.5 England Power Pool Agreement 10.33 Amendment dated as of Form 10-Q, 3rd Quarter 1983, October 1, 1983 to Exhibit 10.1 New England Power Pool Agreement 10.34 Amendment No. 1 to the Form 10-K, 1983, Exhibit 10(b) Maine Yankee Power Contract 10.35 Amendment No. 2 to the Form 10-K, 1983, Exhibit 10(c) Maine Yankee Power Contract 10.36 Additional Power Con- Form 10-K, 1983, Exhibit 10(d) tract between Maine Yankee and its sponsors, including the Company 10.37 Interim Protection Agree- Form 10-Q, 1st Quarter 1984, ment dated as of April Exhibit 10.1 27, 1984 relating to the Seabrook project 10.38 Fifteenth Amendment Form 10-Q, 1st Quarter 1984, to the Seabrook Joint Exhibit 10.2 Ownership Agreement 10.39 Sixteenth Amendment Form 10-Q, 2nd Quarter 1984, to the Seabrook Joint Exhibit 10.1 Ownership Agreement 10.40 Agreement for Seabrook Form 10-Q, 2nd Quarter 1984, Project Disbursing Agent Exhibit 10.2 10.41 Seventeenth Amendment to Form 10-K, 1984, Exhibit 10(a) Seabrook Joint Ownership Agreement and corresponding First Amendment to Seabrook Project Disbursing Agent Agreement (neither of which were executed by the Company) 10.42 Preliminary Support Form 10-K, 1984, Exhibit 10(b) Agreement - Phase 2 of Hydro-Quebec Inter- connection 10.43 Letter of Intent between Form 10-Q, 2nd Quarter 1985, the Company and Eastern Exhibit 10.1 Utilities Associates re: possible sale of Seabrook interest 10.44 First, Second and Third Form 10-K, 1985, Exhibit 10(a) Amendments to agreement for Seabrook Project Disbursing Agent (none of which were executed by the Company) 10.45 Amendment dated September 1, Form 10-K, 1985, Exhibit 1985 to Agreement with 10(b) respect to Use of Quebec Interconnection 10.46 Energy Contract dated Form 10-K, 1985, Exhibit 10(c) March 1983 between NEPOOL and Hydro-Quebec re: Hydro-Quebec Phase I interconnection project 10.47 Energy Banking Agreement Form 10-K, 1985, Exhibit 10(d) dated March 1983 between NEPOOL and Hydro-Quebec re Hydro-Quebec Phase I interconnection project 10.48 Interconnection Agreement Form 10-K, 1985, Exhibit 10(e) dated March 1983 between NEPOOL and Hydro-Quebec re: Hydro-Quebec Phase I interconnection project 10.49 Amendment dated September 1 Form 10-K, 1985, Exhibit 1985 to NEPOOL Agreement 10(f) re: Hydro-Quebec Phase II interconnection project 10.50 Firm Energy Contract dated Form 10-K, 1985, Exhibit October 14, 1985 between 10(g) New England utilities and Hydro-Quebec re: Hydro- Quebec Phase II interconnection project 10.51 Boston Edison AC Facilities Form 10-K, 1985, Exhibit Support Agreement dated June 10(h) 1, 1985 re: Hydro-Quebec Phase II interconnection project 10.52 Phase II New England Form 10-K, 1985, Exhibit Power AC Facilities 10(i) Support Agreement dated June 1, 1985 re: Hydro- Quebec Phase II interconnection project 10.53 Phase II Massachusetts Form 10-K, 1985, Exhibit Transmission Facilities 10(j) Support Agreement dated June 1, 1985 re: Hydro- Quebec Phase II interconnection project 10.54 Phase II New Hampshire Form 10-K, 1985, Exhibit 10(k) Facilities Support Agreement dated June 1, 1985 re: Hydro-Quebec Phase II interconnection project 10.55 First Amendment dated Form 10-K, 1985, Exhibit 10(l) March 1, 1985 and Second Amendment dated January 1, 1986 to Preliminary Quebec Interconnection Support Agreement - Phase II 10.56 Amendment No. 3 dated Form 10-K, 1985, Exhibit 10(m) October 1, 1984 to Maine Yankee Power Contract 10.57 Amendment No. 1 dated Form 10-K, 1985, Exhibit 10(n) August 1, 1985 to Maine Yankee Capital Funds Agreement 10.58 Amendments dated August 1, Form 10-K, 1985, Exhibit 1985, August 15, 1985, and 10(o) January 1, 1986 to NEPOOL Agreement 10.59 Fourth Amendment to Form 10-Q, 1st Quarter 1986, Seabrook Project Exhibit 10.1 Disbursing Agent Agreement 10.60 Third Amendment to Vermont Form 10-Q, 1st Quarter 1986, Transmission Line Support Exhibit 10.2 Agreement 10.61 First Amendment to Hydro- Form 10-Q, 1st Quarter 1986, Quebec Phase I Intercon- Exhibit 10.3 nection Agreement 10.62 First Amendment to Hydro- Form 10-Q, 2nd Quarter 1986, Quebec Phase II Exhibit 10.1 Massachusetts Trans- mission Facilities Support Agreement 10.63 First Amendment to Hydro- Form 10-Q, 2nd Quarter 1986, Quebec Phase II New Exhibit 10.2 Hampshire Transmission Facilities Support Agreement 10.64 First Amendment to Hydro- Form 10-Q, 2nd Quarter 1986, Quebec Phase II New England Exhibit 10.3 Power AC Facilities Support Agreement 10.65 First Amendment to Form 10-Q, 2nd Quarter 1986, Hydro-Quebec Phase II Exhibit 10.4 Boston Edison Company AC Facilities Support Agreement 10.66 Eighteenth Amendment to Form 10-Q, 2nd Quarter 1986, Seabrook Joint Ownership Exhibit 10.5 Agreement 10.67 Amendment Number 3 to Form 10-Q, 3rd Quarter 1986, Hydro-Quebec Phase l Exhibit 10.1 Terminal Facility Support Agreement 10.68 Amendment Number 3 to Form 10-Q, 3rd Quarter 1986, Hydro-Quebec Phase I Exhibit 10.2 Vermont Transmission Line Support Agreement 10.69 Power Sale Agreement for Form 10-Q, 3rd Quarter 1986, sale of approximately Exhibit 10.3 31 MW of system power by Bangor Hydro-Electric Company to UNITIL Power Corp. 10.70 Purchase Agreement with Form 10-Q, 3rd Quarter 1986, respect to Wyman No. 4 Exhibit 10.4 between Bangor Hydro- Electric Company and Fitchburg Gas and Electric Light Company 10.71 Nineteenth Amendment to Form 10-K, 1986, Exhibit 10(a) Seabrook Joint Ownership Agreement 10.72 Twentieth Amendment to Form 10-K, 1986, Exhibit 10(b) Seabrook Joint Ownership Agreement 10.73 Agreement of Purchase and Form 10-K, 1986, Exhibit 10(c) Sale dated February 19, 1986, regarding the sale of the Company's Seabrook interest to EUA Power 10.74 Bill of Sale and Assumption Form 10-K, 1986, Exhibit of Obligations dated 10(d) November 25, 1986 regarding the sale of the Company's Seabrook interest to EUA Power 10.75 Deed dated November 21, Form 10-K, 1986, Exhibit 10(e) 1986 regarding the sale of the Company's Seabrook interest to EUA Power 10.76 Agreement to Share Certain Form 10-K, 1986, Exhibit Costs re Tewksbury-Seabrook 10(f) Transmission Line dated May 8, 1986 10.77 Joint Venture Agreement Form 10-K, 1986, Exhibit effective as of June 9, 10(g) 1986, between the Company and Pacific Lighting Energy Systems (as amended by a First Amendment thereto dated June 16, 1986) re Bangor-Pacific Hydro Associates (formerly West Enfield Associates) 10.78 Capital Support Agreement Form 10-K, 1986, Exhibit dated as of January 29, 10(h) 1987, among the Company and lenders to Bangor- Pacific Hydro Associates 10.79 Power Purchase Agreement Form 10-K, 1986, Exhibit dated June 9, 1986 and 10(i) Amendment No. 1 thereto dated January 14, 1987, between the Company and Bangor-Pacific Hydro Associates (formerly West Enfield Associates) 10.80 Deed and Bill of Sale re Form 10-K, 1986, Exhibit transfer of West Enfield 10(j) site from the Company to Bangor-Pacific Hydro Associates 10.81 Assignment by the Company Form 10-K, 1986, Exhibit of Joint Venture Interest 10(k) to Penobscot Hydro Co., Inc. 10.82 Power Sale Agreement dated Form 10-K, 1986, Exhibit August 1, 1986, and First 10(l) Amendment thereto, between the Company and Unitil Power Corp. re Wyman No. 4 10.83 Third Amendment to Pre- Form 10-K, 1987, Exhibit liminary Quebec Intercon- 10(a) nection Support Agreement - Phase II 10.84 Fourth Amendment to Pre- Form 10-K, 1987, Exhibit liminary Quebec Intercon- 10(b) nection Support Agreement - Phase II 10.85 Fifth Amendment to Pre- Form 10-K, 1987, Exhibit liminary Quebec Intercon- 10(c) nection Support Agreement - Phase II 10.86 Sixth Amendment to Pre- Form 10-K, 1987, Exhibit liminary Quebec Intercon- 10(d) nection Support Agreement - Phase II 10.87 Seventh Amendment to Pre- Form 10-K, 1987, Exhibit liminary Quebec Intercon- 10(e) nection Support Agreement - Phase II 10.88 Amendment to New England Form 10-K, 1987, Exhibit Power Pool Agreement dated 10(f) March 1, 1988 10.89 Second Amendment to Credit Form 10-K, 1987, Exhibit Agreement, dated as of July 10(h) 22, 1987, among the Company and the Banks named therein 10.90 Dividend Reinvestment and Form 10-K, 1987, Exhibit Common Stock Purchase Plan 10(i) Effective as of December 1, 1987 10.91 Deed dated December 2, Form 10-K, 1988, Exhibit 1988 regarding the sale 10(a) of certain Seabrook trans- mission facilities to EUA Power 10.92 Ninth Amendment to Form 10-K, 1988, Exhibit Preliminary Quebec 10(b) Interconnection Support Agreement - Phase II 10.93 Tenth Amendment to Form 10-K, 1988, Exhibit Preliminary Quebec 10(c) Interconnection Support Agreement - Phase II 10.94 Second Amendment to Form 10-K, 1988, Exhibit Massachusetts Trans- 10(d) mission Facilities Support Agreement 10.95 Third Amendment to Form 10-K, 1988, Exhibit Massachusetts Trans- 10(e) mission Facilities Support Agreement 10.96 Fourth Amendment to Form 10-K, 1988, Exhibit Massachusetts Trans- 10(f) mission Facilities Support Agreement 10.97 Fifth Amendment to Form 10-K, 1988, Exhibit 10(g) Massachusetts Trans- mission Facilities Support Agreement 10.98 Sixth Amendment to Form 10-K, 1988, Exhibit 10(h) Massachusetts Trans- mission Facilities Support Agreement 10.99 Second Amendment to Form 10-K, 1988, Exhibit 10(i) New Hampshire Trans- mission Facilities Support Agreement 10.100 Third Amendment to Form 10-K, 1988, Exhibit 10(j) New Hampshire Trans- mission Facilities Support Agreement 10.101 Fourth Amendment to Form 10-K, 1988, Exhibit 10(k) New Hampshire Trans- mission Facilities Support Agreement 10.102 Fifth Amendment to Form 10-K, 1988, Exhibit 10(l) New Hampshire Trans- mission Facilities Support Agreement 10.103 Sixth Amendment to Form 10-K, 1988, Exhibit 10(m) New Hampshire Trans- mission Facilities Support Agreement 10.104 Second Amendment to Form 10-K, 1988, Exhibit 10(n) Phase II AC New England Power Facilities Sup- port Agreement 10.105 Third Amendment to Form 10-K, 1988, Exhibit 10(o) Phase II AC New England Power Facilities Sup- port Agreement 10.106 Fourth Amendment to Form 10-K, 1988, Exhibit 10(p) Phase II AC New England Power Facilities Sup- port Agreement 10.107 Fifth Amendment to Form 10-K, 1988, Exhibit 10(q) Phase II AC New England Power Facilities Sup- port Agreement 10.108 Second Amendment to Form 10-K, 1988, Exhibit 10(r) Phase II Boston Edison AC Facilities Support Agreement 10.109 Third Amendment to Form 10-K, 1988, Exhibit 10(s) Phase II Boston Edison AC Facilities Support Agreement 110.110 Fourth Amendment to Form 10-K, 1988, Exhibit 10(t) Phase II Boston Edison AC Facilities Support Agreement 10.111 Fifth Amendment to Form 10-K, 1988, Exhibit 10(u) Phase II Boston Edison AC Facilities Support Agreement 10.112 Letter of Assurances, Form 10-K, 1988, Exhibit 10(v) Consents and Agreements With Respect to Credit Facility Financing for Phase II Hydro-Quebec Financing 10.113 Agreement With Hanlin Form 10-K, 1988, Exhibit 10(w) Group, Inc., also known as "LCP", for the sale of electricity 10.114 401 (k) Plan for Non- Form 10-K, 1988, Exhibit 10(x) Union Employees 10.115 Credit Agreement dated Form 10-Q, First Quarter, 1989 as of May 2, 1989 among Exhibit 4.2 the Company, the Banks named therein, and Manufacturers Hanover Trust Company, as Agent 10.116 Agreement for the Sale Form S-2, Reg. No. 33-39181, and Purchase of Electricity Exhibit 10.79 dated as of August 13, 1984 between Ultrapower Incorpor- ated-Jonesboro and the Company 10.117 Agreement for the Sale Form S-2, Reg. No. 33-39181, and Purchase of Electricity Exhibit 10.80 dated as of August 13, 1984 between Ultrapower Incorpor- ated-West Enfield and the Company 10.118 Amendment Agreement Form S-2, Reg. No. 33-39181, dated November 3, 1988 Exhibit 10.81 between the Company and Babcock-Ultrapower West Enfield and Babcock- Ultrapower-Jonesboro 10.119 Agreement for the Form S-2, Reg. No. 33-39181, Purchase and Sale of Exhibit 10.82 Electricity dated as of June 21, 1984 between Penobscot Energy Recovery Company and the Company 10.120 Amendment No. 1 as of Form S-2, Reg. No. 33-39181, March 24, 1986 to the Exhibit 10.83 Agreement for the Purchase and Sale of Electricity dated as of June 21, 1984 between Penobscot Energy Recovery Company and the Company 10.121 Power Purchase Agree- Form S-2, Reg. No. 33-39181, ment dated October 24, 1984 Exhibit 10.84 between Alternative Energy Decisions, Inc. and the Company 10.122 Partnership Agreement Form S-2, Reg. No. 33-39181, dated as of July 1, 1990 Exhibit 10.85 between NORVARCO and Bangor Var Co., Inc. 10.123 Form of Agreement with Form 10-K, 1992, Exhibit 10(a) certain Executive Officers providing supplemental death and retirement benefits 10.124 Form of Agreement with Form 10-K, 1992, Exhibit 10(b) certain Executive Officers providing benefits upon a change of control 10.125 Purchase Agreement between Form 10-Q, 3rd Quarter 1995, Babcock-Ultrapower Exhibit 10.1 Jonseboro and Bangor Hydro- Electric Company 10.126 Purchase Agreement between Form 10-Q, 3rd Quarter 1995, Babcock-Ultrapower West Exhibit 10.2 Enfield and Bangor Hydro- Electric Company EX-27 2 FINANCIAL DATA SCHEDULE ACCOMPANYING FORM 10-K
UT This schedule contains summary financial information extracted from 10-K and is qualified in its entirety by reference to such 10-K. 0000009548 BANGOR HYDRO-ELECTRIC COMPANY 1,000 12-MOS DEC-31-1995 DEC-31-1995 PER-BOOK 218,440 48,666 35,763 263,207 0 566,076 36,508 56,611 10,073 103,192 12,070 4,734 288,075 0 35,000 0 13,646 3,923 0 0 106,066 566,076 184,914 1,422 159,823 161,245 23,669 760 24,429 20,092 4,337 1,702 2,635 6,319 17,597 (164,522) .36 .36
EX-3 3 EXHIBIT 3(A) TO BANGOR HYDRO-ELECTRIC COMPANY-10K STATE OF MAINE CHANGE OF CLERK or REGISTERED OFFICE or BOTH Pursuant to 13-A MRSA Section 304 the undersigned corporation advises you of the following change(s): FIRST: The name and registered office of the clerk appearing on the record in Secretary of State's office FREDERICK S. SAMP ------------------------------------------------------------------ 33 STATE STREET, BANGOR ME 04401 ------------------------------------------------------------------ (street, city, state and zip code) SECOND: The name and physical location of the registered office of the successor (new) clerk, who must be a Maine resident, are: ANDREW LANDRY ------------------------------------------------------------------ (name) 33 STATE STREET, BANGOR ME 04401 ------------------------------------------------------------------ (street address (not PO Box), city, state and zip code) ------------------------------------------------------------------ (mailing address if different from above) THIRD: Upon a change in clerk this must be completed: (X) Such change was authorized by the directors and the power to make such change is not reserved to the shareholders by the articles or the bylaws. ( ) Such change was authorized by the shareholders. (Complete the following) I certify that I have custody of the minutes showing the above action by the shareholders. /s/ Andrew Landry ----------------------------------------------- (signature of new clerk, secretary or assistant secretary) Dated: OCTOBER 13, 1995 BANGOR HYDRO-ELECTRIC COMPANY ----------------- ---------------------------------------------- (Name of Corporation) By /s/ Andrew Landry --------------------------------------------- (signature) ANDREW LANDRY, CLERK --------------------------------------------- (type or print name and capacity) By -------------------------------------------- (signature) -------------------------------------------- (type or print name and capacity) - --------------------------------------- This document MUST be signed by (1) the CLERK or (2) the PRESIDENT or a vice- president AND the SECRETARY, an assistant secretary or other officer the bylaws designate as second certifying officer OR (3) if no such officers, a majority of the DIRECTORS or such directors designated by a majority of directors then in office OR (4) if no directors, the holders, or such of them designated by the HOLDERS, OF RECORD OF A MAJORITY OF ALL OUTSTANDING SHARES entitled to vote thereon OR (5) the HOLDERS OF ALL OUTSTANDING SHARES. BANGOR HYDRO-ELECTRIC COMPANY FORM 10-K EXHIBIT 10(A) - ------------- EXHIBIT 10(A) TO BHE FORM 10-K FOR 1995 FORM NO. MBCA-3 Rev. 90 SUBMIT COMPLETED FORMS TO: Secretary of State, Station 101, Augusta, Maine 04333 EX-10 4 EXHIBIT 10(A) TO BANGOR HYDRO-ELCTRIC COMPANY-10K BANGOR HYDRO-ELECTRIC COMPANY TO CHEMICAL BANK, as Trustee ------------- Supplemental Indenture DATED AS OF OCTOBER 1, 1995 TO General and Refunding Mortgage Indenture and Deed of Trust DATED AS OF JUNE 1, 1995 SUPPLEMENTAL INDENTURE, dated as of October 1, 1995 (the "Supplemental Indenture"), made by and between BANGOR HYDRO- ELECTRIC COMPANY, a corporation organized and existing under the laws of the State of Maine (the "Company"), the post office address of which is 33 State Street, Bangor, Maine 04401, and CHEMICAL BANK, a corporation organized and existing under the laws of the State of New York (the "Trustee"), as Trustee under the General and Refunding Mortgage Indenture and Deed of Trust dated as of June 1, 1995, hereinafter mentioned, the post office address of which is 450 West 33rd Street, New York, New York 10001; WHEREAS, the Company has heretofore executed and delivered its General and Refunding Mortgage Indenture and Deed of Trust dated as of June 1, 1995 (the "Indenture"), to the Trustee, for the security of the bonds of the Company issued thereunder (the "Bonds"); and WHEREAS, the Company has heretofore executed and delivered its Supplemental Indenture dated as of June 15, 1995; and WHEREAS, the Company has heretofore executed authenticated, delivered and issued a Series of Bonds entitled General and Refunding Mortgage Bonds, Series A (the "Series A Bonds") in the aggregate principal amount of $126,000,000, all of which are Outstanding as of the date hereof; and WHEREAS, Section 14.01 of the Indenture provides that without the consent of any Holders, the Company and the Trustee, at any time and from time to time, may enter into one or more indentures supplemental thereto, in form satisfactory to the Trustee, for among other things, the purpose of correcting or amplifying the description of any property at any time subject to the Lien of the Indenture; and WHEREAS, the Company, in the exercise of the powers and authority conferred upon and reserved to it under Section 14.01 of the Indenture, has duly resolved and determined to make, execute and deliver to the Trustee a Supplemental Indenture in the form hereof for the purposes herein provided; and WHEREAS, all conditions and requirements necessary to make this Supplemental Indenture a valid, binding and legal instrument have been done, performed and fulfilled and the execution and delivery hereof have been in all respects duly authorized; NOW, THEREFORE, THIS SUPPLEMENTAL INDENTURE WITNESSETH: THAT BANGOR HYDRO-ELECTRIC COMPANY, in consideration of the service by the Trustee, and its successors, under the Indenture and of One Dollar to it duly paid by the Trustee at or before the ensealing and delivery of these presents, the receipt whereof is hereby acknowledged, hereby covenants and agrees to and with the Trustee and its successors in the trust under the Indenture, for the benefit of those who shall hold the Bonds as follows: ARTICLE I. SUPPLEMENTAL PROPERTY DESCRIPTION The description of property subject to the Lien of the Indenture is set forth in Exhibit A hereto, and amplifies the description of property subject to the Lien of the Indenture attached as Exhibit A to the Indenture as originally executed and delivered by the Company and filed in each county in the State of Maine in which the Company has any right, title or interest in property, and is deemed to replace and supersede such Exhibit A in full. ARTICLE II. THE TRUSTEE. The Trustee hereby accepts the trusts hereby declared and provided, and agrees to perform the same upon the terms and conditions in the Indenture set forth and upon the following terms and conditions: The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of this Supplemental Indenture or the due execution hereof by the Company or for or in respect of the recitals contained herein, all of which recitals are made by the Company solely. ARTICLE III. MISCELLANEOUS PROVISIONS. This Supplemental Indenture may be simultaneously executed in any number of counterparts, each of which when so executed shall be deemed to be an original; but such counterparts shall together constitute but one and the same instrument. IN WITNESS WHEREOF, said Bangor Hydro-Electric Company has caused this Supplemental Indenture to be executed on its behalf by an Authorized Executive Officer as defined in the Indenture, and its corporate seal to be hereto affixed and said seal and this Supplemental Indenture to be attested by an Authorized Executive Officer as defined in the Indenture; and Chemical Bank, in evidence of its acceptance of the trust hereby created, has caused this Supplemental Indenture to be executed on its behalf by its President or one of its Vice Presidents and its corporate seal to be hereto affixed and said seal and this Supplemental Indenture to be attested by its Secretary or one of its Trust Officers all as of the date first above written. BANGOR HYDRO-ELECTRIC COMPANY By /s/ Robert S. Briggs -------------------------- [CORPORATE SEAL] President and Chief Executive Officer ATTEST: /s/ Andrew Landry - -------------------- Clerk CHEMICAL BANK [CORPORATE SEAL] By /s/ ------------------------- Vice President ATTEST: /s/ - ------------------------ Trust Officer STATE OF MAINE ) ) ss.: COUNTY OF PENOBSCOT ) BE IT REMEMBERED, that on this 18TH day of October 1995, before me, the undersigned, GAYLE A. KILLAM , a Notary Public within and for the County and State aforesaid, personally came Robert S. Briggs, President, and Andrew Landry, Clerk, of Bangor Hydro-Electric Company, a corporation duly organized, incorporated and existing under the laws of the State of Maine, who are personally known to me to be such officers, and who are personally known to me to be the same persons who executed as such officers the within instrument of writing, and such persons duly acknowledged that they signed, sealed and delivered the said instrument as their free and voluntary act as such President and Clerk, respectively, and as the free and voluntary act of said Bangor Hydro-Electric Company for the uses and purposes therein set forth. IN WITNESS WHEREOF, I have hereunto subscribed my name and affixed my official seal on the day and year last above written. /s/ Gayle A. Killam --------------------------------- Notary Public [NOTARIAL SEAL] STATE OF NEW YORK ) ) ss.: COUNTY OF NEW YORK ) BE IT REMEMBERED, that on this 30TH day of November, 1995, before me, the undersigned ROBERT J. STANISLARO , a Notary Public within and for the County and State aforesaid, personally came W.B. DODGE , a Vice-President and WANDA EILAND , a Trust Officer, of Chemical Bank, a corporation organized and existing under the laws of State of New York, who are personally known to me to be the same persons who executed as such officers the within instrument of writing, and such persons duly acknowledged that they signed, sealed and delivered the said instrument as their free and voluntary act as such Vice-President and Trust Officer, respectively, and as the free and voluntary act of Chemical Bank for the uses and purposes therein set forth. IN WITNESS WHEREOF, I have hereunto subscribed my name and affixed my official seal on the day and year last above written. /s/ Robert J. Stanislaro ---------------------------- Notary Public [NOTARIAL SEAL] EXHIBIT A DESCRIPTION OF PROPERTY All land and interests in land subject to the lien of and referenced in the Mortgage and Deed of Trust, dated as of July 1, 1936, between Bangor Hydro-Electric Company and City Bank Farmers Trust Company (as predecessor to Citibank, N.A.), as supplemented and amended by duly recorded indentures supplemental thereto (and related real estate property descriptions) (the "1936 Mortgage") except land and interests in land which have been specifically released from such lien from time to time; and as originally recorded in the following places in the State of Maine: in Aroostook County Registry of Deeds, in Book 444, Page 130; in Hancock County Registry of Deeds, in Book 654, Page 79, in Penobscot County Registry of Deeds, in Book 1117, Page 3, in Piscataquis County Registry of Deeds, in Book 257, Page 241, in Washington County Registry of Deeds, in Book 418, Page 102; in Cumberland County Registry of Deeds, in Book 3957, Page 1; in Waldo County Registry of Deeds, in Book 786, Page 119; in the City Clerk's Office for the City of Bangor, in Book 19, Page 304; and in the Rockingham County Registry of Deeds in the State of New Hampshire, in book 2351, Page 203. Such land and interests in land are further described in certain supplemental indentures, dated respectively as of March 1, 1938, recorded in the Penobscot County Registry of Deeds in Book 1129, Page 380, in the Washington County Registry of Deeds in Book 426, Page 31, in the Hancock County Registry of Deeds in Book 661, Page 104, and in the Piscataquis County Registry of Deeds in Book 260, Page 119; January 17, 1939, recorded in the Penobscot County Registry of Deeds in Book 1134, Page 445, in the Washington County Registry of Deeds in Book 426, Page 198, in the Hancock County Registry of Deeds in Book 662, Page 302, and in the Piscataquis County Registry of Deeds in Book 260, Page 462; March 1, 1941, recorded in the Penobscot County Registry of Deeds in Book 1167, Page 226, in the Washington County Registry of Deeds in Book 437, Page 216, in the Hancock County Registry of Deeds in Book 679, Page 33, and in the Piscataquis County Registry of Deeds in Book 264, Page 441; February 11, 1942, recorded in the Penobscot County Registry of Deeds in Book 1177, Page 412, in the Washington County Registry of Deeds in Book 448, Page 14, in the Hancock County Registry of Deeds in Book 681, Page 591, and in the Piscataquis County Registry of Deeds in Book 272, Page 253; July 10, 1945, recorded in the Penobscot County Registry of Deeds in Book 1223, Page 382, in the Washington County Registry of Deeds in Book 463, Page 37, in the Hancock County Registry of Deeds in Book 700, Page 580, and in the Piscataquis County Registry of Deeds in Book 278, Page 171; July 8, 1947, recorded in the Penobscot County Registry of Deeds in Book 1268, Page 48, in the Washington County Registry of Deeds in Book 472, Page 457, in the Hancock County Registry of Deeds in Book 717, Page 119, and in the Piscataquis County Registry of Deeds in Book 290, Page 94; September 13, 1949, recorded in the Penobscot County Registry of Deeds in Book 1308, Page 446, in the Washington County Registry of Deeds in Book 488, page 57, in the Hancock County Registry of Deeds in Book 731, Page 11, and in the Piscataquis County Registry of Deeds in Book 294, Page 208; May 20, 1952, recorded in the Penobscot County Registry of Deeds in Book 1363, Page 193, in the Washington County Registry of Deeds in Book 515, Page 1, in the Hancock County Registry of Deeds in Book 749, Page 28, and in the Piscataquis County Registry of Deeds in Book 308, Page 35; January 8, 1981, recorded in the Waldo County Registry of Deeds in Book 788, Page 333; December 1, 1984, recorded in the Penobscot County Registry of Deeds in Book 3608, Page 117, in the Washington County Registry of Deeds in Book 1305, Page 209, in the Waldo County Registry of Deeds in Book 833, Page 100, in the Hancock County Registry of Deeds in Book 1521, Page 214, and in the Piscataquis County Registry of Deeds in Book 571, Page 448; March 15, 1989, recorded in the Penobscot County Registry of Deeds in Book 4408, Page 165, in the Washington County Registry of Deeds in Book 1565, page 289, in the Waldo County Registry of Deeds in Book 1086, Page 83, in the Hancock County Registry of Deeds in Book 1742, Page 486, and in the Piscataquis County Registry of Deeds in Book 715, Page 327; July 3, 1990, recorded in the Penobscot County Registry of Deeds in Book 4678, Page 205, in the Washington County Registry of Deeds in Book 1649, page 40, in the Waldo County Registry of Deeds in Book 776, Page 203, in the Hancock County Registry of Deeds in Book 1817, Page 360, and in the Piscataquis County Registry of Deeds in Book 776, Page 203; March 31, 1992, recorded in the Penobscot County Registry of Deeds in book 5037, Page 229, in the Washington County Registry of Deeds in Book 1762, Page 314, in the Waldo County Registry of Deeds in Book 1278, Page 298, in the Hancock County Registry of Deeds in Book 1924, Page 177, and in the Piscataquis County Registry of Deeds in Book 846, Page 14; October 22, 1992, recorded in the Penobscot County Registry of Deeds in Book 5192, Page 1, in the Washington County Registry of Deeds in Book 1808, Page 1, in the Hancock County Registry of Deeds in Book 2015, Page 209, and in the Piscataquis County Registry of Deeds in Book 873, Page 8; June 23, 1995, recorded in the Penobscot County Registry of Deeds in Book 5891, Page 41, in the Washington County Registry of Deeds in Book 2009, Page 98, in the Waldo County Registry of Deeds in Book 1539, Page 306, in the Hancock County Registry of Deeds in Book 2406, Page 122, and in the Piscataquis County Registry of Deeds in Book 991, Page 268. -----END PRIVACY-ENHANCED MESSAGE-----