10-K 1 b10k2000.txt 10K 2000 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, 2000 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.) 3 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 -------------------------- ----------------------- (7,363,424 shares outstanding at March 20, 2001) ------------------------------------------------ 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, 2001 of the voting stock held by non-affiliates of the registrant was $194.4 million. This Page Intentionally Left Blank FORM 10-K FOR THE FISCAL YEAR ENDED DECEMBER 31, 2000 PAGE ---- Cover Page 1 Index 3 PART I: ------ Items 1 through 2: Business; Properties 6 -General 6 -Certain Issues Facing the Company 8 -Construction Program 9 -Rates and Regulation 9 -Seabrook 10 -Joint Ventures 10 -Employees 11 -Power Supply Commitments 11 -Maine Yankee 12 -Environmental Matters 14 Item 3: Legal Proceedings 14 Item 4: Submission of Matters to a Vote of Security Holders 14 PART II: ------- Item 5: Market for Registrant's Common Equity and Related Stockholder Matters 15 Item 6: Selected Financial Data 17 Item 7: Management's Discussion and Analysis of Results of Operations and Financial Condition 19 Item 8: Financial Statements & Supplementary Data 34 -Consolidated Statements of Income 34 -Consolidated Balance Sheets 35 -Consolidated Statements of Capitalizations 37 -Consolidated Statements of Cash Flows 38 -Consolidated Statements of Common Stock Investment 39 -Notes to Consolidated Financial Statements 40 1) Nature of Operations and Summary of Significant Accounting Policies 40 2) Income Taxes 42 3) Common and Preferred Stock and Earnings Per Share 45 4) Lending Agreements and Monetization of Power Sale Contract 46 5) Postretirement Benefits 48 6) Jointly Owned Facilities and Power Supply Commitments 52 7) Recovery of Seabrook Investment and Sale of Seabrook Interest 62 8) Unaudited Quarterly Financial Data 63 9) Fair Value of Financial Instruments 63 10) Industry Restructuring and Rate Regulation 64 11) Proposed Merger Agreement with Emera 67 12) Construction of Facilities for Casco Bay Energy 68 13) Storm Damage 68 14) Derivative Financial Instruments 69 15) Contingencies 69 15) New Accounting Pronouncements 70 Report of Independent Accountants 71 Item 7A: Quantitative and Qualitative Disclosures about Market Risk 72 Item 9: Changes in and Disagreements with Audit Firms on Financial Disclosures 72 PART III: -------- Item 10: Directors and Executive Officers of the Registrant 72 Item 11: Executive Compensation 74 Item 12: Security Ownership of Certain Beneficial Owners and Management 76 Item 13: Certain Relationships and Related Transactions 78 PART IV: ------- Item 14: Exhibits, Financial Statement Schedules, and Reports on Form 8-K 79 Signatures 80 Schedule VIII - Reserve for Doubtful Accounts 81 EXHIBIT INDEX: ------------- Exhibits Filed Herewith 82 Exhibits Incorporated Herein by Reference 83 FORWARD LOOKING INFORMATION - In addition to the historical information contained herein, this report contains a number of statements that are "forward-looking" as defined in the Private Securities Litigation Reform Act of 1995. These statements are subject to certain risks and uncertainties that could cause actual results to differ materially from those anticipated in the forward-looking statements. Readers should not place undue reliance on forward-looking statements, which reflect management's view only as of the date hereof. The Company undertakes no obligation to publicly revise these forward-looking statements to reflect subsequent events or circumstances. Factors that might cause such differences include, but are not limited to, the proposed merger with Emera, future economic conditions, relationship with lenders, earnings retention and dividend payout policies, electric utility restructuring, developments in the legislative, regulatory and competitive environments in which the Company operates, and other circumstances that could affect revenues and costs. PART I ------ ITEMS 1 THROUGH 2 BUSINESS; PROPERTIES --------------------------------------- GENERAL ------- The Company is a public utility primarily engaged in the transmission and distribution of electric energy, with a service area of approximately 5,275 square miles having a population of approximately 192,000 people. The Company serves approximately 107,000 customers in portions of the counties of Penobscot, Hancock, Washington, Waldo, Piscataquis and Aroostook. The Company owns approximately 580 miles of transmission lines and approximately 4,500 miles of distribution lines to serve its customers. The Company owns a variety of customer and business information systems used to manage its business operations. Other properties consist of office, garage and warehouse facilities at various locations in its service area. The Company has three material wholly-owned subsidiaries, Bangor Var Co., Inc. ("Bangor Var Co."), Bangor Fiber Company, Inc. ("Bangor Fiber"), and Bangor Energy Resale, 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. For a further discussion of Bangor Var Co., see "Joint Ventures." Bangor Fiber was incorporated in 2000 to supply fiber optic communications cable to communications companies and cable service providers and other related activities. Finally, Bangor Energy Resale, Inc. was formed in 1997 as a special purpose vehicle to permit Bangor Hydro's use of a power sales agreement as collateral for a bank loan. For a further discussion of this transaction, see Note 4 to the Consolidated Financial Statements included in Item 8, below. With the implementation of competition in the electric utility industry starting March 1, 2000, and excluding the standard-offer service, the Company is no longer selling electricity to customers. The Company's T&D and stranded cost charges to customers, though, continue to be based on customers' electricity usage measured in kilowatt-hours (KWH). See "Certain Issues Facing the Company - Changes in the Electric Utility Industry and in Regulation," below, and Item 7, "Management's Discussion and Analysis of Results of Operations and Financial Condition - Recent Events Affecting The Electric Utility Industry And The Company - Implementation of Competition in Electric Utility Industry" and Note 10 to the Consolidated Financial Statements included in Item 8, below. In 2000, 32.0% of the Company's KWH sales were to residential customers, 33.3% were to commercial customers, 34.7% were to industrial customers and 0.5% were to other customers. For additional information concerning the Company's sales, see Item 6, "Selected Financial Data". 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. During 2000, however, the Company experienced its maximum peak electric demand during the summer months, with the peak of approximately 304.7 megawatts ("MW") occurring on September 1, 2000. The Company owns 7% of the common stock of Maine Yankee Atomic Power Company ("Maine Yankee"), which owns and, prior to its permanent closure in 1997, operated an 880 MW nuclear generating plant in Wiscasset, Maine. Maine Yankee, which had commenced commercial operation on January 1, 1973, is the only nuclear facility in which the Company has an ownership interest. The Company's equity ownership in the plant had entitled the Company to about 7% of the output pursuant to a cost-based power contract. Pursuant to a contract with Maine Yankee, the Company is obligated to pay its pro rata share of Maine Yankee's operating expenses, including 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" and Note 6 to the Consolidated Financial Statements included in Item 8, below. 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, the regional transmission and generation reliability organization for the New England region. On December 1, 1996, the members of NEPOOL, including the Company, entered into the 33rd Amendment to the NEPOOL Agreement which provided for a substantial restructuring of NEPOOL. This revised agreement, together with NEPOOL's Open Access Transmission Tariff were filed with the Federal Energy Regulatory Commission ("FERC") on December 31, 1996 and were subsequently approved. Pursuant to this restructuring, effective July 1, 1997 an independent system operator, ISO- New England, assumed oversight of the operations and integration of NEPOOL transmission and generation with respect to reliability and market operations. The intent of these changes in NEPOOL is to increase competition in the market for electric generation. The Company is subject to the regulatory authority of the Maine Public Utilities Commission ("MPUC") as to retail distribution rates, accounting, service standards, territory served, the issuance of securities and various other matters. The Company is also subject to the jurisdiction of the FERC as to certain matters, including 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. PROPOSED MERGER AGREEMENT WITH EMERA - On June 29, 2000, the Company entered into a definitive merger agreement with Emera of Halifax, Nova Scotia, pursuant to which Emera will acquire all of the outstanding shares of common stock of Bangor Hydro for US$26.50 per share in cash. After the closing of the merger, each of Bangor Hydro's outstanding warrants to purchase common stock will entitle the holder to receive US$26.50 in cash, less the exercise price. For a discussion of the common stock warrants, see Note 6 of the notes to the consolidated financial statements. The equity market value of the transaction is approximately $206 million. The transaction will take the form of a merger of Bangor Hydro with a U.S. corporate subsidiary to be formed by Emera. Upon completion of the merger, Bangor Hydro will be a wholly-owned subsidiary of Emera. Bangor Hydro's outstanding debt and preferred stock will not be affected by the transaction. The transaction is subject to a number of approvals, including the approval of Bangor Hydro's shareholders, which was accomplished on October 24, 2000, and regulatory approvals from the Maine Public Utilities Commission (MPUC), the Federal Energy Regulatory Commission (FERC), which occurred on January 5, 2001 and January 24, 2001, respectively, and the U.S. Securities and Exchange Commission (SEC) under the Public Utility Holding Company Act of 1935. Proceedings are pending at the SEC for what is anticipated to be the last major regulatory approval. The processes for all necessary regulatory approvals are expected to be complete in the first half of 2001. The MPUC order requires the Company to file an alternative rate plan with the MPUC within two months after the completion of the merger with Emera or June 30, 2001, whichever is earlier. CERTAIN ISSUES FACING THE COMPANY --------------------------------- LOSS OF MAJOR CUSTOMER - HoltraChem Manufacturing Company, a major user of the Company's transmission and distribution services, ceased production at its Orrington, Maine manufacturing facility in mid-October, 2000. For a discussion of the impact of this event on the Company see Item 7, "Management's Discussion and Analysis of Results of Operations and Financial Condition - Recent Events Affecting The Electric Utility Industry And The Company - Loss of a Major Customer." CHANGES IN THE ELECTRIC UTILITY INDUSTRY AND IN REGULATION - Pursuant to "An Act to Restructure the State's Electric Industry", enacted in 1997 by the Maine Legislature, effective March 1, 2000, the Company is no longer permitted to engage directly in the generation and sale of electric energy unless designated by the MPUC to provide so-called "standard offer" service. For the period March 1, 2000 through February 28, 2001 and again for the period March 1, 2001 through February 28, 2002, the MPUC ordered the Company to assume the responsibility to provide for standard offer service. See Item 7, "Management's Discussion and Analysis of Results of Operations and Financial Condition - Recent Events Affecting The Electric Utility Industry And The Company - Implementation of Competition in Electric Utility Industry" and Note 10 to the Consolidated Financial Statements included in Item 8, below. The Company will remain regulated as a provider of electricity transmission and distribution services. RATES AND REGULATION - See "Rates and Regulation", below, together with Note 10 to the Consolidated Financial Statements included in Item 8, below, for a discussion of recent and pending regulatory proceedings affecting the Company's rates and revenues. PERC POWER CONTRACT RESTRUCTURING - See Note 6 to the Consolidated Financial Statement included in Item 8, below, for a discussion of the effect on the Company of the restructuring of its power contract with Penobscot Energy Recovery Company ("PERC"). OTHER ISSUES - See Item 7, "Management's Discussion and Analysis of Results of Operations and Financial Condition - Recent Events Affecting The Electric Utility Industry And The Company" for a discussion of the effect of other significant issues and events on the Company. CONSTRUCTION PROGRAM -------------------- The Company's construction program consists of extensions and improvements of its transmission and distribution facilities, 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 approximately $45-50 million in the period 2001 through 2003. RATES AND REGULATION -------------------- RATE MATTERS - In February 2000, the Company received a final rate order from the MPUC setting its distribution and stranded cost rates effective March 1, 2000. The Company's total annual revenue requirement as set in the rate proceedings, including transmission, distribution and stranded, amounted to $103.2 million. The stranded cost recovery includes the decommissioning and other plant closure expenses for Maine Yankee. There were no write-offs of previously deferred costs based on the final rate order. In Maine, stranded costs are treated in the same manner as most other costs and may be included in calculations for prospective rate changes. Stranded costs represent approximately 40% of the Company annual cost of service, although this amount is expected to decline over time. The MPUC is required to review and reevaluate the stranded cost recovery no less frequently than every three years. Customers reducing or eliminating their consumption of electricity by switching to self-generation, conversion to alternative fuels or utilizing demand-side management measures cannot be assessed exit or entry fees. On February 26, 2001, the FERC issued an Order approving transmission rates for the Company. Pursuant to federal policy, upon implementation of retail electric service unbundling as part of the electric industry restructuring scheme enacted by the State of Maine, rates for retail transmission service became subject to FERC jurisdiction. Costs relating to the provision of transmission service represent approximately 10% of the Company's annual cost of service. Under the FERC Order approving new transmission rates, a "formula" rate was approved, allowing the Company to adjust its rates annually to reflect changes in the Company's costs and its sales volume during the preceding calendar year. As part of its Order dated December 18, 2000 approving the Company's proposed merger with Emera, the MPUC required the Company to propose no later than June 30, 2001 an Alternative Rate Plan to govern distribution rates. In recent years, the MPUC has indicated a preference for alternative forms of rate regulation. The Company was previously subject to such a ratemaking scheme from 1998 to 2000. OTHER REGULATION - The MPUC regulates numerous other matters affecting the Company, including financing, construction of transmission facilities, credit and 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 or nonoperating licenses have already been issued, or impose new conditions on such permits or licenses. The FERC regulates rates for transmission services and rates for sales of electricity to other utilities. 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 -------------- NEPOOL/HYDRO-QUEBEC - 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. See Note 6 to the Consolidated Financial Statement included in Item 8, below BANGOR VAR CO. - In 1990, the Company formed Bangor Var Co., whose sole function is to be a 50% general partner in Chester SVC Partnership ("Chester"), a partnership which owns a static var compensator (SVC), which is electrical equipment that supports the Phase 2 transmission line. See Note 6 to the Consolidated Financial Statement included in Item 8, below. MEPCO - The Company owns 14.2% of the common stock of Maine Electric Power Company ("MEPCO"). MEPCO owns and operates electric transmission facilities from Wiscasset, Maine, to the Maine-New Brunswick border. See Note 6 to the Consolidated Financial Statement included in Item 8, below EMPLOYEES --------- At December 31, 2000, the Company had 427 full time employees approximately 48% of whom were represented by a local union affiliated with the International Brotherhood of Electrical Workers (AFL-CIO). The present collective bargaining agreement with union employees expires December 31, 2004. The Company believes that its relations with its employees are satisfactory. POWER SUPPLY COMMITMENTS ------------------------ COMPANY-OWNED GENERATION - As part of the electric industry restructuring process in the State of Maine, on May 27, 1999, the Company completed the sale of most of its electric generating assets and certain transmission rights to PP&L Global, Inc. The Company continues to own eleven internal combustion generation units located at three stations having a total capacity of 21 MW. These units are used to provide voltage support for the Company's local transmission and distribution system, as needed, and to provide generating capacity to serve the Company's power sales contract with UNITIL Power Corp., a New Hampshire based electric utility, with a contract term ending in the year 2003. 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 As part of the electric industry restructuring process in the State of Maine, in late 1999, the Company entered into a contract to sell the output of these contracts to Morgan Stanley Capital Group, a subsidiary of Morgan Stanley Dean Witter & Company, for a two year period. Also a part of the transaction are all of the energy and capacity from several smaller agreements with Pumpkin Hill, Milo, Green Lake and Sebec Hydro. See Note 6 to the Consolidated Financial Statements included in Item 8, below. For the period March 1, 2001 through February 28, 2002, the MPUC has ordered the Company to assume the responsibility for providing standard offer service. See Item 7, "Management's Discussion and Analysis of Results of Operations and Financial Condition - Recent Events Affecting The Electric Utility Industry And The Company - Implementation of Competition in Electric Utility Industry" and Note 10 to the Consolidated Financial Statements included in Item 8, below. The Company intends to meet its obligations through short and intermediate term contracts and spot market purchases, a strategy that has been approved by the MPUC. MAINE YANKEE ------------ GENERAL - The Company owns 7% of the common stock of Maine Yankee, which owns and, prior to its permanent closure in 1997, operated an 880 MW nuclear generating plant in Wiscasset, Maine. Maine Yankee, which had commenced commercial operation on January 1, 1973, is the only nuclear facility in which the Company has an ownership interest. The Company's equity ownership in the plant had entitled the Company to about 7% of the output pursuant to a cost-based power contract. Pursuant to a contract with Maine Yankee, the Company is obligated to pay its pro rata share of Maine Yankee's operating expenses, including 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. PERMANENT SHUTDOWN OF THE MAINE YANKEE PLANT - On August 6, 1997, the Board of Directors of Maine Yankee voted to permanently cease power operations at Maine Yankee and to begin decommissioning the plant. See Note 6 to the Consolidated Financial Statement included in Item 8, below. MAINE YANKEE RATE CASE SETTLEMENT - See Note 6 to the Consolidated Financial Statement included in Item 8, below. TERMINATION OF DECOMMISSIONING OPERATIONS CONTRACT - See Note 6 to the Consolidated Financial Statement included in Item 8, below. LOW-LEVEL WASTE DISPOSAL. The federal Low-Level Radioactive Waste Policy Amendments Act, enacted in 1986, required states either alone or in multistate compacts to provide for the disposal of low-level radioactive waste generated within their borders. The states of Maine, Texas and Vermont entered into a compact for the disposal of low-level waste over a 30-year period at a then-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. As a possible alternative, the states could agree to a financing arrangement for the payment, in which case Maine Yankee's share, along with interest, could be paid out over an extended period of time. 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 bill providing for ratification of the compact was approved by Congress in September 1998. However, in October 1998 the Texas Natural Resource Conservation Commission denied a permit for the proposed west Texas site, and construction of such a facility in Texas is uncertain. Maine Yankee expects the Texas Legislature to consider low-level waste issues at its session that convened in January 2001. Maine Yankee is currently shipping its low-level waste to other facilities licensed to accept this material. Maine Yankee is unable to predict whether or when a facility in Texas will be licensed and built or whether or when the State of Maine will assess any payments required under the compact. NUCLEAR INSURANCE. The Price-Anderson Act is a federal statue providing, among other things, a limit on the maximum liability for damages resulting from a nuclear incident. Coverage for the liability is provided for by existing private insurance and retrospective assessments for costs in excess of those covered by insurance, up to $88.1 million for each reactor owned, with a maximum assessment of $10 million per reactor in any year. However, after appropriate exemptive action by the NRC Maine Yankee, and therefore its sponsors, are not responsible for retrospective assessments resulting from any event or incident occurring after January 7, 1999. SPENT FUEL - Maine Yankee's spent fuel is currently stored in the spent fuel pool at the plant site. Federal legislation enacted in 1987 directed the 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 provided for the possible development of a Monitored Retrievable Storage ("MRS") facility and abandoned 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. The DOE has indicated that the permanent disposal site is not expected to open before 2010, although originally scheduled to open in 1998. In November 1997 the U.S. Court of Appeals for the District of Columbia Circuit confirmed the DOE's obligation under the Nuclear Waste Policy Act of 1982 to take responsibility for spent nuclear fuel in 1998. After an unsuccessful effort by Maine Yankee in the same court to compel the DOE to take Maine Yankee's spent fuel, in June 1998 Maine Yankee filed a claim for money damages in the U.S. Court of Federal Claims for the costs associated with the DOE's failure to begin to take fuel in 1998. In November 1998 the Court granted summary judgment in favor of Maine Yankee, ruling that the DOE had violated its contractual obligations, but leaving the amount of damages incurred by Maine Yankee for later determination by the Court. Since then the parties have been engaged in discovery and resolving pre-trial issues in the damages phase of the proceeding. Maine Yankee is continuing to pursue its claim for damages vigorously, but cannot predict the outcome of its claim. At the same time, as an interim measure until the DOE meets its contractual obligations to dispose of Maine Yankee's spent fuel, the Company is proceeding with construction of an independent spent fuel storage installation on the plant site. HAZARDOUS SUBSTANCE SITE - Maine Yankee has been notified by the Maine Department of Environmental Protection ("DEP") that it is one of many potentially responsible parties under the Maine Uncontrolled Hazardous Substance Sites law for having arranged for the transport of hazardous substances to sites owned by the Portland Bangor Waste Oil Company that have been designated uncontrolled hazardous substance sites by the DEP. Under the Maine law, each responsible party is jointly and severally liable for costs associated with the abatement, cleanup or mitigation of the hazards at such a site. Since the investigations by the DEP and Maine Yankee are in their early stages and a large number of potentially responsible parties are involved, the Company cannot now predict the amount of costs that Maine Yankee will ultimately be required to assume. Environmental costs that are unrelated to the decommissioning and dismantlement of the plant site could generally be considered to be operation and maintenance costs to be recovered through Maine Yankee's billing process. Site characterization work at the plant site, an initial part of the decommissioning process, and related activities could give rise to additional environmental issues. ENVIRONMENTAL MATTERS --------------------- See Item 7, "Management's Discussion and Analysis of Results of Operations and Financial Condition - Contingencies and Disclosures About Market Risk" for a discussion of Environmental Matters. ITEM 3 LEGAL PROCEEDINGS ------ ----------------- See Note 14 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, 2000, there were 6,222 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 Declared Fiscal Period High Low Per Share ------------- ---- --- --------- 1999 ---- First Quarter................ $14 5/16 $12 9/16 $.00 Second Quarter............... 16 3/8 11 7/8 .15 Third Quarter................ 16 15/16 15 3/4 .15 Fourth Quarter............... 17 5/16 15 .15 2000 ---- First Quarter................ $17 3/8 $12 9/16 $.20 Second Quarter............... 24 7/16 14 3/8 .20 Third Quarter................ 24 1/2 23 5/16 .20 Fourth Quarter............... 25 3/4 24 3/16 .20 2001 ---- First Quarter (through March 20, 2001).. $26 1/8 $25 1/4 $.20 Approximately 84% of the outstanding shares of common stock are registered in the "street names" of depositories and brokers for the benefit of their clients who are unknown to the Company. Therefore, the actual number of stockholders at any given time, including these "beneficial owners," is likely to be substantially greater than the number of holders shown on the Company's records. The Company's credit agreements with its lending banks and the Finance Authority of Maine contain a number of covenants keyed to the Company's financial condition and performance. One such covenant currently prohibits the Company from paying dividends on or make certain other defined payments with respect to its common stock, including repurchases of equity securities, of more than 60% of its earnings applicable to common stock during any calendar year. In addition, pursuant to the definitive merger agreement with Emera dated June 29, 2000, the Company may not increase the rate of dividends on common stock to more than $.25 per share per quarter. This Page Intentionally Left Blank BANGOR HYDRO-ELECTRIC COMPANY Item 6 Selected Financial Data Six-Year Statistical Summary (Unaudited)
2000 1999 1998 1997 1996 1995 Megawatt Hours (MWH) Generated And Purchased Hydro Generation (Company) 90,719 205,265 275,379 262,377 321,532 275,810 Nuclear Generation (Maine Yankee) - - - - 348,719 13,606 Oil (Company) 3,142 69,026 96,476 69,580 26,912 50,706 Biomass/Refuse 152,060 137,384 156,051 159,990 163,279 177,558 NEPOOL/Other Purchases 1,914,615 1,629,643 1,522,125 1,583,093 1,359,116 1,540,530 --------- --------- --------- --------- --------- --------- Total Generated & Purchased 2,160,536 2,041,318 2,050,031 2,075,040 2,219,558 2,058,210 Less Line Losses and Company Use 140,470 143,198 139,028 147,298 141,426 140,128 --------- --------- --------- --------- --------- --------- Remainder-MWH sold 2,020,066 1,898,120 1,911,003 1,927,742 2,078,132 1,918,082 ========= ========= ========= ========= ========= ========= Classification of Sales-MWH Residential 558,596 533,566 522,836 533,161 536,490 513,076 Commercial 570,963 545,087 524,292 515,904 508,331 507,243 Industrial 604,959 667,059 662,382 687,365 652,087 690,863 Lighting 8,859 8,911 8,901 8,780 8,945 9,547 Wholesale 2,799 2,716 2,704 3,841 4,486 10,961 --------- --------- --------- --------- --------- --------- Total MWH Billed to Customers 1,746,176 1,757,339 1,721,115 1,749,051 1,710,339 1,731,690 Unbilled Sales-Net Increase (Decrease) 2,629 11,772 1,040 33,011 2,998 4,658 --------- --------- --------- --------- --------- --------- Total Delivered Sales (MWH) 1,748,805 1,769,111 1,722,155 1,782,062 1,713,337 1,736,348 (Less) Interruptible Sales 78,943 230,378 248,091 265,438 237,553 295,818 --------- --------- --------- --------- --------- --------- Total Firm Delivered Sales (MWH) 1,669,862 1,538,733 1,474,064 1,516,624 1,475,784 1,440,530 Off-System Sales 271,261 129,009 188,848 145,680 364,795 181,734 --------- --------- --------- --------- --------- --------- Total Energy Sales (MWH) 2,020,066 1,898,120 1,911,003 1,927,742 2,078,132 1,918,082 ========= ========= ========= ========= ========= ========= Electric Operating Revenues and Expenses (000's) Electric Operating Revenues Residential $ 57,746 $ 73,304 $ 71,396 $ 67,532 $ 66,805 $ 66,061 Commercial 44,329 63,093 60,191 55,391 54,010 54,702 Industrial 23,749 43,560 42,645 41,930 39,105 40,257 Lighting 1,929 2,268 2,207 2,065 2,032 2,051 Wholesale 63 220 235 310 314 859 ----------- ------------ ------------ ------------ ------------ ------------ Total Revenue from Customers $ 127,816 $ 182,445 $ 176,674 $ 167,228 $ 162,266 $ 163,930 Standard Offer Service Revenue 56,657 - - - - - Total Operating Revenue $ 184,473 $ 182,445 $ 176,674 $ 167,228 $ 162,266 $ 163,930 ----------- ------------ ------------ ------------ ------------ ------------ Unbilled Sales-Net Increase (Decrease) 1,651 2,042 481 2,375 408 210 ----------- ------------ ------------ ------------ ------------ ------------ Total Revenue $ 186,124 $ 184,487 $ 177,155 $ 169,603 $ 162,674 $ 164,140 (Less) Interruptible Revenue 4,973 10,049 11,064 11,215 9,537 11,149 ----------- ------------ ------------ ------------ ------------ ------------ Total Firm Revenue $ 181,151 $ 174,438 $ 166,091 $ 158,388 $ 153,137 $ 152,991 Off-System Revenue 19,352 12,947 14,630 13,615 18,384 14,098 ----------- ------------ ------------ ------------ ------------ ------------ Total Electric Operating Revenues $ 205,476 $ 197,434 $ 191,785 $ 183,218 $ 181,058 $ 178,238 =========== ============ ============ ============ ============ ============ Operating Expenses Fuel for Generation and Purchased Power $ 44,144 $ 80,748 $ 82,027 $ 92,792 $ 78,477 $ 98,684 Standard Offer Service Purchased Power 65,553 - - - - - Operating and Maintenance Expense 37,212 36,492 34,448 32,471 32,441 35,711 Depreciation and Amortization 26,776 30,565 31,891 35,104 29,965 20,544 Taxes 12,228 14,032 11,642 3,168 10,249 6,306 ----------- ------------ ------------ ------------ ------------ ------------ Total Operating Expenses $ 185,913 $ 161,837 $ 160,008 $ 163,535 $ 151,132 $ 161,245 =========== ============ ============ ============ ============ ============ Summary of Operations (000's) Operating Revenue $ 212,338 $ 197,994 $ 195,144 $ 187,324 $ 187,374 $ 184,914 Operating Expenses 185,913 161,837 160,008 163,535 151,132 161,245 Other Income (including equity AFDC) 613 2,806 1,292 1,292 1,466 760 Interest Expense (net of borrowed AFDC) 15,936 20,683 24,963 25,467 26,425 20,092 ----------- ------------ ------------ ------------ ------------ ------------ Net Income (Loss) $ 11,102 $ 18,280 $ 11,465 $ (386)$ 11,283 $ 4,337 Less Preferred Dividends 266 945 1,244 1,376 1,537 1,702 ----------- ------------ ------------ ------------ ------------ ------------ Earnings (Loss) on Common Stock $ 10,836 $ 17,335 $ 10,221 $ (1,762)$ 9,746 $ 2,635 =========== ============ ============ ============ ============ ============ Selected Financial Data Total Assets (000's) $ 532,220 $ 543,950 $ 605,688 $ 600,583 $ 556,629 $ 566,076 Electric Plant (000's) Total Electric Plant $ 327,247 $ 318,435 $ 372,782 $ 358,878 $ 341,526 $ 323,664 Depreciation Reserve 86,684 84,825 101,633 96,595 87,736 81,934 ----------- ------------ ------------ ------------ ------------ ------------ Net Electric Plant $ 240,563 $ 233,610 $ 271,149 $ 262,283 $ 253,790 $ 241,730 =========== ============ ============ ============ ============ ============ Capitalization (000's) Short-Term Debt $ - $ - $ 12,000 $ 34,000 $ 32,500 $ 35,000 Long-Term Debt 161,960 183,300 263,028 221,643 274,221 288,075 Redeemable Preferred Stock - - 7,604 9,137 10,670 12,070 Preferred Stock 4,734 4,734 4,734 4,734 4,734 4,734 Common Equity 137,420 132,722 118,864 106,558 108,321 103,192 ----------- ------------ ------------ ------------ ------------ ------------ Total $ 304,114 $ 320,756 $ 406,230 $ 376,072 $ 430,446 $ 443,071 =========== ============ ============ ============ ============ ============ Capital Structure Ratios (%) Short-Term Debt - % - % 3.0 % 9.1 % 7.5 % 7.9 % Long-Term Debt 53.2 % 57.1 % 64.7 % 58.9 % 63.7 % 65.0 % Preferred Stock 1.6 % 1.5 % 3.0 % 3.7 % 3.6 % 3.8 % Common Stock 45.2 % 41.4 % 29.3 % 28.3 % 25.2 % 23.3 % ----------- ------------ ------------ ------------ ------------ ------------ Total 100.0 % 100.0 % 100.0 % 100.0 % 100.0 % 100.0 % =========== ============ ============ ============ ============ ============ Miscellaneous Statistics Shares Outstanding (Average) 7,363,424 7,363,424 7,363,424 7,363,424 7,336,174 7,264,360 Shares Outstanding (Year End) 7,363,424 7,363,424 7,363,424 7,363,424 7,363,424 7,301,557 Number of Common Stockholders (Year End) 6,222 5,678 6,328 6,868 7,734 8,250 Basic Earnings (Loss) Per Common Share $ 1.47 $ 2.35 $ 1.39 $ (0.24) $ 1.33 $ 0.36 Diluted Earnings (Loss) Per Common Share $ 1.30 $ 2.08 $ 1.33 $ (0.24) $ 1.33 $ 0.36 Dividends Declared Per Common Share $ 0.80 $ 0.45 $ - $ - $ 0.72 $ 0.87 Book Value Per Common Share $ 18.66 $ 18.02 $ 16.14 $ 14.47 $ 14.71 $ 14.13 Return on Common Equity 7.98 % 13.81 % 9.11 % (1.64)% 9.09 % 2.51 % Ratio of AFDC to Common Stock Earnings 3 % (4)% 11 % (48)% 12 % 48 % Ratio of Earnings to Fixed Charges 2.11 % 2.25 % 1.59 % 0.86 % 1.50 % 1.14 % Payout Ratio 54 % 26 % - % - % 54 % 242 % Percentage of Construction Expenditures Funded Internally 100 % 100 % 100 % 100 % 100 % 86 % =========== =========== =========== =========== =========== =========== Residential Customer Data Average Number of Customers 92,656 91,726 90,888 90,433 89,769 86,194 Kilowatt-Hours per Customer 6,029 5,817 5,753 5,896 5,976 5,953 Revenue per Customer $ 623.23 $ 799.16 $ 785.54 $ 746.76 $ 744.19 $ 766.42 Revenue per Kilowatt-Hour in Cents 10.34 13.74 13.65 12.67 12.45 12.88 =========== ============ =========== =========== =========== =========== Miscellaneous System Data Net System Capability at Time of Peak (MW) Firm* 98.98 273.72 381.54 344.44 373.04 330.01 System Peak Demand (MW) 304.71 293.08 281.63 277.06 274.32 267.98 Reserve Margin at Time of Peak** (67.5)% (6.6)% 35.5 % 24.3 % 36.0 % 23.2 % System Load Factor 70.8 % 74.5 % 75.4 % 79.5 % 77.0 % 79.9 % =========== ============ =========== =========== =========== =========== * The net system capability was reduced in 2000 and 1999 as a result of the generation asset sale. ** While the reserve margin at time of peak in 2000 and 1999 was negative, the system requirements were met through spot market purchases.
ITEM 7 ------ MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION RECENT EVENTS AFFECTING THE ELECTRIC UTILITY INDUSTRY AND THE COMPANY --------------------------------------------------------------------- PROPOSED MERGER AGREEMENT WITH EMERA - On June 29, 2000, the Company entered into a definitive merger agreement with Emera of Halifax, Nova Scotia, pursuant to which Emera will acquire all of the outstanding shares of common stock of Bangor Hydro for US$26.50 per share in cash. After the closing of the merger, each of Bangor Hydro's outstanding warrants to purchase common stock will entitle the holder to receive US$26.50 in cash, less the exercise price. For a discussion of the common stock warrants, see Note 6 of the notes to the consolidated financial statements. The equity market value of the transaction is approximately $206 million. The transaction will take the form of a merger of Bangor Hydro with a U.S. corporate subsidiary to be formed by Emera. Upon completion of the merger, Bangor Hydro will be a wholly- owned subsidiary of Emera. Bangor Hydro's outstanding debt and preferred stock will not be affected by the transaction. The transaction is subject to a number of approvals, including the approval of Bangor Hydro's shareholders, which was accomplished on October 24, 2000, and regulatory approvals from the Maine Public Utilities Commission (MPUC), the Federal Energy Regulatory Commission (FERC), which occurred on January 5, 2001 and January 24, 2001, respectively, and the U.S. Securities and Exchange Commission (SEC) under the Public Utility Holding Company Act of 1935. Proceedings are pending at the SEC for what is anticipated to be the last major regulatory approval. The processes for all necessary regulatory approvals are expected to be complete in the first half of 2001. The MPUC order requires the Company to file an alternative rate plan with the MPUC within two months after the completion of the merger with Emera or June 30, 2001, whichever is earlier. The merger is part of Emera's strategy to grow its business beyond its current borders. Bangor Hydro will operate as a standalone division of Emera and will be the base for Emera to launch other initiatives. The companies will share best practices learned from their respective utility system operations. Emera is a diversified energy and services company, with about 440,000 customers and (Cdn)$2.9 billion in assets. It owns 100% of Nova Scotia Power, Inc., the primary electricity supplier in the province of Nova Scotia. Emera's energy product line also includes bunker oil, diesel fuel and light fuel oil, and the company has a 12.5% interest in the Maritimes & Northeast Pipeline, which delivers Sable Island natural gas to markets in Maritime Canada, and the northeastern United States. IMPLEMENTATION OF COMPETITION IN ELECTRIC UTILITY INDUSTRY - In connection with the state of Maine's electric industry restructuring law, effective March 1, 2000, consumers of electricity had the right to purchase generation services directly from competitive electricity suppliers. In February 2000, and in connection with the implementation of the restructuring law, the Company received a final rate order from the MPUC setting its transmission and distribution (T&D) and stranded cost rates effective March 1, 2000. The Company's total annual revenue requirement as set in the rate proceedings, including $40 million associated with stranded cost recovery, amounted to $103.2 million. The stranded cost recovery includes the decommissioning and other plant closure expenses for Maine Yankee. There were no write-offs of previously deferred costs based on the final rate order. In Maine, stranded costs are treated in the same manner as most other costs and may be included in calculations for prospective rate changes. Absent any rate proceedings, however, in 2003 and every three years thereafter until the stranded costs are recovered, the MPUC shall review and reevaluate the stranded cost recovery. Customers reducing or eliminating their consumption of electricity by switching to self- generation, conversion to alternative fuels or utilizing demand-side management measures cannot be assessed exit or entry fees. The electric utility industry restructuring and the Company's associated rate proceedings at the MPUC are discussed in more detail in the 1999 Form 10-K. As discussed in the 1999 Form 10-K, the restructuring law also provided for a standard-offer service being available for all customers who did not choose to purchase energy from a competitive supplier starting March 1, 2000. As a result of the bids from competitive energy suppliers to provide energy under the standard-offer service being higher than anticipated, and as ordered by the MPUC, the Company assumed the responsibility of being the standard-offer service provider starting March 1, 2000 for a one-year period. The MPUC established the schedule of rates the Company could charge for this service starting March 1, 2000. The Company entered into arrangements with third parties to purchase the energy to serve the standard-offer customers. The Company is allowed by the MPUC to defer the difference between revenues realized from the standard-offer sales and the costs incurred to provide this service, including carrying costs on the deferred balance. As a result of this reconciliation mechanism, standard-offer related revenues and expenses do not have any impact on the Company's earnings, although they do result in increases in both categories in the Company's consolidated statements of income. The deferred amount will be recovered from/returned to customers in the future. Since March 1, 2000, when new rates went into effect, the costs of providing the standard offer service have exceeded the revenues realized from customers, and consequently, the Company has recorded a regulatory asset of $3.1 million, including carrying costs, as of December 31, 2000 (which is included in Other regulatory assets on the Consolidated Balance Sheets). The excess of costs is due principally to unusually high purchased power costs for one day in May 2000, which is discussed below, and higher than anticipated spot energy market prices in the summer of 2000. As a result of the growth in the balance of this regulatory asset, the MPUC approved standard offer service rate increases for customers in each of August and October 2000. These rate increases were necessitated to avoid a deficiency in standard offer service revenues that the Company projected would otherwise result based on actual costs already incurred and projected costs through February 2001. In October 2000, the MPUC issued a Request for Proposal seeking firms willing to supply standard-offer service for the Company's service territory. In part because of rapidly changing conditions in the electricity markets, the MPUC did not receive any acceptable proposals. In December 2000 the MPUC directed the Company to explore power supply arrangement to assist the MPUC in fulfilling its obligation to provide standard-offer service. In February 2001, based on orders from the MPUC, the Company retained responsibility as the standard-offer service provider starting March 1, 2001. The MPUC initially set the standard- offer power supply price for small (residential and non-residential) and medium non-residential electric customers located in the Company's service territory for the period from March 1, 2001 through February 28, 2002 at a rate which is approximately 20% above the then current standard-offer price. The MPUC also set the standard-offer electric supply price for the Company's large customers for this same period at a rate approximately 29% above the then current standard-offer price. The MPUC also approved additional power contracts which the Company was able to procure at the request of the MPUC locking in prices for a portion of the projected standard-offer load over the next three years. The Company will continue to be allowed by the MPUC to defer the difference between revenues realized from the standard-offer sales and the costs incurred to provide this service, including carrying costs on the deferred balance. BANGOR GAS INVESTMENT - As discussed in the 1999 Form 10-K, the Company announced in late 1999 that it no longer intended to participate in the Bangor Gas Company, LLC (Bangor Gas) joint venture and intended to sell its joint venture interest. On July 13, 2000, the Company and Penobscot Natural Gas Company (Penobscot Gas), the Company's wholly- owned subsidiary which owned a 50% interest in Bangor Gas, completed a stock purchase agreement to sell the Company's interest in Penobscot Gas to Sempra Energy (Sempra). Sempra had owned the other 50% interest in Bangor Gas. As previously discussed, a one-time gain on the sale of Penobscot Gas of approximately $1.2 million was recognized in the third quarter of 2000 and is included as a component of Other Income in the Consolidated Statements of Income for the year ending December 31, 2000. The completion of this sale has no impact on the previously discussed proposed merger agreement with Emera. INCREASE IN COMMON STOCK DIVIDEND - On March 15, 2000 the Company's board of directors declared a cash dividend on its common stock of $.20 per share. The quarterly dividend represented a $.05 increase over the $.15 per share dividend declared in each of the prior three quarters. In June of 1999, the board of directors resumed payment of quarterly common stock dividends after having suspended them in March 1997 due to financial difficulties triggered by problems at the Maine Yankee nuclear generating plant. The Company has a 7% ownership interest in Maine Yankee, which was permanently shut down in 1997 and is now in the process of being decommissioned. MAINE YANKEE - TERMINATION OF DECOMMISSIONING OPERATIONS CONTRACT - As discussed in the 1999 Form 10-K, the Company owns 7% of the common stock of Maine Yankee, which owns and, prior to its permanent closure in 1997, operated an 880 megawatt nuclear generating plant (the Plant) in Wiscasset, Maine. Pursuant to a contract with Maine Yankee, the Company is obligated to pay its pro rata share of Maine Yankee's operating expenses, including decommissioning costs. On May 4, 2000, Maine Yankee notified its decommissioning operations contractor, Stone & Webster Engineering Corporation (Stone & Webster), that it was terminating the decommissioning operations contract pursuant to the terms of the contract. Stone & Webster subsequently notified Maine Yankee that it was disputing Maine Yankee's grounds for terminating the contract. On May 8, 2000, Stone & Webster announced a proposed transaction in which it would transfer substantially all of its assets in exchange for an immediate credit facility and other consideration, including cash and stock. Stone & Webster said that the credit facility was intended to enable it to address its liquidity difficulties and continue to operate its businesses until the asset sale was completed. Stone & Webster also announced that it intended to seek bankruptcy court approval of the asset sale and credit agreement. On June 2, 2000, Stone & Webster filed a voluntary petition under Chapter 11 of the U.S. Bankruptcy Code with the United States Bankruptcy Court for the District of Delaware. By Sale Order dated July 13, 2000, the Bankruptcy Court approved the sale of substantially all of Stone & Webster's assets to the successful bidder in the Chapter 11 sale, The Shaw Group, Inc. (Shaw), for cash, stock, and the assumption of certain liabilities of Stone & Webster, and the proposed transaction announced earlier by Stone & Webster was terminated. Stone & Webster reported that the Shaw transaction was effectively closed on July 14, 2000, and that it would continue to operate as a Debtor-in- Possession subject to the supervision and orders of the Bankruptcy Court. Commencing in May 2000, Maine Yankee entered into interim agreements with Stone & Webster in order to allow decommissioning work to continue and avoid the adverse consequences of an abrupt or inefficient demobilization from the Plant site. After obtaining assignments of several subcontracts from Stone & Webster, Maine Yankee temporarily assumed the general contractor role. The decommissioning of the Plant site continued throughout 2000, with major emphasis directed to maintaining the schedule of critical-path projects such as construction of the ISFSI and preparation of the Plant's reactor vessel for eventual shipment to an off-site disposal facility. During this period, Maine Yankee performed comprehensive assessment of its long-term alternatives for safely and efficiently completing the decommissioning, including evaluating detailed competitive-bid proposals from prospective successor general contractors. On January 26, 2001, Maine Yankee announced its decision to continue to manage the decommissioning project itself without an external general contractor. On June 30, 2000, Federal Insurance Company (Federal), which provided performance and payment bonds in the amount of approximately $37.6 million each in connection with the decommissioning operations contract, filed a Complaint for Declaratory Judgement against Maine Yankee in the United States Bankruptcy Court for the District of Delaware, which was subsequently transferred to the United States District Court in Maine. The Complaint, which seeks a declaration that Federal has no obligation to pay Maine Yankee under the bonds, alleges that Maine Yankee improperly terminated the decommissioning operations contract with Stone & Webster and failed to give proper notice of the termination to Federal under the contract, and that Federal therefore had no further obligations under the bonds. On August 24, 2000, Maine Yankee filed a $78.2 million claim in the Stone & Webster Bankruptcy Court proceeding in Delaware seeking to recover its additional costs caused by Stone & Webster's contract default. Maine Yankee expects the court hearings in both proceedings to take place later in 2001. Maine Yankee believes that its termination of the Stone & Webster contract was proper and that it is entitled to recover such additional costs in the bankruptcy proceeding or under the bonds, but cannot predict the outcome of the litigation. In connection with the state of Maine's electric industry restructuring law, the Company was allowed the recovery of Maine Yankee decommissioning costs as a component of its stranded costs. In the Company's rate order from the MPUC that became effective March 1, 2000, the Company was allowed to defer the amount of any future FERC ordered changes in Maine Yankee's decommissioning collections. Consequently, management does not believe that Maine Yankee's current decommissioning contractor difficulties will have a material adverse impact on the Company's results of operations, financial condition or cash flows. MAINE YANKEE REPLACEMENT POWER COSTS - As discussed in the 1999 Form 10-K, under the Maine Yankee settlement agreement, the Maine owners of Maine Yankee are required, for the period from March 1, 2000 through December 1, 2004, to hold Maine retail ratepayers harmless from the amounts by which the replacement power costs for Maine Yankee exceed the replacement power costs assumed in the report to the Maine Yankee board of directors that served as a basis for the plant shutdown decision. As part of a further settlement, the Company's liability was fixed at approximately $2.2 million to be reflected as a reduction in stranded costs effective March 1, 2002. The Company charged to fuel and purchased power expense and recorded as a regulatory liability $2 million in December 2000 representing the net present value of this future obligation. LOSS OF MAJOR CUSTOMER - On September 15, 2000 HoltraChem Manufacturing Company (HoltraChem) ceased production at its Orrington, Maine manufacturing facility and closed the facility in mid-October of 2000. HoltraChem, a manufacturer of caustic soda and chlorine, has been a major user of the Company's transmission and distribution services, and before the restructuring of the electric utility industry in Maine in March 2000, was a major purchaser of energy from the Company. For the 12 months ended August 31, 2000, the Company earned approximately $2.2 million pre-tax associated with the provision of transmission and distribution services to HoltraChem, or approximately 9% of the Company's total pre-tax income during that period. The previously discussed alternative rate plan filing required by the MPUC will likely address the loss of revenues from HoltraChem. OTHER - Management's discussion and analysis of results of operations and financial condition contains items that are "forward-looking" as defined in the Private Securities Litigation Reform Act of 1995. These statements are subject to certain risks and uncertainties that could cause actual results to differ materially from those anticipated in the forward-looking statements. Readers should not place undue reliance on forward-looking statements, which reflect management's view only as of the date hereof. The Company undertakes no obligation to publicly revise these forward-looking statements to reflect subsequent events or circumstances. Factors that might cause such differences include, but are not limited to, the Company's proposed merger agreement with Emera, future economic conditions, relationships with lenders, earnings retention and dividend payout policies, electric utility restructuring, developments in the legislative, regulatory and competitive environments in which the Company operates and other circumstances that could affect revenues and costs. LIQUIDITY, CAPITAL REQUIREMENTS, AND CAPITAL RESOURCES ------------------------------------------------------ The Consolidated Statements of Cash Flows reflect events for the years ended December 2000, 1999 and 1998 as they affect the Company's liquidity. Net cash provided by operations was $37.6 million in 2000, $47.4 million in 1999, and $30.9 million in 1998. Negatively impacting cash flows in the 2000 period was $3 million in previously discussed deferred costs associated with the Company providing standard-offer service to customers, as well as $1.4 million in deferred costs for the period from March 1, 2000 through December 31, 2000, associated with a deficiency in actual revenues realized from customers under special rate contracts as compared to the estimated revenues for these customers utilized in setting the Company's new electric rates starting March 1, 2000. The Company was granted a deferral mechanism for the differences in these revenues in its February 2000 rate order from the MPUC. Also negatively impacting cash flows in 2000 was the impact of a lower authorized return on equity of 11% ordered by the MPUC effective March 1, 2000 with the advent of the electric industry restructuring. Positively impacting cash flows from operations in the 1999 period was the receipt of a $1.75 million payment related to a terminated purchased power contract (See the 1999 Form 10-K). These decreases in cash flows from operations for 2000 as compared to 1999 were offset to some extent by a $5.8 million reduction in interest payments in 2000 principally as a result of long-term debt principal payments discussed below. Also the Company incurred $5.3 million in closing and selling costs associated with the generation asset sale in 1999. Positively impacting cash flows from operating activities in the 1999 period as compared to 1998 were the beneficial impacts of the 5.83% and 1.36% rate increases effective February 13, 1998 and June 1, 1999, respectively, $1.8 million received from the federal government in connection with service restoration costs associated with the major ice storm in January 1998 (see Note 13), a $1.75 million payment received in the first quarter of 1999 related to a terminated purchased power contract (see Note 6), a $2.9 million reduction in deferred Maine Yankee incremental costs in the 1999 period as compared to 1998, and a reduction in the Company's interest payments of $2.9 million in the 1999 period due principally to the long-term debt principal payments and reduction in borrowings on the Company's revolving credit facility in 1999. In addition, in the 1998 period, cash flows were reduced by $7.7 million in payments associated with restructuring the Penobscot Energy Recovery Company (PERC) purchased power contract as compared to $1.1 million in such payments in 1999 (see Note 6), were reduced by a $1.3 million due to the effect of a large customer who prepaid its electric usage for a one-year period in the third quarter of 1997, and were reduced by $4.2 million because of incremental costs incurred in 1998 in connection with the previously discussed ice storm. Offsetting the previously discussed cash flow enhancements in 1999 as compared to 1998 were an $8.2 million increase in state and federal income tax payments as a result of the gain on sale of generating assets for income tax purposes. In 1999 the Company recorded $5.3 million in cost deferrals associated with its generation asset sale as compared to $2.3 million of such costs in 1998 (see Note 10). The generation asset sale cost deferrals include the selling and closing costs associated with the sale, the costs incurred for the early retirement of long-term debt and preferred stock through the utilization of asset sale proceeds, income tax expense impacts associated with the asset sale gain, and the net expense associated with the sale of the generating assets and the simultaneous purchased power buyback agreement with PP&L. Also in 1999, the Company paid $3.3 million to holders of the PERC warrants in lieu of issuing shares of common stock (see Note 6). Over the last three years, capital expenditures have been $16.7 million in 2000, $20.3 million in 1999 and $18.2 million in 1998. In 2000, approximately $8.2 million of the capital expenditures were related to the Company's electric distribution system, $4.2 million was associated with the electric transmission system, $2.4 million was expended in connection with customer information system changes necessitated by the electric industry restructuring, and the remainder related to other general property and equipment, software, and internal combustion facilities. In 1999, approximately $8 million of the capital expenditures were related to the Company's electric distribution system, $5.6 million was associated with the electric transmission system and certain fiber optic equipment, $3.2 million was expended in connection with Y2K compliance and restructuring related activities, and the remainder related to other general property and equipment, software, and internal combustion facilities. In 1998, approximately $2.6 million of the capital expenditures were related to implementing new geographic and financial information systems, $.9 million were related to the Company's power production facilities, $7.3 million were for its distribution system, and $6.2 million were for its transmission system, with the remainder related to other general property and equipment and costs associated with the licensing of hydroelectric projects. The Company expects its capital expenditures to total between $45 and $50 million 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, in July 2000 the Company received $1.2 million in connection with the sale of Penobscot Gas. As discussed in the 1999 Form 10-K, the Company received approximately $79.6 million in proceeds related to its generation asset sale in late May 1999 and an additional $10 million in late July 1999 in connection with the sale of its wholly owned subsidiary, Penobscot Hydro Co., Inc. (Penobscot Hydro). Also impacting cash flows in 1999 and 1998 were Graham Station property sale proceeds. This sale is discussed in the 1999 Form 10-K. The $6.2 million in proceeds associated with the sale of this property were required to be deposited with a third party trustee in September 1998. In January 1999 the trustee released the $6.2 million to the Company, and the funds were utilized to repay outstanding medium term notes. As previously discussed, the increase in dividends paid on common stock in both 2000 and 1999 was a result of the reinstatement of the Company's common dividend in the second quarter of 1999, and the increase in the common dividend from $.15 to $.20 per share in March 2000. No common dividends were paid in 1998. The reduction in preferred dividends paid in 2000 resulted from the final redemption of the remaining outstanding 8.76% mandatory redeemable preferred stock in October 1999. The reduction in preferred dividends in 1999 as compared to 1998 resulted from the $1.5 million sinking fund payment made on the Company's 8.76% mandatory redeemable preferred stock in December 1998 and the final redemption in October 1999. In 2000 the Company made $19.5 million in repayments on long-term debt, including a $14 million principal payment at the end of June 2000 on the Finance Authority of Maine Revenue Notes and $5.5 million in payments on the $24.8 million medium term notes which are discussed below. In 1999 the Company made $85.8 million in repayments on long-term debt. The increase in repayments in 1999 was due principally to the utilization of generation asset sale proceeds. The Company made $3.7 million in principal repayments on the Company's 12.25% first mortgage bonds (which were fully repaid in August 1999); a $13.1 million principal payment at the end of June 1999 on the Finance Authority of Maine Revenue Notes; $4.7 million in payments on the $24.8 million medium term notes; principal repayments of $6.2 million and $38.8 million in January and June 1999, respectively, on the $45 million medium term notes which were issued on June 29, 1998; the full redemption of $15 million in outstanding 10.25% series first mortgage bonds in early July 1999; and the redemption of $4.2 million in outstanding variable rate Pollution Control Revenue Bonds in early September 1999. The Company made $1.8 million in sinking fund payments on its 12.25% first mortgage bonds in 1998. In the first quarter of 1998 the Company made the final $2.5 million payment on its 6.75% first mortgage bonds and made a $4 million principal repayment on its medium term notes. In June 1998 the Company made a $12.3 million principal payment on its Finance Authority of Maine Revenue Notes. Also, as previously discussed, in connection with the new credit agreement, the Company fully repaid its $30 million in outstanding medium term notes in June 1998. In 1998 the Company made $2.9 million in principal payments associated with the medium term notes issued in connection with the UNITIL Power Corp. (UNITIL) contract monetization (see Note 4). In connection with the monetization of the UNITIL contract, the Company issued $24.8 million in medium term notes on March 31, 1998. The Company's net proceeds from this issuance were $23.3 million, due to the requirement to deposit $1.5 million in a capital reserve fund for the final payment of principal and interest in 2002. Of the $23.3 million of proceeds received, the Company utilized $19 million to repay borrowings outstanding under its revolving credit facility. The remaining funds were utilized for the PERC purchased power contract restructuring transaction. Also, in June 1998 the Amended and Restated Revolving Credit and Term Loan Agreement provided a two-year term loan of $45 million. In 1999, through the use of generation asset sale proceeds, the Company redeemed the remaining outstanding 90,000 shares of its 8.76% mandatory redeemable preferred stock amounting to $9 million. As discussed in more detail in Note 3 to the Consolidated Financial Statements, the Company also made approximately $563,000 in payments to the institutional holder of the 8.76% series preferred stock related to a "make whole provision" under the preferred stock purchase agreement. Of this amount approximately $320,000 was recorded as a reduction of the deferred asset sale gain, while approximately $243,000 was recorded as a reduction in the 8.76% preferred stock balance. Also in 1998 the Company made a sinking fund payment of $1.5 million on this preferred stock and a $94,000 make whole provision payment. Capital and operating needs in 2000, 1999 and 1998 were met through internally generated funds, the Company's revolving credit line, generation asset sale proceeds in 1999, and, for 1998, the new medium term notes. As a result of the Amended and Restated Revolving Credit and Term Loan Agreement in 1998, these facilities should provide adequate borrowing capacity for the Company's operation, maintenance and construction funding requirements. The Company has approximately $133.3 million of first mortgage bonds and other long-term debt maturities in the period 2001-2005. RESULTS OF OPERATIONS --------------------- EARNINGS - Basic earnings per common share were $1.47, $2.35, and $1.39, for the years ended 2000, 1999 and 1998, respectively. Earned return on average common equity was 8% in 2000, 13.8% in 1999 and 9.1% in 1998. The relatively high level of earnings in 1999 as compared to 2000 was in part attributable to a number of one-time benefits amounting to approximately $.52 per share. The largest of these was a $1.5 million income tax benefit recorded in the fourth quarter of 1999 (approximately $.20 per common share) from the flow through of unamortized deferred investment tax credits and excess deferred income taxes associated with the 1999 sale of the Company's generation assets. Other one-time items for 1999 include a gain on the sale of a subsidiary as part of the mandatory divestiture of generation assets (approximately $.04 per common share after taxes) recorded in the third quarter of 1999. In the second quarter the Company recorded a one-time benefit of $896,000 ($.07 per common share after taxes) because of the settlement of a dispute related to the NEPOOL transmission rates, and in the first quarter the Company recorded a one-time benefit of $802,000 ($.07 per common share after taxes) due to the settlement by the NEPOOL of a contract dispute with Hydro-Quebec. Finally, in 1999 the Company participated in a major construction project for a third party unrelated to its core utility business. This activity, now completed, allowed the Company to charge some of its fixed costs directly to that third party resulting in a reduction to operation and maintenance expense and producing a benefit to 1999 earnings of $.14 per share after taxes. Several other major changes account for the difference between 2000 and 1999 earnings. The largest change is attributable to new rates implemented by order of the MPUC effective March 1, 2000 that reflect a lower authorized return on equity of 11% in Maine's restructured electric industry. Also affecting earnings in 2000 were costs billed to the Company associated with transmission constraints in New England ($.15 per common share after taxes), as well as the recognition of costs related to the proposed merger ($.24 per common share after taxes) with Emera, and a write-off associated with power costs to replace generation from the Maine Yankee nuclear power plant ($.16 per common share after taxes). Somewhat offsetting these charges to earnings was the previously discussed $1.2 million ($.10 per common share after taxes) gain on the sale of Penobscot Gas. Total revenues and expenses for the periods presented are difficult to compare because of changes associated with the introduction of retail competition effective March 1, 2000. Aside from the one-time items mentioned above, energy sales to the Company's non-contract customers increased by 3.4% over 1999 showing continued strength in the local economy. Results for 1999 compared favorably to those in 1998 in part because of the previously discussed one-time benefits to earnings in 1999. Aside from these benefits, improvement in 1999 earnings was also attributable to improved energy sales and to the fact that the February 1998 rate increase authorized by the MPUC was in effect for the entire year. REVENUES - With the previously discussed implementation of competition in the electric utility industry starting March 1, 2000, and excluding the standard-offer service, the Company is no longer selling electricity to customers. The Company's T&D and stranded cost charges to customers, though, continue to be based on customers' electricity usage measured in kilowatt-hours (KWH). Consequently, discussion related to electric operating revenues will continue to have a KWH sales, or hereafter referred to as "energy sales" component. Electric operating revenue increased by $14.3 million in 2000 as compared to 1999 due to several factors. Other revenues (not attributable to KWH sales) were approximately $12.7 million greater in 2000 as compared to 1999 due principally to four factors. First, as a result of the previously discussed deferral mechanism for the standard- offer service revenues and costs, the Company recorded additional revenue of $3 million in 2000 to recognize the standard-offer service expenses in excess of revenues. Off-system sales, which are sales related to power pool and interconnection agreements and resales of purchased power, were approximately $6.4 million higher in 2000 as a result of the Company's requirement to resell the capacity and energy from its six purchased power contracts pursuant to Chapter 307 of Maine's 1997 law restructuring the State's electric industry (See the Note 6 to the Consolidated Financial Statements for a more complete discussion). Also, primarily as a result of electric generators in the Company's service territory wheeling power over the Company's transmission lines and out of its service territory, the Company recorded approximately $1.8 million in higher transmission wheeling revenues in 2000 as compared to 1999. Finally, in 2000 the Company recorded approximately $1.4 million of revenues associated with the previously discussed deferral mechanism for special rate contracts. Total electric operating revenues attributable to energy sales were $1.6 million greater in 2000 than in 1999. Total energy sales were 1.2% or 20.3 million KWH's lower in 2000 as compared to 1999, largely attributable to reduced sales to the Company's largest special contract customers (64.5 million KWH reduction in energy sales and $6.9 million reduction in electric operating revenues). These reduced special contract customer sales and revenues were attributable to the previously discussed shutdown of Holtrachem on September 15, 2000, and sales to another large industrial customer in 2000. Sales to this customer, which contribute a relatively low profit margin to the Company, can vary greatly from year to year as they own self-generation facilities. Reduced revenues for this group of customers were also affected by certain of these large customers choosing a competitive electricity supplier starting March 1, 2000 (197.5 million KWH's or 62% of total large special contract energy sales for the period from March through December 2000) and not contributing to the Company's standard- offer service revenues. For those who have chosen standard-offer service, corresponding revenues have been impacted by the various associated rate changes in 2000 discussed below. Exclusive of the Company's largest special contract customers, total T&D and stranded cost revenues related to energy sales were $8.5 million higher in 2000 as compared to 1999 principally as a result of a 5.3% increase in energy sales and effect of various rate changes discussed below. As with the large special contract customers, certain non-special contract commercial customers have been able to purchase electricity from competitive energy providers starting in March 2000 (37 million KWH's or 3% of total non-special contract energy sales for the period from March through December 2000), and consequently, the Company's electric operating revenues have been reduced. The increased energy sales in 2000 were impacted by the previously discussed strength in the local economy and colder weather in 2000 as compared to 1999. As a result of the February 2000 rate order from the MPUC, the Company's overall rates, including the impact of the initial standard- offer prices, were reduced by approximately 2.9% starting March 1, 2000. The Company has also implemented various rate changes for its standard-offer service as approved by the MPUC. The result of these standard-offer rate changes for the period from March 1 through October 1, 2000 was an increase in the standard-offer prices of 36% for residential and small commercial customers and 25% for large industrial customers as compared to the prices when initially set by the MPUC on March 1, 2000. Electric operating revenue for 1999 increased by $2.9 million as compared to 1998 due principally to the impact of the previously discussed rate increases on February 13, 1998 and June 1, 1999, and an overall 2.7% increase in energy sales (excluding off-system sales, which are sales related to power pool and interconnection agreements and resales of purchased power) in the 1999 period. The increase in energy sales in 1999 was affected by service interruptions during the ice storm in January 1998, slightly colder weather in the winter and spring of 1999, and warmer weather during the summer months of 1999 as compared to 1998. The increased revenues were offset by a $1.7 million reduction in off-system sales in the 1999 period and a $1.8 million reduction in revenue sharing from the Company's largest industrial customer. EXPENSES - Fuel for generation and purchased power expense increased $28.9 million in 2000 as compared to 1999. Total power purchases in 2000 were fairly consistent with those in 1999 due to the Company continuing to fulfill its long-term power purchase contract obligations subsequent to the implementation of the electric industry restructuring on March 1, 2000 and also procuring power to serve the standard-offer load. In 2000, though, the Company purchased significantly more power on the spot power market as compared to 1999 as a result of having less power contracts than in place in 1999. These factors resulted in higher fuel and purchased power costs in 2000. With more of the Company's power purchases being made in the spot power market in 2000, the price of the power was negatively affected by very high oil prices in 2000 and new market rules implemented by NEPOOL in May 1999, which set prices for replacement purchases from the pool at market levels related to supply and demand as opposed to actual marginal fuel costs. Also impacting power cost increases in each year were very unusual circumstances in NEPOOL for one day in each of the respective years, with record-breaking loads occurring while many generators were still out of service on spring maintenance. The result was on-peak power prices that, for the June 1999 event were two to three times as great as would normally occur during June. However, the May 2000 event resulted in prices that were approximately five times as high as the prices paid on the day in June 1999. The Company incurred approximately $2 million more in purchased power costs on the day in 2000 as compared to the day in 1999. In connection with the previously discussed standard-offer service deferral mechanism, the high power costs for the day in May 2000 have been deferred and are recoverable from customers in the future. Increased fuel and purchased power expense was also impacted by higher ISO New England (ISO) expenses in 2000 as compared to 1999, due to the implementation of NEPOOL new market rules in May 1999 and $1.9 million in previously discussed ISO costs in 2000 associated with transmission constraints. Also increasing fuel and purchased power expense in 2000 was $2 million charged to expense in connection with the previously discussed write-off associated with power costs to replace generation from the Maine Yankee nuclear power plant. The increased expense in 2000 as compared to 1999 was also due to the previously discussed settlement of the dispute with HQ which resulted in a $747,000 reduction in expense in the first quarter of 1999, and the settlement of a dispute related to NEPOOL, which resulted in a $896,000 reduction in expense in the second quarter of 1999. Fuel for generation and purchased power expense decreased $1.3 million in 1999 as compared to 1998. The decreased expense was a result of several factors. The previously discussed settlements of the disputes with Hydro-Quebec and NEPOOL resulted in $747,000 and $896,000 reductions in expense, respectively in 1999. The Company recorded a benefit of $2.9 million in 1999 as compared to $2 million for 1998 related to savings realized from the restructuring of the PERC purchased power contract in June 1998. The $1.7 million reduction in off-system sales in 1999 also impacted the decrease in fuel and purchased power expense. Excluding the impact of the previously discussed unusually high replacement power costs incurred in June 1999, there was a reduction in oil-related and other purchased power costs in the 1999 period as compared to 1998. A significant portion of the Company's power contracts are directly tied to the price of residual oil, which was 34% higher in 1999 as compared to 1998. However, the Company had hedged these purchases through its fuel risk management program with a fixed price about 13% lower in 1999 compared to 1998 (see Note 13 for a discussion of the Company's fuel risk management program). As a result, the Company received approximately $1.8 million in hedge settlements in 1999 as compared to paying out $5.1 million in hedge settlements in 1998. Any hedge settlement receipts/payments offset corresponding increases/decreases in purchased power costs. Also, prior to the generation asset sale at the end of May 1999, purchased power expenses were reduced by an increase in power generation by the Company's hydroelectric facilities. Purchased power expenses increased by about $3.2 million in the 1999 period due to the May 27th sale of the Company's hydroelectric facilities and subsequent buyback contract with PP&L for the power from the plants. Incremental replacement power costs for other entitlements in Wyman #4, Hydro-Quebec and MEPCO transmission were $3.6 million greater than the comparable 1998 expense. June 1999 replacement power costs were extremely high due to the previously discussed very unusual circumstances in NEPOOL, with record-breaking loads while many generators were still out of service on spring maintenance. Further, the NEPOOL new market rules resulted in on-peak power prices that were two to three times as great as would normally occur during June. Other operation and maintenance (O&M) expense increased by approximately $720,000 in 2000 as compared to 1999. Increasing other O&M expense in 2000 was a $1.7 million increase in O&M payroll due principally to less labor in 2000 being charged to capital projects as compared to 1999 as a result of less construction activity in 2000, and the impact of a 4% wage rate increase for bargaining unit employees on January 1, 2000 and various wage rate increases for non-bargaining unit employees. Further increasing other O&M in 2000 was the amortization expense of approximately $680,000 associated with incremental costs deferred in connection with the implementation of the electric utility industry restructuring (see Note 10 to the Consolidated Financial Statements). Recovery of the cost deferrals was allowed in rates in the Company's February 2000 rate order from the MPUC over a three year period starting March 1, 2000. Decreasing other O&M expense in 1999 was a $706,000 increase in overhead expenses allocated to capital projects. This increased overhead allocation in 1999 was principally a result of major construction activities being performed by the Company in connection with the Maine Independence Station, a new 520 megawatt gas fired generation facility in Veazie, Maine, which has subsequently become operational and is connected to the regional transmission power grid. The Company was reimbursed by the owner of the facility for the construction costs incurred, including overhead expense. Offsetting these increases to some extent in 2000 was a $1.3 million decrease in incremental expenditures related to electric utility industry restructuring activities, costs associated with assessment and testing of systems for year 2000 compliance, and an upgrade to the Company's customer information system which was completed in May 1999. Also reducing other O&M expense in 2000 was a decrease in pension and other postretirement benefit expense of $1 million, resulting principally from plan amendments in 1999 and changes in actuarial assumptions. Other O&M expense increased by $2 million in 1999 as compared to 1998. Increasing other O&M expense in 1999 was a $1.7 million increase in postretirement and active medical costs (due principally to higher medical claims costs) and pension expense; the Company incurred approximately $826,000 of additional incremental non-labor expenditures in 1999 as compared to 1998 related to electric utility industry restructuring activities (net of the previously discussed deferral in 1999), costs associated with Y2K compliance, and an upgrade to the Company's customer information system; the Company recorded $671,000 of amortization expense associated with deferred ice storm costs for the period from June 1 through December 31, 1999; the Company incurred $497,000 in additional employee incentive bonus expense in 1999 as a result of attaining a greater level of targeted goals in 1999, and the Company incurred approximately $410,000 in increased outside legal services expense in 1999 as compared to 1998, with much of the increase attributable to FERC and NEPOOL issues. Offsetting the increases in other O&M expense to some extent was a $1.7 million increase in overhead expenses allocated to capital projects in 1999 as compared to 1998. This increase was principally a result of the previously discussed major construction activities being performed by the Company in connection with the Maine Independence Station. Also, in 1999 there was a $730,000 reduction in hydroelectric and Wyman #4 non-labor O&M expenses as a result of the generation asset sale in late May 1999. Depreciation and amortization expense increased $1.1 million in 2000 as compared to 1999 due principally to two factors, the first being additions to the Company's electric plant in service. Also increasing depreciation expense in 2000 was the effect of a depreciation study conducted in December 1996, which determined that the Company's reserve for depreciation was overaccumulated by approximately $3.6 million. In connection with the MPUC's rate order in February 1998, the Company was allowed to amortize this balance over a two-year period, starting in February 1998. The amortization was increased in June 1999 as a result of the Company's generation asset sale. See Note 1 to the Consolidated Financial Statements for a complete discussion of this transaction. The amortization recorded as a reduction in depreciation expense in 1999 amounted to $2.2 million as compared to $308,000 of amortization in 2000. Depreciation and amortization expense decreased $1.7 million in 1999 as compared to 1998 due principally to the sale of the Company's generation assets in May 1999. This reduction was offset somewhat by the impact of 1999 property additions. The Company's expenses over the period 1998-2000 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 electric 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 to collect these amounts 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 abandoned investment in the Seabrook nuclear project 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 1985, 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 purchased power contract termination at a rate of $3.9 million annually over a nine-year period. With the July 1, 1997 temporary rate increase, the MPUC required the Company to accelerate the amortization of this deferred regulatory asset. Effective December 12, 1997, the MPUC ordered the amortization of this regulatory asset to be returned to the level before the temporary rate order. Effective with the rate order in February 1998, the amortization was reduced, so that the unamortized balance of the regulatory asset would be the same as under the original amortization schedule as of March 1, 2000. Consequently, as a result of the rate orders, amortization associated with this regulatory asset was $3.7 million in 2000, $2.8 million in 1999 and $2.9 million in 1998. The approximately $170 million of costs associated with the 1995 purchased power contract buy-back were deferred and recorded as a regulatory asset, to be amortized and collected over a ten-year period, beginning July 1, 1995. Amortization expense related to this contract buyout amounted to $17 million in each of 2000, 1999 and 1998. Prior to the implementation of new rates in March 2000, the Company was recovering deferred PERC restructuring costs at an annual rate of $1 million. Effective March 1, 2000, recovery of PERC restructuring costs was adjusted to include the estimated future value of warrants to be exercised. The adjusted annual amortization amounted to $1.6 million. The amortization expense associated with PERC contract restructuring costs was $1.5 million in 2000, $1 million in 1999 and $500,000 in 1998. Effective with the March 1, 2000 rate change, the Company began amortizing the deferred asset sale gain over a 70 month period. The annual amortization amounts are to be recorded in an uneven manner in order to levelize the Company's revenue requirement over this period. As a result of an increase in the Company's FERC regulated transmission rates on June 1, 2000, and the desire to not increase rates to its retail customers close to the implementation of electric industry restructuring, which occurred on March 1, 2000, the Company agreed to reduce its MPUC jurisdictional distribution rates in an amount equal to the increase in its transmission rates. The reduction in the distribution rates was accomplished by accelerating the amortization of the deferred asset sale gain by an annualized total of $2.5 million. The Company recorded $491,000 of amortization for April and May of 2000 and increased the monthly amortization to $703,000 starting in June 2000. The decrease in property and other taxes in 2000 period was due principally to reductions in property taxes as a result of the sale of the Company's generation assets. This reduction in property taxes was offset to some extent by increased electric plant additions and higher property tax rates. The decrease in property and other taxes in 1999 was due principally to reductions in property taxes as a result of the sale of the Company's generation assets. This reduction in property taxes was offset to some extent by increased electric plant additions in 1999. The decrease in total federal and state income taxes was principally a function of lower earnings in 2000 as compared to 1999, while the increases in income taxes in 1999 was due principally to greater earnings as compared to 1998. See Footnote 2 to the Consolidated Financial Statements for a reconciliation of the Company's effective income tax rate. OTHER INCOME AND (DEDUCTIONS) AND INTEREST EXPENSE - Allowance for funds used during construction (AFDC), which includes carrying costs on certain regulatory assets and liabilities, increased by approximately $940,000 in 2000 relative to 1999 due mainly to a $1.25 million increase in carrying costs being recorded on the deferred asset sale gain in 1999. This increase was offset to some extent by a $378,000 reduction in AFDC being recorded on construction work in progress in 2000 due principally to decreased construction costs. AFDC decreased $1.7 million in 1999 relative to 1998 due principally to $1.8 million in carrying costs being recorded on the previously discussed deferred asset sale gain. Other income decreased by approximately $2.7 million in 2000 principally as a result of the previously discussed $1.5 million income tax benefit recorded in 1999 associated with the flow-through of unamortized investment tax credits and excess deferred income taxes related to generation assets sold to PP&L in May 1999 and the previously discussed incremental merger related costs ($1.8 million, net of tax) incurred in 2000. Also decreasing other income in 2000 as compared to 1999 was a $310,000, net of tax, gain on sale of the Company's wholly-owned subsidiary, Penobscot Hydro, in July 1999 (See Note 6 to the Consolidated Financial Statements for a discussion of this sale). These decreases in other income in 2000 were offset to some extent by the $714,000, net of tax, gain on the previously discussed sale of Penobscot Gas in July The $2.3 million increase in other income in 1999 was principally a result of the previously discussed $1.5 million income tax benefit associated with the flow-through of unamortized investment tax credits and excess deferred income taxes ; the previously discussed $310,000, net of tax gain on sale of Penobscot Hydro; and the Company earned greater interest income as a result of investments utilizing the generation asset sale proceeds. Long-term debt interest expense decreased $3.8 million in 2000 as compared to 1999 and $3.9 million in 1999 as compared to 1998 as a result of the previously discussed principal repayments in 1998, 1999 and 2000 on various long-term debt issues. Other interest expense decreased $500,000 in 2000 due principally to a reduction in the amortization of debt issuance costs in 2000. The amortization decrease was primarily attributable to the end of the amortization of certain deferred debt issuance costs in 1999 as a result of the repayment of long-term debt through the utilization of generation asset sale proceeds and the end of the amortization period of certain deferred debt issuance costs in June 2000. Also impacting the reduction in other interest expense was $11 million in weighted average borrowings under the Company's revolving credit facility for the first quarter of 1999 as compared to no outstanding borrowings in 2000. The Company fully repaid the outstanding balance under its revolving credit line in April 1999, and no new borrowings have subsequently occurred. Other interest expense decreased $1.4 million due principally to a $20 million reduction in weighted average short-term borrowings outstanding in 1999 as compared to 1998. CONTINGENCIES AND DISCLOSURES ABOUT MARKET RISK ----------------------------------------------- ENVIRONMENTAL MATTERS - The Company is regulated by the United States Environmental Protection Agency (EPA) as to compliance with the Federal Water Pollution Control Act, the Clean Air Act, and several federal statutes governing the treatment and disposal of hazardous wastes. The Company is also regulated by the Maine Department of Environmental Protection (DEP) under various Maine environmental statutes. The Company is actively engaged in complying with these federal and state acts and statutes, and it has not, to date, encountered material difficulties in connection with such compliance. In 1992, the Company received notice from the DEP 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 EPA placed one of those sites on the National Priorities List under the Comprehensive Environmental Response, Compensation and Liability Act and would pursue potentially responsible parties. With respect to this site, the Company is one of a number of waste generators under investigation. The Company has recorded a liability, based on currently available information, for what it believes are the estimated environmental remediation costs that the Company expects to incur for this waste disposal site. Additional future environmental cleanup costs are not reasonably estimable due to a number of factors, including the unknown magnitude of possible contamination, the appropriate remediation methods, and possible effects of future legislation or regulation and the possible effects of technological changes. At December 31, 2000, the liability recorded by the Company for its estimated environmental remediation costs amounted to $282,000. The Company's actual future environmental remediation costs may be higher as additional factors become known. In 2000 the Company expended approximately $291,000 in operations expense and $103,000 in capital expenditures to comply with environmental standards for air, water and hazardous materials. DISCLOSURES ABOUT MARKET RISK - The Company's major financial market risk exposure is changing interest rates. Changes in interest rates will affect interest paid on variable rate debt and the fair value of fixed rate debt. The Company manages interest rate risk through a combination of both fixed and variable rate debt instruments and an interest rate swap, which is associated with the Company's medium term notes (See Note 14 to the Consolidated Financial Statements). As of December 31, 2000, the Company had $11.7 million of medium term notes outstanding which bear floating, LIBOR-based rates (6.56125% LIBO rate at December 31, 2000). The interest rate swap fixes the interest rate on the medium term notes at 5.72% for the full notional amount of the debt. See Note 4 to the Consolidated Financial Statements for a discussion of these medium term notes. NEW ACCOUNTING PRONOUNCEMENT ---------------------------- In May 1999, the Financial Accounting Standards Board voted to delay for one year the effective date of Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS 133). The new effective date for implementing this pronouncement is for fiscal years beginning after June 15, 2000. Based on current guidance, management does not believe that the adoption of SFAS 133 will have a material effect on the Company's financial statements. Item 8 Financial Statements & Supplementary Data ----------------------------------------- BANGOR HYDRO-ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF INCOME For the Years Ended December 31,
2000 1999 1998 Electric Operating Revenues Electric operating revenue (Note 1) $ 146,204,013 $ 197,994,796 $ 195,144,007 Standard offer service (Note 10) 66,133,532 - - ------------- --------------- --------------- $ 212,337,545 $ 197,994,796 $ 195,144,007 ------------- --------------- --------------- Operating Expenses: Fuel for generation and purchased power (Notes 1 and 3) $ 44,144,334 $ 80,748,385 $ 82,026,860 Standard offer service purchased power (Note 10) 65,552,980 - - Other operation and maintenance (Notes 1 and 5) 37,211,862 36,491,666 34,448,324 Depreciation and amortization (Note 1) 9,158,885 8,063,939 9,749,229 Amortization of Seabrook nuclear unit (Note 7) 1,699,050 1,699,050 1,699,050 Amortization of contract buyouts and restructuring (Note 6) 22,311,448 20,801,816 20,442,441 Amortization of deferred asset sale gain (Note 10) (6,393,038) - - Taxes - Local property and other 4,795,698 5,059,140 5,549,049 Income (Note 2) 7,432,261 8,973,166 6,093,286 ------------- --------------- --------------- $ 185,913,480 $ 161,837,162 $ 160,008,239 ------------- --------------- --------------- Operating Income $ 26,424,065 $ 36,157,634 $ 35,135,768 Other Income And (Deductions): Allowance for equity funds used during construction (Note 1) $ 158,698 $ (326,026) $ 430,028 Other, net of applicable income taxes (Notes 1, 2, 6 and 11) 454,715 3,132,097 862,723 ------------- --------------- --------------- Income Before Interest Expense $ 27,037,478 $ 38,963,705 $ 36,428,519 ------------- --------------- --------------- Interest Expense: Long-term debt (Notes 4 and 13) $ 15,211,905 $ 19,004,624 $ 22,906,021 Other (Note 4) 893,455 1,393,547 2,750,863 Allowance for borrowed funds used during construction (Note 1) (169,929) 284,933 (693,682) ------------- --------------- --------------- $ 15,935,431 $ 20,683,104 $ 24,963,202 ------------- --------------- --------------- Net Income $ 11,102,047 $ 18,280,601 $ 11,465,317 Dividends On Preferred Stock (Note 3) 265,570 945,396 1,244,488 ------------- --------------- --------------- Earnings Applicable To Common Stock $ 10,836,477 $ 17,335,205 $ 10,220,829 ------------- --------------- --------------- Weighted Average Number Of Shares Outstanding (Note 3) 7,363,424 7,363,424 7,363,424 ------------- --------------- --------------- Earnings Per Common Share (Note 3): Basic $ 1.47 $ 2.35 $ 1.39 Diluted 1.30 2.08 1.33 ------------- --------------- --------------- Dividends Declared Per Common Share $ .80 $ .45 $ - ------------- --------------- --------------- The accompanying notes are an integral part of these consolidated financial statements.
Item 8 Financial Statements & Supplementary Data ----------------------------------------- BANGOR HYDRO-ELECTRIC COMPANY CONSOLIDATED BALANCE SHEETS December 31,
Assets 2000 1999 Investment In Utility Plant: Electric plant in service, at original cost (Notes 6, 10 and 12) $ 316,167,622 $ 306,970,789 Less - Accumulated depreciation and amortization (Notes 1, 6 and 10) 86,684,205 84,825,432 ------------- ------------- $ 229,483,417 $ 222,145,357 Construction work in progress (Note 1) 5,457,707 5,668,246 ------------- ------------- $ 234,941,124 $ 227,813,603 Investments in corporate joint ventures: (Notes 1 and 6) Maine Yankee Atomic Power Company $ 4,949,696 $ 5,266,697 Maine Electric Power Company, Inc. 672,581 529,630 ------------- ------------- $ 240,563,401 $ 233,609,930 ------------- ------------- Other Investments, at cost (Notes 6 and 9) $ 3,174,561 $ 3,629,431 ------------- ------------- Funds held by trustee, at cost (Notes 4, 9 and 10) $ 22,696,405 $ 22,698,843 ------------- ------------- Current Assets: Cash and cash equivalents (Notes 1 and 9) $ 12,462,780 $ 15,691,166 Accounts receivable, net of reserve ($761,000 in 2000 and $1,075,000 in 1999) 21,731,869 18,269,672 Unbilled revenue receivable (Note 1) 15,778,696 14,127,645 Inventories, at average cost: Material and supplies 2,585,107 2,792,904 Fuel oil 93,746 45,310 Prepaid expenses 829,181 927,998 ------------- ------------- Total current assets $ 53,481,379 $ 51,854,695 ------------- ------------- Regulatory Assets and Deferred Charges: Investment in Seabrook nuclear project, net of accumulated amortization of $33,571,296 in 2000 and $31,872,246 in 1999 (Notes 7 and 10) $ 25,270,779 $ 26,969,829 Costs to terminate/restructure purchased power contracts, net of accumulated amortization of $123,171,966 in 2000 and $100,860,518 in 1999 (Notes 6 and 10) 99,312,319 118,565,234 Maine Yankee decommissioning costs (Notes 6 and 10) 43,028,107 46,041,644 Other regulatory assets (Notes 2,5,6,10, and 13) 41,025,080 36,925,665 Other deferred charges 3,667,769 3,655,009 ------------- ------------- Total regulatory assets and deferred charges $ 212,304,054 $ 232,157,381 ------------- ------------- Total Assets $ 532,219,800 $ 543,950,280 ============= ============= Stockholders' Investment and Liabilities Capitalization: (see accompanying statement) Common stock investment (Note 3) $ 137,419,659 $ 132,721,895 Preferred stock (Note 3) 4,734,000 4,734,000 Long-term debt, net of current portion (Notes 4, 9 and 13) 161,960,000 183,300,000 ------------- ------------- Total capitalization $ 304,113,659 $ 320,755,895 ------------- ------------- Current Liabilities: Notes payable - banks (Note 4) $ - $ - ------------- ------------- Other current liabilities - Current portion of long-term debt (Notes 4 and 9) $ 21,340,000 $ 19,460,000 Accounts payable 24,785,193 14,175,408 Dividends payable 1,539,114 1,170,942 Accrued interest 2,529,237 2,552,758 Customers' deposits 502,276 398,897 Current income taxes payable 305,323 4,125,696 ------------- ------------- Total other current liabilities $ 51,001,143 $ 41,883,701 ------------- ------------- Total current liabilities $ 51,001,143 $ 41,883,701 ------------- ------------- Commitments and Contingencies (Notes 6, 12 and 15) Regulatory and Other Long-term Liabilities (Note 2) Deferred income taxes - Seabrook $ 13,109,098 $ 13,994,668 Other accumulated deferred income taxes 58,314,350 55,826,890 Maine Yankee decommissioning liability (Note 6) 43,028,107 46,041,644 Deferred gain on asset sale (Note 10) 22,788,408 29,357,358 Other regulatory liabilities (Note 10) 12,556,052 9,872,188 Unamortized investment tax credits 1,452,059 1,591,727 Accrued pension and postretirement benefit costs (Note 5) 12,124,106 11,301,057 Other long-term liabilities (Notes 6 and 12) 13,732,818 13,325,152 ------------- ------------- Total regulatory and other long-term liabilities $ 177,104,998 $ 181,310,684 ------------- ------------- Total Stockholders' Investment and Liabilities $ 532,219,800 $ 543,950,280 ============= ============= The accompanying notes are an integral part of these consolidated financial statements.
Item 8 Financial Statements & Supplementary Data BANGOR HYDRO-ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF CAPITALIZATION December 31,
2000 1999 ---- ---- Common Stock Investment (Notes 1 and 3) Common stock, par value $5 per share- $ 36,817,120 $ 36,817,120 Authorized -- 10,000,000 shares Outstanding -- 7,363,424 shares in 2000 and 1999 Amounts paid in excess of par value 58,642,367 58,890,342 Retained earnings 41,960,172 37,014,433 -------------- ------------- Total common stock investment $ 137,419,659 $ 132,721,895 Preferred Stock, Non-participating, cumulative, par value $100 per share, -------------- ------------- authorized 600,000 shares (Note 3): Not redemable or redeemable solely at the option of the issuer- 7%, Noncallable, 25,000 shares authorized and outstanding $ 2,500,000 $ 2,500,000 4.25%, 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 Long-Term Debt (Notes 4, 9 and 14) -------------- ------------- First Mortgage Bonds- 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 -------------- ------------- $ 85,000,000 $ 85,000,000 Other Long-Term Debt- -------------- ------------- Finance Authority of Maine - Taxable Electric Rate Stabilization Revenue Notes, 7.03% Series 1995A, due 2005 $ 86,600,000 $ 100,600,000 Medium Term Notes, Variable interest rate-LIBO rate plus 1.125%, due 2002 11,700,000 17,160,000 -------------- ------------- $ 98,300,000 $ 117,760,000 Less: Current portion of long-term debt 21,340,000 19,460,000 -------------- ------------- $ 76,960,000 $ 98,300,000 -------------- ------------- Total Long-Term Debt $ 161,960,000 $ 183,300,000 -------------- ------------- Total Capitalization $ 304,113,659 $ 320,755,895 ============== ============= The accompanying notes are an integral part of these consolidated financial statements.
Item 8 Financial Statements & Supplementary Data ----------------------------------------- BANGOR HYDRO-ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS For the years ended December 31,
2000 1999 1998 ---- --- ---- Cash Flows From Operating Activities: Net income $ 11,102,047 $ 18,280,601 $ 11,465,317 Adjustments to reconcile net income to net cash from operating activities: Depreciation and amortization 9,158,885 8,063,939 9,749,229 Amortization of Seabrook nuclear project (Note 7) 1,699,050 1,699,050 1,699,050 Amortization of contract buyouts and restructuring (Note 6) 22,311,448 20,801,816 20,442,441 Amortization of deferred asset sale gain (Note 10) (6,393,038) - - Other amortizations 1,896,179 2,590,725 2,035,505 Allowance for equity funds used during construction (Note 1) (158,698) 326,026 (430,028) Deferred income tax provision and amortization of investment tax credits (Note 2) (2,765,264) (131,897) 5,876,874 Gain on sale of subsidiary (Notes 6 and 10) (1,205,727) (523,390) - Deferred Maine Yankee replacement power cost write-off (Note 6) 1,992,848 - - Flow-through of unamortized investment tax credits and excess deferred income taxes (Note 2) - (1,485,131) - Changes in assets and liabilities: Costs to restructure purchased power contract (Note 6) (1,000,000) (1,099,000) (7,704,185) Deferred standard-offer service costs (Note 10) (2,988,823) - - Deferred special rate contract revenues (Note 10) (1,368,948) - - Deferred incremental Maine Yankee costs (Note 6) 807,616 2,886,401 (793,608) Deferred incremental ice storm costs (Note 11) - 1,817,851 (4,200,423) Deferred costs associated with generation asset sale (Note 10) 107,765 (5,266,689) (2,317,688) Exercise of PERC warrants-cash paid in lieu of issuing shares (Note 6) (2,129,387) (3,321,710) - Payment received related to terminated purchased power contract (Note 6 - 1,750,000 - Deferred revenue - - (1,285,101) Accounts receivable, net and unbilled revenue (5,113,248) (2,759,315) (1,423,947) Accounts payable 10,609,785 (11,081) 724,721 Accrued interest (23,521) (921,611) (192,272) Current and deferred income taxes (10,093) 3,755,913 121,153 Accrued postretirement benefit costs (Note 5) 1,322,206 1,608,414 600,699 Other current assets and liabilities, net 202,486 (356,034) (22,036) Other, net (433,387) (345,523) (3,413,741) ------------- -------------- ------------- Net Increase in Cash From Operating Activities: $ 37,620,181 $ 47,359,355 $ 30,931,960 Cash Flows From Investing Activities: ------------- -------------- ------------- Construction expenditures $ (16,680,501) $ (20,323,360) $ (18,240,226) Asset sale proceeds (Note 10) - 79,587,841 6,200,000 Proceeds from sale of subsidiary (Notes 6 and 10) 1,250,000 10,000,000 - Release (deposit) of Graham Station property sale proceeds held by trustee (Note 10) - 6,200,000 (6,200,000) Allowance for borrowed funds used during construction (Note 1) (169,929) 284,933 (693,682) ------------- -------------- ------------- Net (Decrease) Increase in Cash From Investing Activities $ (15,600,430) $ 75,749,414 $ (18,933,908) Cash Flows From Financing Activities: ------------- -------------- ------------- Dividends on preferred stock $ ($265,570)$ (1,127,882) $ (1,216,434) Dividends on common stock (5,522,567) (2,209,028) - Payments on long-term debt (Note 4) (19,460,000) (85,782,897) (53,478,554) Payments on mandatory redeemable preferred stock (Note 4) - (9,243,742) (1,593,914) Issuance of long-term debt, net of capital reserve fund requirements (Note 4) - - 68,300,000 Short-term debt, net (Note 4) - (12,000,000) (22,000,000) ------------- -------------- ------------- Net Decrease in Cash From Financing Activities $ (25,248,137) $ (110,363,549) $ (9,988,902) ------------- -------------- ------------- Net (Decrease) Increase in Cash and Cash Equivalents $ (3,228,386) $ 12,745,220 $ 2,009,150 Cash and Cash Equivalents at Beginning of Year 15,691,166 2,945,946 936,796 ------------- -------------- ------------- Cash and Cash Equivalents at End of Year $ 12,462,780 $ 15,691,166 $ 2,945,946 ============= ============== ============= The accompanying notes are an integral part of these consolidated financial statements.
Item 8 Financial Statements & Supplementary Data ----------------------------------------- BANGOR HYDRO-ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF COMMON STOCK INVESTMENT
Amounts Paid Total Common Common in Excess of Retained Stock Stock Par Value Earnings Investment ----------- ----------- ----------- ------------ Balance December 31, 1997 $36,817,120 $56,969,428 $12,771,940 $106,558,488 Net income - - 11,465,317 11,465,317 Cash dividends declared on- Preferred stock - - (1,183,584) (1,183,584) Issuance of warrants (Note 6) - 2,084,775 - 2,084,775 Other (Note 3) - - (60,904) (60,904) ----------- ----------- ----------- ------------ Balance December 31, 1998 $36,817,120 $59,054,203 $22,992,769 $118,864,092 Net income - - 18,280,601 18,280,601 Cash dividends declared on- Preferred stock - - (899,718) (899,718) Common stock - - (3,313,541) (3,313,541) Exercise of warrants-cash paid in lieu of issuing shares (Note 3) - (410,052) - (410,052) Transfer of mandatory redeemable 8.76% preferred stock issuance costs to the deferred asset sale gain (Note 10) 246,191 246,191 Other (Note 3) - - (45,678) (45,678) ----------- ----------- ----------- ------------ Balance December 31, 1999 $36,817,120 $58,890,342 $37,014,433 $132,721,895 Net income - - 11,102,047 11,102,047 Cash dividends declared on- Preferred stock - - (265,570) (265,570) Common stock - - (5,890,738) (5,890,738) Exercise of warrants-cash paid in lieu of issuing shares (Note 3) - (247,975) - (247,975) ----------- ----------- ----------- ------------ Balance December 31, 2000 $36,817,120 $58,642,367 $41,960,172 $137,419,659 ----------- ----------- ----------- ------------ The accompanying notes are an integral part of these consolidated financial statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 1. NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES ---------------------------------------------------------------------------- NATURE OF OPERATIONS - Bangor Hydro-Electric Company (the Company) is a public utility engaged in the transmission and distribution of electric energy and other energy related services, with a service area of approximately 5,275 square miles having a population of approximately 192,000 people. The Company serves approximately 107,000 customers in portions of the Maine counties of Penobscot, Hancock, Washington, Waldo, Piscataquis, and Aroostook. The Company's regulated operations are 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 rates for transmission services. The Company is a member of the New England Power Pool (NEPOOL), 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 the Company include its wholly- owned subsidiaries, Bangor Var Co., Inc. (BVC), Bangor Energy Resale, Inc. (BERI), CareTaker, Inc. (CareTaker), Bangor Fiber Co., Inc. (Bangor Fiber), Penobscot Natural Gas Co., Inc. (Penobscot Gas) for the first six months of 2000, and Penobscot Hydro Co, Inc. (PHC) for the first seven months of 1999. The Company sold Penobscot Gas in early July 2000 and PHC in late July 1999. See Notes 6 and 10 for a detailed discussion of the Penobscot Gas and PHC sales, respectively. BERI was formed in 1997 as a special purpose vehicle to permit Bangor Hydro's use of a power sales agreement as collateral for a bank loan (see Note 4 for a discussion of this financing arrangement). CareTaker was incorporated in 1997 and provides security alarm services on a retail basis to residential and commercial customers. Bangor Fiber was formed in 2000 to supply fiber optic communications cable to communications companies and cable service providers and other related activities. See Note 6 for additional information with respect to BVC, Penobscot Gas and PHC. 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 fuel for generation and purchased power expense. See Note 6 for additional information with respect to these investments. ELECTRIC OPERATING REVENUE - Electric Operating Revenue, including that associated with standard offer service (See Note 10) 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. As of March 1, 2000, the Company bills customers for the energy supplied by competitive energy providers (See Note 10). Competitive energy providers are paid only after the funds are collected from customers. The Company records accounts receivable for the amounts billed to competitive energy customers and a corresponding accounts payable for the amounts due to the energy supplier. No revenue is recognized as the Company is acting as an agent. 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 properties over their estimated service lives. The composite depreciation rate (excluding intangible assets), expressed as a percentage of average depreciable plant in service, and considering the amortization of overaccu- mulated depreciation (discussed below), was approximately 2.9% in 2000, 2.1% in 1999 and 2.5% in 1998. A study conducted as of December 31, 1996 determined that the Company's reserve for depreciation was overaccumulated by approximately $3.6 million. In connection with the MPUC's rate order in February 1998, the Company was allowed to amortize this balance over a two-year period, starting in February 1998. The Company recorded approximately $307,000 in amortization in 2000, $2.4 million in 1999 and $1.6 million in 1998 which reduced depreciation expense. The 1999 and 2000 amortizations were increased as a result of the sale of the Company's hydroelectric plant assets in May 1999. 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 removed from such accounts. The original costs of units of property retired and removal costs, less salvage, are charged to the depreciation reserve. 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 $10 million in 2000, $9.5 million in 1999 and $7 million in 1998. 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. As a result of the generation asset sale (see Note 10), the Company filed with the FERC for authorization to reclassify the reserve for licensed hydro projects, classified as appropriated retained earnings, to unappropriated earnings. Such authorization was received in February 2001 and the reserve was reclassified from appropriated retained earnings to unappropriated retained earnings at December 31, 2000. The reserve balance at December 31, 1999 amounted to approximately $3 million. 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 and liabilities, including the deferred asset sale gain (see Note 10), were also capitalized in 2000 and 1999 and included in AFDC in the Consolidated Statements of Income. The average AFDC (carrying costs) rates computed by the Company were 9.3% in 2000, 9.5% for 1999 and 9.1% in 1998. 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. SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION - Cash paid for interest, net of amounts capitalized was approximately $15.1 million, $20.9 million and $23.8 million in 2000, 1999 and 1998, respectively. Cash paid for income taxes was approximately $10 million, $8.9 million and $655,000 in 2000, 1999 and 1998, respectively. Non- cash operating activity: In 1998, the Company issued common stock warrants in connection with the Penobscot Energy Recovery Company (PERC) purchased power contract restructuring (see Note 6), which were recorded at a fair value of $2 million as a regulatory asset and additional paid-in capital. RISK MANAGEMENT AND DERIVATIVE FINANCIAL INSTRUMENTS - The Company's major financial market risk exposure is changing interest rates. Changing interest rates will affect interest paid on variable rate debt and the fair value of fixed rate debt. The Company manages interest rate risk through a combin-ation of both fixed and variable rate debt instruments and an interest rate swap (see Notes 4 and 14). The Company does not hold or issue derivatives for trading purposes. The Company's accounting for derivatives used to manage risk is in accordance with Statement of Financial Accounting Standards No. 80, "Accounting for Futures Contracts". RECLASSIFICATIONS-Certain prior year amounts have been reclassified to conform with the presentation used in the 2000 Consolidated Financial Statements. NOTE 2. INCOME TAXES -------------------- The individual components of federal and state income taxes reflected in the Consolidated Statements of Income for 2000, 1999 and 1998 are stated in the table below. Year Ended December 31, 2000 1999 1998 Current: Federal $ 7,445,626 $7,390,387 $ 725,466 State 2,920,769 2,314,251 195,876 ----------- ---------- ---------- $10,366,395 $9,704,638 $ 921,342 ----------- ---------- --------- Deferred: Federal-Other $ (1,276,946) $ 89,444 $5,089,469 State-Other (934,560) (375,468) 1,442,801 Federal-Seabrook (341,917) (341,917) (341,917) State-Seabrook (72,173) (72,173) (72,173) ----------- ------------ ------------ $ (2,625,596) $ (700,114) $6,118,180 -------------- ------------- ------------ Investment Tax Credits, Net $ (139,668) $ (317,877) $ 385,805) -------------- ------------- ---------- Total Provision $ 7,601,131 $8,686,647 $6,653,717 Allocated to Other Income (168,870) 286,519 (560,431) -------------- ------------- ----------- Charged to Operating Expense $ 7,432,261 $8,973,166 $6,093,286 ============ ========== =========== The table below reconciles the 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 Consolidated Statements of Income. The difference is represented by the permanent and timing differences for which deferred taxes are not provided for ratemaking purposes. 2000 1999 1998 ------------------------------------- (Dollars in Thousands) Amount % Amount % Amount % ------------------------------------------- Federal income tax provision at statutory rate $6,546 35.0% $9,439 35.0% $6,342 35.0% Less (Plus) permanent differences in tax expense resulting from statutory exclusions from taxable income: Dividend received deduction related to earnings of associated companies 164 .9 253 .9 40 .2 Equity component of AFDC 138 .7 185 .7 151 .8 Amortization of equity component of AFDC on recoverable Seabrook investment (160) (.8) (160) (.6) (160) (.9) Other 33 .1 (29) (.1) (28) (.1) -------------------------------------------- Federal income tax provision before effect of timing differences $6,371 34.1% $9,190 34.1% $6,339 35.0% Less (Plus) timing differences that are flowed through for rate-making and accounting purposes: Amortization of debt component of AFDC and capitalized overheads on recoverable Seabrook investment (151) (.8) (151) (.6) (151) (.8) Book depreciation greater than tax depreciation (69) (.4) (85) (.3) (88) (.5) Equity earnings in excess of (less than) dividends (41) (.2) (276) (1.0) 201 1.1 Amortization of deferred asset sale gain (276) (1.5) - - - - State income tax liability deducted for federal income tax purposes 550 2.9 673 2.5 498 2.8 Reversal of excess deferred income taxes 147 .8 167 .6 124 .7 Amortization of investment tax credits 140 .8 350 1.3 241 1.3 Investment tax credits and excess deferred taxes flowed through - - 1,485 5.5 - - Other 42 .3 27 .1 282 1.5 --------------------------------------------------- Federal income tax provision $6,029 32.2% $7,000 26.0% $5,232 28.9% =================================================== Under the federal income tax laws, the Company received investment tax credits (ITC) on qualified property additions through 1986. ITC utilized were deferred and are being amortized over the life of the related property. In 1999 the Company utilized the remaining available ITC of about $3.2 million to reduce its federal income tax obligation. In 1999 the Company utilized its remaining tax net operating loss carryforwards of $66.6 million to reduce its regular income tax liability. In 2000, the Company utilized the remaining $3.6 million of federal alternative minimum tax credits to reduce its regular income tax liability while in 1999, the Company utilized $4.2 million of federal and state alternative minimum tax credits. In 1998 the Company utilized approximately $31.9 million of tax net operating loss carryforwards to reduce its regular income tax liability. 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 1995, which were deferred for financial reporting purposes (see Note 6). In accordance with Statement of Financial Accounting Standards No. 109 "Accounting for Income Taxes" (FAS 109), the Company recorded cumulative net additional deferred income tax liabilities of approximately $16.4 million as of December 31, 2000 and $16 million as of December 31, 1999. 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 ($25.3 million and $24.8 million as of December 31, 2000 and 1999, 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 ($8.1 million and $7.9 million as of December 31, 2000 and 1999, respectively), and the establishment of deferred tax assets on unamortized investment tax credits ($858,000 and $900,000 as of December 31, 2000 and 1999, respectively). These latter amounts have been recorded in Other Regulatory Liabilities at December 31, 2000 and 1999. 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 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, 2000 and 1999: 2000 1999 -------------- -------------- Deferred Income Tax Liabilities: Costs to terminate/restructure purchased power contracts $35,091,730 $ 42,793,031 Excess book over tax basis of electric plant in service 37,184,354 35,395,877 Investment in jointly-owned companies 1,358,081 1,492,533 Deferred standard-offer service costs 1,248,764 - Deferred incremental ice storm costs 1,156,526 1,429,579 Deferred restructuring related costs 454,142 681,031 Other 817,035 319,488 ------------ ------------- $ 77,310,632 $ 82,111,539 ------------ ------------- Deferred Income Tax Assets: Deferred asset sale gain $ 8,776,804 $ 12,121,099 Accrued pension and postretirement benefit costs 4,500,464 4,127,529 Deferred state income tax benefit 1,724,310 3,317,437 Unamortized investment tax credit 858,554 941,134 Deferred write-off of Maine Yankee replacement power costs 813,234 - Deferred incremental Maine Yankee costs 673,783 453,414 Reserve for bad debts 632,652 719,981 Deferred taxes provided on alternative minimum tax - 3,627,596 Other 1,016,481 976,459 -------------- ------------- $ 18,996,282 $ 26,284,649 ------------- ------------- Total other accumulated deferred income taxes $ 58,314,350 $ 55,826,890 ============ ============ As a result of the Company's generation asset sale to PP&L Global (see Note 10), the Company realized $1.5 million in income tax benefits associated with the recognition of previously unamortized deferred ITC associated with the generation assets sold and the reversal of the excess deferred income taxes associated with these assets. These income tax benefits have been recorded as a component of Other Income in the Consolidated Statements of Income in 1999. Note 3. Common and Preferred Stock and Earnings Per Share --------------------------------------------------------- COMMON STOCK - 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. In January 1997, the Company further amended the Plan to allow for the option of purchasing shares either on the open market or from newly issued shares sold by the Company. The Company anticipates that for the foreseeable future common stock will be purchased on the open market. PREFERRED STOCK - Authorized but unissued shares of 552,660 (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. 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 STOCK - 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 had a maturity of fifteen years with a mandatory sinking fund of $1.5 million per year starting in 1995. Through the utilization of generation asset sale proceeds, the Company redeemed the remaining outstanding 90,000 shares in October 1999 at a cost of $9.8 million, which included a call premium of $282,000, and $563,000 associated with the make whole provision, which is discussed below. The agreement to issue this series of preferred stock contained a provision whereby, if the Company paid a dividend that was considered a return of capital for federal income tax purposes, the Company was required to make a payment (make whole provision) 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 and 1995 and 50% in 1993 were considered a return of capital, the Company became obligated to pay this stockholder approximately $939,000, on a pro-rata basis (10% per year) in conjunction with each sinking fund payment starting in 1995. With the redemption of the remaining outstanding shares in 1999, the Company was obligated to pay the remaining make whole provision amount of $563,000 at the time of the redemption. The make whole provision obligation was being recognized over the remaining life of the issue through a direct charge to retained earnings, which amounted to approximately $46,000 in 1999 and $61,000 in 1998. In 1998 the Company made a $1.5 million sinking fund payment, as well as approximately $94,000 under the make whole provision. EXERCISE OF WARRANTS - In 2000, 212,786 common stock warrants, which were issued in connection with the PERC purchased power contract restructuring, were exercised at market prices ranging from $14.75 to $24.8125 per share. For a complete discussion of the PERC contract restructuring and the issuance of warrants, see Note 6. The Company exercised its option to pay cash to the holders of the warrants instead of actually issuing shares of common stock. These payments amounted to approximately $2.5 million. Since the common shares were not issued, and the Company had recorded the estimated fair value of these warrants when issued in June 1998 as a $248,000 addition to paid-in capital, an adjustment has been made in connection with the cash payments option to reduce paid-in capital by this amount as of December 31, 2000. At December 31, 2000 there were approximately 1.4 million unexercised common stock warrants in connection with the PERC contract restructuring. In 1999, 349,999 common stock warrants, which were issued in connection with the PERC purchased power contract restructuring, were exercised at market prices ranging from $16 1/16 to $16 3/4 per share. The Company exercised its option to pay cash to the holders of the warrants instead of actually issuing shares of common stock. These payments amounted to approximately $3.3 million. Since the common shares were not issued, and the Company had recorded the estimated fair value of these warrants when issued in June 1998 as a $410,000 adjustment to paid-in capital, an adjustment was made in connection with the cash payments option to reduce paid-in capital by this amount as of December 31, 1999. EARNINGS PER SHARE - The following table reconciles basic and diluted earnings per common share assuming all outstanding common stock warrants were converted to common shares (see Note 6 for discussion of warrants issued in connection with the PERC purchased power contract restructuring): 2000 1999 1998 ----------- ----------- ----------- Earnings applicable to common stock $10,836,477 $17,335,205 $10,220,829 ------------ ------------ ----------- Average common shares outstanding 7,363,424 7,363,424 7,363,424 Plus: incremental shares from assumed conversion of outstanding warrants 990,099 984,200 329,778 ------------ ------------ --------- Average common shares outstanding plus assumed warrants converted 8,353,523 8,347,624 7,693,202 ------------ ----------- ----------- Basic earnings per common share $1.47 $2.35 $1.39 ------------- ------------ ----------- Diluted earnings per common share $1.30 $2.08 $1.33 ============= ============ ========== Note 4. Lending Agreements and Monetization of Power Sale Contract ------------------------------------------------------------------ On June 29, 1998, the Company entered into an Amended and Restated Revolving Credit and Term Loan Agreement with a new group of lenders that provided a two-year term loan of $45 million and a revolving credit commitment of $30 million. The amended credit agreement is secured by $82.5 million of non-interest bearing First Mortgage Bonds. The revolving credit portion of the credit agreement has a term of three years. The Company may borrow, at its option, at rates, as defined in the agreement, based on the London Interbank Offered (LIBO) rate, or the base rate, which is the higher of the agent bank's defined base rate or one-half of one percent (1/2%) above the federal funds interest rate. The applicable risk premium based on the Company's corporate credit rating is added to the core interest rate, which results in the total combined interest rate for borrowing under the agreement. A required commitment fee, based on the Company's available revolving credit commitment, is also priced according to the Company's corporate credit rating. The maturity of the term loan was the earlier of two years or when the Company completed any portion of its generation asset sale (see Note 10). Interest on the term loan was determined similarly to the revolving credit portion of the new credit agreement but with a different risk premium. In January 1999 the Company utilized the $6.2 million in proceeds associated with the sale of property at its Graham Station in Veazie, Maine to Casco Bay Energy (see Note 10) to repay a portion of the outstanding medium term notes, and the remaining principal outstanding of $38.8 million was repaid at the end of May 1999 utilizing proceeds from the Company's generation asset sale to PP&L Global on May 27, 1999. 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 $30 million revolving credit facility. The new credit agreement contains certain financial covenants related to the Company's debt ratio, fixed charge coverage, net worth, and limitation on the payment of common dividends. The Company was in compliance with all covenants associated with the new credit agreement during 2000 and 1999. The Company provided power directly to UNITIL Power Corp. (UNITIL), a New Hampshire based electric utility, at significantly above-market rates, with the contract term ending in the year 2003. On March 31, 1998, the Company completed a transaction with lenders and one of its wholly owned subsidiaries, BERI (see below) that provided a loan of approximately $23.3 million in net proceeds secured by the value of the UNITIL contract. As a requirement of the financing, the Company established BERI, a special purpose entity which holds the medium term notes and acts as a conduit between Bangor Hydro and UNITIL for the procurement of power under the terms of the original power sales contract between the two parties. The loan was comprised of $24.8 million in medium term notes, with a term of 53 months. BERI must maintain a capital reserve fund of $1.5 million, funded with proceeds from the loan, which will be used to pay the final installment of principal and interest due in 2002. The assets in the capital reserve fund are held by a third party trustee and invested in money market funds whose investments are limited to commercial paper, corporate notes and bonds, certificates of deposit, municipal bonds, U.S. Agency obligations and repurchase agreements. Interest is payable, at the Company's option, under the agreement at the LIBO rate plus 1.125% or the base rate, which is the higher of (a) the lending bank's reported "base rate" and (b) one-half of one percent (1/2%) above the federal funds effective interest rate. The Company has historically selected the LIBO rate interest option. To provide interest rate protection through the maturity date of the term loan, in April 1998, BERI entered into an interest rate swap agreement with one of the lending banks. The interest rate swap fixed the LIBO interest rate on the medium term notes at 5.72%. As a result of the interest rate swap agreement, BERI realized reduced interest expense of $96,168 in 2000 and incurred additional interest expense in 1999 amounting to approximately $114,000. The agreement also contains certain financial covenants, with which BERI was in compliance during 2000 and 1999. 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 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, which began on July 1, 1998. The amount held in the capital reserve fund will be used to pay the final installment 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 investment contract, earning interest at an annual rate of 6.51%. 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 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. The Company may not issue any additional First Mortgage Bonds in the future. The Company issued bonds to FAME under the new mortgage in the amount of $126 million. Certain information related to total short-term borrowings under the Credit Agreements and the lines of credit is as follows: 2000 1999 1998 ----------- ----------- ----------- Total credit available at end of period $30,000,000 $30,000,000 $30,000,000 Letter of credit secured under the revolving credit facility - $ 4,200,000 $ 4,200,000 Unused credit at end of period $30,000,000 $13,800,000 $15,800,000 Borrowings outstanding at end of period - - $12,000,000 Effective interest rate (exclusive of fees) on borrowings outstanding at end of period -% -% 7.2% Average daily outstanding borrowings for the period $ - $ 2,802,740 $20,369,863 Weighted daily average annual interest rate -% 6.7% 7.9% Highest level of borrowings outstanding at any month-end during the period $ - $13,000,000 $37,500,000 =========== =========== =========== 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. Current maturities of the first mortgage bonds and other long-term debt for the five years subsequent to December 31, 2000, amounting to $133,300,000, are $21,340,000 in 2001, $41,560,000 in 2002, $32,200,000 in 2003, $18,400,000 in 2004, and $19,800,000 in 2005. Note 5. Postretirement Benefits ------------------------------- The Company has a noncontributory pension plan covering substantially all of its employees. Benefits under the plan 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 Company also has an unfunded noncontributory supplemental non-qualified pension plan that provides additional retirement benefits to certain management employees. There were no employer contributions to the noncontributory pension plan in 2000, 1999 or 1998. The plan's assets are composed of fixed income securities, equity securities and cash equivalents. The following tables detail the funded status of the plan, the amounts recognized in the Company's Consolidated Financial Statements, the components of pension (income) expense for 2000, 1999 and 1998 and the major assumptions used to determine these amounts (includes both the funded and unfunded plans). Total pension (income) expense included the following components: 2000 1999 1998 ---------- ---------- ---------- Service cost-benefits earned during the period $1,186,910 $1,439,047 $1,208,393 Interest cost on projected benefit obligation 3,479,260 3,295,172 3,107,258 Expected return on plan assets (4,460,416) (4,317,379) (3,737,267) Amortization of unrecognized asset and gains (losses) (664,911) 252,043 (333,507) ------------ ---------- ----------- Total pension (income) expense $ (459,157) $ 668,883 $ 244,877 ============ ========== =========== The following table sets forth the plans' funded status at December 31, 2000 and 1999: 2000 1999 ----------- ----------- Change in Projected Benefit Obligation Balance as of December 31, 1999 and 1998 $45,165,460 $48,215,365 Service cost 1,186,910 1,439,047 Interest cost 3,479,260 3,295,172 Benefits paid (2,900,824) (2,965,723) Amendments - 1,047,567 (Gains) and losses 1,020,990 (5,865,968) ----------- ----------- Balance as of December 31, 2000 and 1999 $47,951,796 $45,165,460 ----------- ----------- Change in Plan Assets Balance as of December 31, 1999 and 1998 $51,834,730 $49,495,200 Employer contributions 40,000 40,000 Benefits paid (2,900,824) (2,965,723) Actual return, less expenses (548,040) 5,265,253 ----------- ----------- Balance as of December 31, 2000 and 1999 $48,425,866 $51,834,730 ----------- ----------- Funded status $ 474,070 $ 6,669,270 Unrecognized net transition asset (390,175) (1,322,500) Unrecognized prior service cost 2,630,838 3,290,845 Unrecognized gain (4,756,609) (11,178,648) ----------- ----------- Accrued pension balance at December 31, 2000 and 1999 $ (2,041,876) $ (2,541,033) ============ ============ The accumulated benefit obligation for the unfunded supplemental pension plan with accumulated benefit obligations in excess of plan assets was $1,999,298 and $1,220,982 as of December 31, 2000 and 1999, respectively. 2000 1999 1998 ------ ----- ----- Significant assumptions used were- Discount rate 8.0% 6.75% 7.0% Rate of increase in future compensation levels 4.0% 4.0% 4.0% Expected long-term rate of return on plan assets 9.0% 9.0% 9.0% The discount rate and rate of increase in future compensation levels used to determine pension obligations, effective January 1, 2001, are 7.75% and 4%, respectively, and were used to calculate the plans' funded status at December 31, 2000. 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 MPUC in 1993 issued a final accounting rule in connection with Statement of Financial Accounting Standards No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" (SFAS 106), which adopted this pronouncement for ratemaking purposes and authorized the Company to defer the excess of the net periodic postretirement benefit cost recognized under SFAS 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 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 amounted to approximately $1.7 million in 2000 and $1.3 million in each of 1999 and 1998. The VEBA's assets are composed of United States Treasury money market funds. The Company's general policy is to contribute to the VEBA amounts necessary to fund claims and administrative costs. The actuarially determined net periodic postretirement benefit cost for 2000, 1999 and 1998 and the major assumptions used to determine these amounts are shown in the following tables: 2000 1999 1998 ---------- ---------- ---------- Service cost of benefits earned $ 573,740 $ 583,385 $ 401,856 Interest cost on accumulated postretirement benefit obligation 1,716,563 1,518,092 1,060,671 Actual return on plan assets (22,002) (9,710) (10,608) Amortization of unrecognized transition obligation 501,200 501,200 501,200 Other deferrals, net 280,255 405,834 (14,392) ---------- --------- ---------- Net periodic postretirement benefit cost $3,049,756 $2,998,801 $1,938,727 ========== ========== ========== The following table sets forth the benefit plan's funded status at December 31, 2000 and 1999. 2000 999 ------------ ------------ Change in Accumulated Postretirement Benefit Obligation Balance as of December 31, 1999 and 1998 $ 20,720,833 $ 19,073,629 Service cost 573,740 583,385 Interest cost 1,716,563 1,518,092 Claims paid (1,091,334) (1,301,239) Gains and losses 1,954,390 846,966 ------------- ------------ Balance as of December 31, 2000 and 1999 $ 23,874,192 $ 20,720,833 ------------ ------------ Change in Plan Assets Balance as of December 31, 1999 and 1998 $ 358,971 $ 321,408 Employer contributions 1,727,550 1,347,000 Retiree contributions 43,428 47,152 Claims paid (1,091,334) (1,301,239) Actual return, less expenses (158,881) (55,350) ------------ ------------- Balance as of December 31, 2000 and 1999 $ 879,734 $ 358,971 ------------ ------------- Funded status $(22,994,458) $(20,361,862) Unrecognized net transition obligation 6,013,600 6,514,800 Unrecognized loss 6,898,628 5,087,038 ------------ ------------ Accrued postretirement benefit cost balance at December 31, 2000 and 1999 $(10,082,230) $ (8,760,024) ============ ============ 2000 1999 1998 ------ ------ ----- Significant assumptions used were- Discount rate 8.0% 6.75% 7.0% Health care cost trend rate, employees less than age 65- Near-term 7.0% 7.5% 8.0% Long-term 5.0% 4.5% 5.0% Health care cost trend rate, employees greater than age 65- Near-term 7.0% 7.5% 8.0% Long-term 5.0% 4.5% 5.0% Rate of return on plan assets 5.0% 5.0% 5.0% The discount rate used to determine postretirement benefit obligations, effective January 1, 2001, and the Plan's funded status at December 31, 2000, was 7.75%. Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plan. A one-percentage-point change in assumed health care cost trend rates would have the following effect: 1% Increase 1% Decrease ----------- ------------- Effect on total of service and interest cost components $ 402,129 $ (318,515) Effect on postretirement benefit obligation 3,103,456 (2,517,883) In 1999 the Company incurred $469,000 and $175,587 in special termination benefits associated with enhanced pension and postretirement medical benefits, respectively, provided to employees who were displaced due to the asset sale to PP&L Global (see Note 10). The state of Maine electric utility restructuring legislation allows utilities to recover the costs of providing such benefits to the workers displaced due to the sale of the Company's generation assets, and consequently, the special termination benefits expense of $644,587 was deferred and is recorded as a regulatory asset at December 31, 1999. Recovery of this regulatory asset began starting March 1, 2000 over a three-year period as specified in the Company's 2000 rate order from the MPUC. The estimates of the Company's accrued pension and postretirement benefit costs involve the utilization of significant assumptions. Changes in any one of these assumptions could impact the liabilities in the near term. The Company also provides a defined contribution 401(k) savings plan for substantially all of its employees. The Company's matching of employee voluntary contributions amounted to approximately $370,000 in 2000, $331,000 in 1999 and $330,000 in 1998. Note 6. Jointly Owned Facilities and Power Supply Commitments ------------------------------------------------------------- MAINE YANKEE - The Company owns 7% of the common stock of Maine Yankee, which owns and, prior to its permanent closure in 1997, operated an 880 megawatt (MW) nuclear generating plant (the Plant) in Wiscasset, Maine. Maine Yankee, which had commenced commercial operation on January 1, 1973, is the only nuclear facility in which the Company has an ownership interest. The Company's equity ownership in the plant had entitled the Company to about 7% of the output pursuant to a cost-based power contract. Pursuant to a contract with Maine Yankee, the Company is obligated to pay its pro rata share of Maine Yankee's operating expenses, including 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. Plant Shutdown and Rate Case Settlement - On August 6, 1997, the board of directors of Maine Yankee voted to permanently cease power operations at the Plant and to begin decommissioning the Plant. The Plant had experienced a number of operational and regulatory problems and did not operate after December 6, 1996. The decision to close the Plant permanently was based on an economic analysis of the costs, risks and uncertainties associated with operating the Plant compared to those associated with closing and decommissioning it. The Plant's operating license from the Nuclear Regulatory Commission was scheduled to expire in 2008. The entire output of the Plant had been sold at wholesale by Maine Yankee to ten New England electric utilities, which collectively own all of the common equity of Maine Yankee; a portion of that output (approximately 6.2%) was in turn resold by certain of the owner utilities to 29 municipal and cooperative utilities in New England (the Secondary Purchasers). Maine Yankee recovered, and since the shutdown decision has continued to recover, its costs of providing service through a formula rate filed with the FERC and contained in Power Contracts with its utility purchasers, which, as amended, are also filed with the FERC. In November 1997, Maine Yankee submitted for filing certain amendments to the Power Contracts (the Amendatory Agreements) and revised rates to reflect the decision to shut down the Plant and to request approval of an increase in the decommissioning component of its formula rates. Maine Yankee's submittal also requested certain other rate changes, including recovery of unamortized investment (including fuel) and certain changes to its billing formula, consistent with the nonoperating status of the Plant. During 1998 and early 1999, the parties to the FERC proceeding, including, among others, the MPUC staff, the Maine Office of the Public Advocate and the Secondary Purchasers, engaged in extensive discovery and negotiations, which resulted in the filing of a settlement agreement with the FERC in January 1999. A separately negotiated settlement filed with the FERC in February 1999 resolved the issues raised by the Secondary Purchasers by limiting the amounts of their payments for decommissioning the Plant and by settling other points of contention affecting individual Secondary Purchasers. Both settlements were found to be in the public interest and were approved by the FERC on June 1, 1999. The settlements constitute a full settlement of all issues raised in the FERC proceeding, including decommissioning cost issues and the issues pertaining to the prudence of the management, operation, and decision to permanently cease operation of the Plant. The primary settlement provides for Maine Yankee to recover amounts intended to cover the costs of decommissioning and those associated with the construction and maintenance of an of an off-site independent spent fuel storage installation (ISFSI). The settlement also provides for recovery of the unamortized investment (including fuel) in the Plant, together with a return on equity of 6.50% on limited equity balances. The Settling Parties also agreed not to contest the effectiveness of the Amendatory Agreements submitted to FERC as part of the original filing, subject to certain limitations including the right to challenge any accelerated recovery of unamortized investment under the terms of the Amendatory Agreements after a required informational filing with the FERC by Maine Yankee. In addition, Maine Yankee agreed to file with the FERC a rate proceeding that will have an effective date of no later than January 1, 2004, when major decommissioning activities are expected to be nearing completion. As a separate part of the settlement, the three Maine Sponsors of Maine Yankee, the MPUC Staff, and the Office of the Public Advocate entered into a further agreement (Maine Agreement) resolving retail rate issues and other issues specific to the Maine parties, including those that had been raised concerning the prudence of the operation and shutdown of the Plant. The Company believes that the settlement, including the Maine Agreement, constituted a reasonable resolution of the issues raised in the Maine Yankee FERC proceeding, and eliminated significant uncertainties concerning the Company's future financial performance. Under the Maine Agreement, the Company would continue to recover its Maine Yankee costs , although the allowed return on equity associated with the Company's equity balance in Maine Yankee was set at 6.50%. The final major provision of the Maine Agreement required the Maine owners, for the period from March 1, 2000, through December 1, 2004, to hold their Maine retail ratepayers harmless from the amounts by which the replacement power costs for Maine Yankee exceeded the replacement power costs assumed in the report to the Maine Yankee board of directors that served as a basis for the Plant shutdown decision. As part of a further settlement, the Company's liability was fixed at approximately $2.2 million to be reflected as a reduction in stranded costs effective March 1, 2002. The Company charged to fuel and purchased power expense and recorded as a regulatory liability $2 million in December 2000 representing the net present value of this future obligation Termination of Decommissioning Operations Contract - On May 4, 2000, Maine Yankee notified its decommissioning operations contractor, Stone & Webster Engineering Corporation (Stone & Webster), that it was terminating the decommissioning operations contract pursuant to the terms of the contract. Stone & Webster subsequently notified Maine Yankee that it was disputing Maine Yankee's grounds for terminating the contract. On May 8, 2000, Stone & Webster announced a proposed transaction in which it would transfer substantially all of its assets in exchange for an immediate credit facility and other consideration, including cash and stock. Stone & Webster said that the credit facility was intended to enable it to address its liquidity difficulties and continue to operate its businesses until the asset sale was completed. Stone & Webster also announced that it intended to seek bankruptcy court approval of the asset sale and credit agreement. On June 2, 2000, Stone & Webster filed a voluntary petition under Chapter 11 of the U.S. Bankruptcy Code with the United States Bankruptcy Court for the District of Delaware. By Sale Order dated July 13, 2000, the Bankruptcy Court approved the sale of substantially all of Stone & Webster's assets to the successful bidder in the Chapter 11 sale, The Shaw Group, Inc. (Shaw), for cash, stock, and the assumption of certain liabilities of Stone & Webster, and the proposed transaction announced earlier by Stone & Webster was terminated. Stone & Webster reported that the Shaw transaction was effectively closed on July 14, 2000, and that it would continue to operate as a Debtor-in- Possession subject to the supervision and orders of the Bankruptcy Court. Commencing in May 2000, Maine Yankee entered into interim agreements with Stone & Webster in order to allow decommissioning work to continue and avoid the adverse consequences of an abrupt or inefficient demobilization from the Plant site. After obtaining assignments of several subcontracts from Stone & Webster, Maine Yankee temporarily assumed the general contractor role. The decom-missioning of the Plant site continued throughout 2000, with major emphasis directed to maintaining the schedule of critical-path projects such as construction of the ISFSI and preparation of the Plant's reactor vessel for eventual shipment to an off-site disposal facility. During this period, Maine Yankee performed comprehensive assessment of its long-term alternatives for safely and efficiently completing the decommissioning, including evaluating detailed competitive-bid proposals from prospective successor general contractors. On January 26, 2001, Maine Yankee announced its decision to continue to manage the decommissioning project itself without an external general contractor. On June 30, 2000, Federal Insurance Company (Federal), which provided performance and payment bonds in the amount of approximately $37.6 million each in connection with the decommissioning operations contract, filed a Complaint for Declaratory Judgement against Maine Yankee in the United States Bankruptcy Court for the District of Delaware, which was subsequently transferred to the United States District Court in Maine. The Complaint, which seeks a declaration that Federal has no obligation to pay Maine Yankee under the bonds, alleges that Maine Yankee improperly terminated the decommissioning operations contract with Stone & Webster and failed to give proper notice of the termination to Federal under the contract, and that Federal therefore had no further obligations under the bonds. On August 24, 2000, Maine Yankee filed a $78.2 million claim in the Stone & Webster Bankruptcy Court proceeding in Delaware seeking to recover its additional costs caused by Stone & Webster's contract default. Maine Yankee expects the court hearings in both proceedings to take place later in 2001. Maine Yankee believes that its termination of the Stone & Webster contract was proper and that it is entitled to recover such additional costs in the bankruptcy proceeding or under the bonds, but cannot predict the outcome of the litigation. In connection with the state of Maine's electric industry restructuring law, the Company was allowed the recovery of Maine Yankee decommissioning costs as a component of its stranded costs. In the Company's rate order from the MPUC that became effective March 1, 2000, the Company was allowed to defer the amount of any future FERC ordered changes in Maine Yankee's decommissioning collections. Consequently, management does not believe that Maine Yankee's current decom- missioning contractor difficulties will have a material adverse impact on the Company's results of operations, financial condition or cash flows. Maine Yankee's most recent estimate of the total costs of decommissioning and plant closure, for the period from 1999 to 2008, excluding funds already collected, is $715 million (undiscounted). The Company's share of the estimated cost at December 31, 2000 is approximately $43 million and is recorded as a regulatory asset and decommissioning liability. The regulatory asset was recorded for the full amount of the decommissioning and plant closure costs due to the state's industry restructuring legislation (see Note 10) allowing the Company future recovery of nuclear decommissioning expenses related to Maine Yankee, as well as the Company being allowed a recovery mechanism in its February 2000 rate order for Maine Yankee non-decommissioning plant closure costs. Accumulated decommissioning funds at December 31, 2000 had an adjusted market value of $156.2 million of which the Company's share was approximately $10.9 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. Information relating to the operations and financial position of Maine Yankee and MEPCO appears later in Note 6. In connection with the Company's generation asset sale in May 1999 (see Note 10), the Company sold certain of its rights to MEPCO transmission capacity. 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 connection with the generation asset sale in May 1999, the Company sold its rights as a participant in the regional utilities agreement with Hydro-Quebec (see Note 10). The Company, though, is still required to pay its share of the costs of ownership and operation of the Hydro-Quebec intertie. Also in connection with the asset sale, PP&L Global (PP&L) has agreed to pay the Company $400,000 per year to partially offset the Company's on- going Hydro-Quebec support payments. Since the Company still has an obligation for the costs of the Hydro-Quebec intertie, but it has sold the rights to the benefits as a participant, an $8 million liability (included in Other Long-term Liabilities) and corresponding regulatory asset (included in Other Regulatory Assets) have been recorded as of December 31, 2000 on the Consolidated Balance Sheet representing the present value of the Company's estimated future payments (net of the $400,000 to be received from PP&L) for costs of ownership and operation of the Hydro-Quebec intertie. Summary Financial Information for Maine Yankee and MEPCO is as follows (dollars in thousands): ---------------------------------------------------------------------- Maine Yankee MEPCO ---------------------------------------------------------------------- 2000 1999 1998 2000 1999 1998 --------- ---------- ---------- --------- -------- ------ Operations: As reported by investee- Operating revenue $ 43,813 $ 69,439 $ 110,608 $ 4,029 $ 2,936 $ 3,514 -------- ---------- ---------- -------- ------- ------ Amortization/depreciation and decommissioning collections $ 47,611 $ 55,286 $ 57,617 $ 319 $ 326 $ 364 Interest and preferred dividends 14,829 14,079 15,958 55 72 77 Other (income) expenses, net (23,267) (4,789) 32,117 2,274 (771) 2,125 --------- --------- --------- --------- ------ ---- Operating expenses $ 39,173 $ 64,576 $ 105,692 $ 2,648 $ (373) $2,566 -------- --------- --------- -------- ------- ----- Earnings applicable to common stock $ 4,640 $ 4,863 $ 4,916 $ 1,381 $ 3,309 $ 948 ======== ========= ========= ======== ======= ===== Amounts reported by the Company- Purchased power costs $ 5,013 $ 4,368 $ 7,185 $ - $ - $ - Equity in net income (320) (83) (215) ( 224) (199) (123) -------- --------- ---------- -------- ------- ------ Net purchased power expense $ 4,693 $ 4,285 $ 6,970 $ (224) $ (199) $(123) ========= ========= ========= ======= ====== ===== Financial Position: As reported by investee- Plant in service $ 685 $ 685 $ 687 $25,593 $23,493 $23,633 Accumulated depreciation - - - (23,075) (23,015)(22,899) Other assets and deferred charges 892,693 1,049,287 1,182,611 3,355 7,589 4,781 --------- --------- --------- ------- ------- ------ Total assets $ 893,378 $1,049,972 $1,183,298 $ 5,873 $ 8,067 $ 5,515 Less- Preferred stock 15,000 15,000 16,800 - - - Long-term debt 40,800 54,000 68,433 - - 220 Other liabilities and deferred credits 766,984 905,994 1,018,575 863 4,339 2,079 --------- --------- -------- --------- ------- ------ Net assets $ 70,594 $ 74,978 $ 79,490 $ 5,010 $ 3,728 $ 3,216 ========= ========= ========== ======== ======= ======= Company's reported equity- Equity in net assets $ 4,942 $ 5,248 $ 5,564 $ 711 $ 529 $ 457 Adjust Company's estimated to actual 8 19 (125) (38) 1 (18) --------- --------- ----------- --------- ------- ------- Equity in net assets as reported $ 4,950 $ 5,267 $ 5,439 $ 673 530 $ 439 ========= ========= ========== ======= ======= ======= WYMAN 4 - The Company owned 8.33% (50 MW) of the oil-fired 600 MW Wyman Unit No. 4 in Yarmouth, Maine. In May 1999 the Company sold its interest in Wyman 4 to PP&L Global as part of its generation asset sale (see Note 10). The Company's proportionate share of the direct expenses of this unit, through the date of the sale, is included in the corresponding operating expenses in the Consolidated Statements of Income. Included in the Company's utility plant at December 31, 1998, with respect to this unit, was electric plant in service of $16,887,608 and accumulated depreciation of $(9,851,639). BANGOR VAR CO. - In 1990, the Company formed BVC, 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 in 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 later in Note 6. PENOBSCOT NATURAL GAS COMPANY - In 1998 the Company formed Penobscot Gas, whose sole function was to be a 50% general partner in Bangor Gas Company, LLC (Bangor Gas), which is constructing a natural gas distribution system in the greater Bangor, Maine area. Sempra Energy (Sempra), a joint venture of Pacific Enterprises and Enova Corporation, owned the other 50% interest in Bangor Gas. Gas service to Maine has become feasible for the first time because of the development of the Maritimes & Northeast Pipeline Project, extending from the Sable Offshore Energy Project near Sable Island, Nova Scotia, through the state of Maine and interconnecting with the Tennessee Gas Pipeline in Dracut, Massachusetts. The pipeline passes near the Bangor area. As the restructuring of the electric industry in Maine has developed, the Company became increasingly cognizant of the need to focus on its core electric transmission and distribution business. Consequently the Company determined that it no longer intended to participate in the Bangor Gas joint venture, and on July 13, 2000, the Company and Penobscot Gas completed a stock purchase agreement to sell the Company's interest in Penobscot Gas to Sempra. A one-time gain on the sale of Penobscot Gas of approximately $1.2 million was recognized in the third quarter of 2000 and is included as a component of Other Income in the Consolidated Statements of Income for the year ending December 31, 2000. The completion of this sale has no impact on the proposed merger agreement with Emera which is discussed in Note 11. At December 31, 1999 and 1998, Penobscot Gas had approximately a $328,000 and $77,000 equity investment in Bangor Gas, respectively. Penobscot Gas recorded equity losses in Bangor Gas of approximately $274,000, $249,000 and $98,000 for the years ended December 31, 2000, 1999 and 1998, respectively. Bangor Gas' total assets, principally construction work in progress, amounted to $12.5 million and $2.9 million at December 31, 1999 and 1998, respectively. Summary Financial Information for Bangor-Pacific and Chester: ----------------------------------------------------------------------- Bangor-Pacific Chester ----------------------------------------------------------------------- (Dollars in Thousands) ----------------------------------------------------------------------- 1999* 1998 2000 1999 1998 --------- --------- --------- --------- ------- Operations: As reported by investee- Operating Revenue $ 4,426 $ 7,309 $ 4,235 $ 4,406 $4,535 --------- --------- --------- --------- ------ Depreciation $ 511 $ 868 $ 1,076 $ 1,075 $1,075 Interest expense 1,688 3,082 2,495 2,616 2,737 Other expenses, net 497 890 664 715 723 ----------- ---------- ---------- ---------- ----- Operating expenses $ 2,696 $ 4,840 $ 4,235 $ 4,406 $4,535 ----------- ---------- ---------- ---------- ------ Net Income $ 1,730 $ 2,469 $ - $ - $ - ========= ========= ========== ========= ====== Company's reported equity in net income $ 865 $ 1,235 $ - $ - $ - ========== ========= ========= ========== ====== Financial Position: As reported by investee- Plant in service $ - $ 44,047 $ 32,028 $ 31,993 $ 31,993 Accumulated depreciation - (9,031) (10,632) (9,598) (8,523) Other assets - 3,308 2,686 3,003 3,008 ---------- ---------- ---------- ---------- ------- Total assets $ - $ 38,324 $ 24,082 $ 25,398 $ 26,478 Less- Long-term debt - 26,300 22,288 23,471 24,654 Other liabilities - 2,517 1,794 1,927 1,824 ----------- ---------- ---------- ---------- -------- Net assets $ - $ 9,507 $ - $ - $ - =========== ========= ========= ========= ======== Company's reported equity in net assets $ - $ 4,754 $ - $ - $ - =========== ========= ========= ========= ======== *Financial information related to the operations of Bangor-Pacific is presented for the first seven months of 1999, prior to the sale of PHC. SMALL POWER PRODUCTION FACILITIES- As of the end of 2000, the Company had contracts with six in-dependent, non-utility power producers known as "small power production facilities." The West Enfield Project, described below, is one such facility. There are four other relatively small hydroelectric facilities, and a 20 MW facility fueled by municipal solid waste (see PERC discussion below). 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 were much higher than at present, and when forecasts for the costs of the Company's long-term power supply were higher than current forecasts. The Company had been attempting to alleviate the adverse impact of high-cost contracts with small power production facilities. One method for doing so had 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. These contract terminations have resulted in significant savings in purchased power costs, and the Company believes such savings will continue over the long term. 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. The remaining outstanding principal of these First Mortgage Bonds was repaid in August 1999 through the utilization of generation asset sale proceeds. 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 agreed to pay the Company $1 million annually for a six-year period beginning in 1994 in return for retaining the ownership and the option of operating the plant. The payments were secured by a mortgage on the property of the Beaver Wood facility. In each of the years from 1994 through 1997 the Company received its $1 million payment. The Company was entitled to receive the final two payments totaling $2 million in 1998 and 1999 from Beaver Wood. However, in July 1998, Beaver Wood indicated that it would not be making the payment due at that time and requested the Company agree to a lower payment. After assessing the potential costs and benefits of foreclosing on the mortgage, the Company determined that accepting a payment of $1.75 million would be a better alternative. This $1.75 million payment was received in February 1999. Management believes it is entitled to recover the $250,000 shortfall from its customers, and therefore it has been recorded as a regulatory asset as of December 31, 2000. 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 could 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 was 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 connection with the temporary rate increase effective July 1, 1997, the MPUC required the Company to accelerate the amortization of this regulatory asset, and effective December 12, 1997, the MPUC authorized the Company to revert to the original amortization schedule. Effective with the rate order in February 1998, the amortization was reduced, so that the unamortized balance of the regulatory asset would be the same as under the original amortization schedule as of March 1, 2000. Effective March 1, 2000, this regulatory asset is being amoritized at an annual rate of $3.9 million through February 2003. 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 buyback costs were deferred and recorded as a regulatory asset and are being amortized and collected over a ten-year period, beginning July 1, 1995. The cost of the buy-back was financed entirely by new debt instruments, thereby significantly increasing the Company's indebtedness (see Note 4). In June 1998 the Company successfully completed this major restructuring of its obligations under various agreements with PERC. It is anticipated that the restructuring will result in a substantial savings for the Company and will allow PERC to continue to meet the solid waste disposal needs of Maine communities. PERC owns a 20 MW waste-to-energy facility in Orrington, Maine, that provides solid waste disposal services to many communities in central, eastern, and northern Maine. The contract requires the Company to purchase the electricity output of the plant until 2018 at a price that is presently above the cost of alternative sources of power, and, in the Company's opinion, is likely to remain so. The Company's net purchased power expense under this contract was approximately $14.9 million in 2000 and is projected to be $15-16 million annually, net of revenues from the resale of power to another utility through 2002, and is projected to be approximately $20-$30 million annually from 2003 through the end of the contract. This major restructuring involved several separate components including the following: 1) PERC refinanced $45 million in existing bonds with a remaining five-year term over a twenty-year period using tax exempt bonds issued by the Finance Authority of Maine under its Electric Rate Stabilization Program. 2) PERC will share the net revenues generated by the facility on a pro rata basis with the Company and the Municipal Review Committee (MRC) which represents over 130 Maine municipalities receiving waste disposal service from PERC. In 2000, 1999 and 1998 the Company realized $3.5 million, $2.9 million and $2 million, respectively, in savings associated with its share of PERC net revenues. The Company expects to realize approximately $3.6 million annually in such savings through the term of the PERC contract. 3) The Company made a onetime payment of $6 million to PERC in June 1998 and is making additional quarterly payments, starting in October 1998, of $250,000 for four years totaling $4 million. 4) The Company and PERC amended their existing power purchase agreement to include the MRC as a party. 5) The MRC's constituent municipalities extended their contracts with PERC by 15 years to supply solid waste to the facility through 2018. 6) The Company issued two million warrants to purchase common stock, one million each to PERC and the MRC. Each warrant entitles the warrant holder to acquire one share of the Company's common stock at a price of $7 per share. No warrants could be exercised within the first nine months after their issuance, and they are exercisable in 500,000 share blocks following the expiration of nine months, 21 months, 33 months, and 45 months from the closing date. Upon exercise, the Company has the option, instead of providing common stock, to pay cash equal to the difference between the then market price of the stock and the exercise price of $7 per share times the number of shares as to which exercise is made. The MPUC has established a cap on ratepayers' exposure to the cost of the warrants. Ratepayer costs are limited to the difference between the higher of $15 per share or the book value per share at the time the warrants are exercised and the $7 exercise price. The Company would not recover any costs above the cap from ratepayers. As previously discussed in Note 3, in 2000 and 1999, 212,786 and 349,999 common stock warrants were exercised (at a market prices below the book value per common share at the time of the exercise), respectively, and the Company exercised its option to pay cash to the holders of the warrants instead of actually issuing shares of common stock. These payments amounted to approximately $2.5 million in 2000 and $3.3 million in 1999. Since the common shares were not issued, and the Company had recorded the estimated fair value of these warrants when issued in June 1998, amounting to approximately $248,000 and $410,000 for the 2000 and 1999 warrants, respectively, as an addition to the PERC regulatory asset, an adjustment has been made in connection with the cash payments option to increase the PERC regulatory asset by approximately $2.1 million and $2.9 million as of December 31, 2000 and 1999, respectively. The additional regulatory assets in 2000 was reduced by approximately $375,000 to reflect the value of the warrants exercised at a price in excess of the previously discussed cap. This amount was charged to fuel for generation and purchased power expense in 2000. The refinancing by PERC was made possible by the Maine Legislature through an amendment to the Electric Rate Stabilization Program that allowed PERC to qualify for such financing. Under the Program, the state of Maine's "moral obligation" supports the new nonrecourse debt. As of December 31, 2000, the Company has deferred, as a regulatory asset, approximately $14 million in connection with the PERC restructuring. Effective with the implementation of new rates on March 1, 2000, the Company began recovering the full amount of deferred PERC restructuring costs, including an estimate of the future value of warrants to be exercised and the additional $250,000 quarterly payments discussed above, amounting to an annual amortization of $1.6 million per year. The Company is not receiving a return on unexercised warrants, but may accrue carrying costs on the value of any warrants exercised until the amounts are included in the determination of new rates in the future. 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. PHC was formed to own the Company's 50% interest in the joint venture, Bangor- Pacific. Bangor-Pacific financed the 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. In late July 1999, in connection with the generation asset sale, the Company sold PHC to PP&L and received $10 million in proceeds. The sale resulted in a gain of approximately $5.2 million, of which $4.7 million was deferred as part of the deferred asset sale gain as of December 31, 1999 (see Note 10). The remaining $.5 million of the gain related to the portion of the gain on sale of PHC which was allocable to shareholders (recorded as Other Income in the Consolidated Statements of Income for the year ending December 31, 1999). Under the purchased power contract with Bangor-Pacific, if the project operates as anticipated, payments by the Company to Bangor-Pacific are estimated to be about $7.5 million. 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 twelve consecutive months. Information relating to the operations of Bangor-Pacific appears earlier in Note 6. OTHER POWER SUPPLY COMMITMENTS - The Company had a contract, which started on March 1, 2000, for the delivery of up to 100 MW of power from another utility, ending February 28, 2001. The energy delivered in connection with the contract was used to serve a portion of the standard offer service customer load. See Note 10 for a discussion of the standard offer service. The Company's purchased power expense under this contract was approximately $26 million in 2000. In late 1999 the Company selected Morgan Stanley Dean Witter & Co., subsidiary Morgan Stanley Capital Group Inc., (Morgan Stanley) as the winning bidder for all of the capacity and energy from its six purchased power contracts being auctioned off pursuant to Chapter 307 of Maine's 1997 law restructuring the State's electric industry. The purchased power contracts provide 38 MWs of capacity and 218,000 MWHs of energy from hydro and biomass generation in Maine. The Morgan Stanley contract commenced March 1, 2000, the date when retail customer choice for power supply commenced in Maine, and will continue for a period of two years. This transaction was approved by the MPUC. Included in the sale are 16 MWs of capacity and associated energy from the Company's contract with PERC and all the capacity and energy from the Company's 19 MW hydro contract with Bangor-Pacific. Also a part of the transaction are all of the energy and capacity from the Company's several smaller agreements with Pumpkin Hill, Milo, Green Lake and Sebec Hydro. The Company recorded $4.5 million in revenues from the resale of power to Morgan Stanley in 2000. In connection with the Company's current rate proceeding with the MPUC, the cost of energy and capacity associated with these agreements, net of the revenues to be realized from the resale to Morgan Stanley are being recovered from customers as stranded costs. Also being recovered as stranded costs are the Company's obligations under the regional utilities agreements with Hydro-Quebec. 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 had established a reserve against those investments in the amount of $8.7 million as of December 31, 1993. Since 1993 the Company had charged to non-operating expense all amounts related to these licensing activities. The projects for which the reserve was established are a proposed 38 MW generating facility located at the so- called Basin Mills site on the Penobscot River in Orono and Bradley, Maine, and an 8 MW addition to the Company's existing dam and power station on the Penobscot River in Veazie and Eddington, Maine. As discussed in Note 10, the Company's investment in the Basin Mills and Veazie projects were included in the assets sold as part of its generation asset sale, and the $8.7 million reserve was reversed during 1999. Note 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. Note 8. Unaudited Quarterly Financial Data ------------------------------------------ Unaudited quarterly financial data pertaining to the results of operations are shown below (Dollars in thousands except for per share amounts): Quarter Ended -------------------------------------------- Mar. 31 June 30 Sept. 30 Dec. 31 -------------------------------------------- 2000 ------ Electric Operating Revenue $ 50,121 $ 48,563 $ 58,641 $ 55,012 Operating Income 8,307 4,652 6,535 6,930 Net Income 3,937 1,339 3,940 1,885 Basic Earnings Per Share of Common Stock $ .53 $ .17 $ .53 $ .25 ========== ========= ========= =========== 1999 ------ Electric Operating Revenue $ 50,222 $ 47,299 $ 51,452 $ 49,022 Operating Income 9,886 8,502 9,331 8,439 Net Income 4,212 3,452 5,037 5,580 Basic Earnings Per Share of Common Stock $ .53 $ .43 $ .65 $ .74 ========== ========= ========= =========== 1998 ------ Electric Operating Revenue $ 49,100 $ 46,601 $ 49,158 $ 50,285 Operating Income 8,410 8,006 9,087 9,633 Net Income 2,408 2,267 2,949 3,841 Basic Earnings Per Share of Common Stock $ .28 $ .27 $ .36 $ .48 ========== ========= ========= =========== Note 9. Fair Value of Financial Instruments ------------------------------------------- The following represents the estimated fair value at December 31, 2000 of each class of financial instrument for which it is practical to estimate the value: Cash and cash equivalents-including investments in commercial paper, U.S. bank certificates of deposits and bankers' acceptances, and variable rate master demand notes: the carrying amount of $12,462,780 approximates fair value. Funds held by trustees and miscellaneous special deposits-Money market funds and U.S. Treasury Bills: the carrying amount of $1,914,221 approximates fair value. The fair values of other financial instruments at December 31, 2000 based upon similar issuances of comparable companies are as follows: (In Thousands) Carrying Amount Fair Value --------------- ---------- Funds held by trustee-guaranteed investment contract $21,188 $22,069 First Mortgage Bonds 85,000 95,619 FAME Revenue Notes 86,600 87,787 Medium Term Notes-LIBO rate plus 1.125% 11,700 11,700 Note 10. Industry Restructuring and Rate Regulation --------------------------------------------------- INDUSTRY RESTRUCTURING - In connection with the state of Maine's electric industry restructuring law, effective March 1, 2000, consumers of electricity had the right to purchase generation services directly from competitive electricity suppliers. In February 2000, and in connection with the implementation of the restructuring law, the Company received a final rate order from the MPUC setting its transmission and distribution and stranded cost rates effective March 1, 2000. The Company's total annual revenue requirement as set in the rate proceedings, including $40 million associated with stranded cost recovery, amounted to $103.2 million. The stranded cost recovery includes the decommissioning and other plant closure expenses for Maine Yankee. There were no write-offs of previously deferred costs based on the final rate order. In Maine, stranded costs are treated in the same manner as most other costs and may be included in calculations for prospective rate changes. Absent any rate proceedings, however, in 2003 and every three years thereafter until the stranded costs are recovered, the MPUC shall review and reevaluate the stranded cost recovery. Customers reducing or eliminating their consumption of electricity by switching to self- generation, conversion to alternative fuels or utilizing demand-side management measures cannot be assessed exit or entry fees. The restructuring law also provided for a standard-offer service being available for all customers who did not choose to purchase energy from a competitive supplier starting March 1, 2000. As a result of the bids from competitive energy suppliers to provide energy under the standard- offer service being higher than anticipated, and as ordered by the MPUC, the Company assumed the responsibility of being the standard- offer service provider starting March 1, 2000 for a one-year period. The MPUC established the schedule of rates the Company could charge for this service starting March 1, 2000. The Company entered into arrangements with third parties to purchase the energy to serve the standard- offer customers. The Company is allowed by the MPUC to defer the difference between revenues realized from the standard-offer sales and the costs incurred to provide this service, including carrying costs on the deferred balance. The deferred amount will be recovered from/returned to customers in the future. Since March 1, 2000, when new rates went into effect, the costs of providing the standard offer service have exceeded the revenues realized from customers, and consequently, the Company has recorded a regulatory asset of $3.1 million, including carrying costs, as of December 31, 2000 (which is included in Other regulatory assets on the Consolidated Balance Sheets). The excess of costs is due principally to unusually high purchased power costs for one day in May 2000, which is discussed below, and higher than anticipated spot energy market prices in the summer of 2000. As a result of the growth in the balance of this regulatory asset, the MPUC approved standard offer service rate increases for customers in each of August and October 2000. These rate increases were necessitated to avoid a in the balance of this regulatory asset, the MPUC approved standard offer service rate increases for customers in August and October 2000. These rate increases were necessitated to avoid a deficiency in standard offer service revenues that the Company projected would otherwise result based on actual costs already incurred and projected costs through February 2001. In October 2000, the MPUC issued a Request for Proposal seeking firms willing to supply standard-offer service for the Company's service territory. In part because of rapidly changing conditions in the electricity markets, the MPUC did not receive any acceptable proposals. In December 2000 the MPUC directed the Company to explore power supply arrangement to assist the MPUC in fulfilling its obligation to provide standard-offer service. In February 2001, based on orders from the MPUC, the Company retained responsibility as the standard-offer service provider starting March 1, 2001. The MPUC initially set the standard- offer power supply price for small (residential and non-residential) and medium non-residential electric customers located in the Company's service territory for the period from March 1, 2001 through February 28, 2002 at a rate which is approximately 20% above the then current standard-offer price. The MPUC also set the standard-offer electric supply price for the Company's large customers for this same period at a rate approximately 29% above the then current standard-offer price. The MPUC also approved additional power contracts which the Company was able to procure at the request of the MPUC locking in prices for a portion of the projected standard-offer load over the next three years. The Company will continue to be allowed by the MPUC to defer the difference between revenues realized from the standard-offer sales and the costs incurred to provide this service, including carrying costs on the deferred balance. As a result of the previously discussed reconciliation mechanism, standard-offer related revenues and expenses do not have any impact on the Company's earnings, although they do result in increases in both categories in the Company's Consolidated Statements of Income. Consequently, the Consolidated Statement of Income for 2000 has been modified to reflect the separate presentation of standard-offer service revenues and purchased power expenses. SALE OF THE COMPANY'S GENERATING ASSETS - On May 27, 1999, the Company completed most of the transaction for the sale of its electric generating assets and certain transmission rights to PP&L. The purchase price for the assets transferred was $79 million. The sale involved all but one of the Company's hydroelectric plants on the Penobscot, Piscataquis, and Union rivers and Bangor Hydro's 8.33% ownership interest in the Wyman Unit #4 oil-fired plant in Yarmouth, Maine-a total base load capacity of 83 megawatts. The sale also involved a transfer by the Company of rights to transmit power over the MEPCO transmission facilities connecting NEPOOL to New Brunswick Canada; the Company's rights as a participant in the regional utilities' agreement with Hydro-Quebec pursuant to an agency agreement; and the Company's rights to develop a second high voltage transmission line that will connect NEPOOL to New Brunswick, Canada. The Company conducted an auction in 1998, which led to the signing of a purchase and sale agreement with PP&L in late September 1998. The purchase and sale agreement also included the Company's 50% interest in the 13 megawatt West Enfield hydro station on the Penobscot River. In late July 1999, the Company received $10 million in proceeds from the transfer of the economic interest in that project, and in late August 1999, the MPUC approved the sale to PP&L of PHC. The Company has utilized a significant portion of the net proceeds of the sale to reduce outstanding debt and preferred stock. The Company realized a net gain on the sale related to the PP&L sale of approximately $24.6 million, and $24.1 million of this amount was recorded as a deferred liability at February 29, 2000, on the Consolidated Balance Sheets. Included in the determination of the deferred gain on sale was the accrual of carrying costs on the deferred gain balance, the selling and closing costs associated with the asset sale, the costs incurred for the early retirement of debt and preferred stock through the utilization of asset sale proceeds, income tax expense impacts associated with the asset sale gain, and the net expense associated with the sale of its generating assets and the simultaneous purchased power buyback agreement with PP&L. As discussed in Note 6, the other $.5 million of the gain on the sale of Penobscot Hydro that was allocable to shareholders, pursuant to orders of the MPUC, was recorded as other income in 1999. As specified in the February 2000 rate order from the MPUC, which is discussed above, the deferred gain is being utilized over a 70 month period to reduce electric rates effective March 1, 2000. The annual amortization amounts are to be recorded in an uneven manner in order to levelize the Company's revenue requirement over this period. As a result of an increase in the Company's FERC regulated transmission rates on June 1, 2000, and the desire to not increase rates to its retail customers close to the implementation of electric industry restructuring, which occurred on March 1, 2000, the Company agreed to reduce its MPUC jurisdictional distribution rates in an amount equal to the increase in its transmission rates. The reduction in the distribution rates was accomplished by accelerating the amortization of the deferred asset sale gain by an annualized total of $2.5 million. The Company recorded $491,000 of amortization for April and May of 2000 and increased the monthly amortization to $703,000 starting in June 2000. In September 1998, the Company sold certain property and equipment at its Graham Station site in Veazie, Maine, to Casco Bay Energy for $6.2 million. The Company realized a net gain from the sale of $5.2 million, which was recorded as a deferred liability at February 29, 2000. Included in the determination of this deferred gain was the accrual of carrying costs on the deferred gain balance, the selling and closing costs associated with the asset sale, and the net savings associated with the sale of these assets (through reduced depreciation and property tax expense, and the return on these assets included in the Company's rates through February 29, 2000). Consistent with the deferred gain on sale of generating assets discussed above, this $5.2 million gain also began to be utilized to reduce electric rates starting March 1, 2000. In connection with the sale, the $6.2 million in proceeds were deposited with a third party trustee, as a requirement under the Company's bond indenture. The $6.2 million was released by the trustee in January 1999 and was utilized to repay a portion of the Company's medium term notes. Also in connection with the sale, the Company deposited $400,000 with a third party trustee to be utilized for future environmental remediation at the site. As of December 31, 2000, the environmental remediation activities have been completed through the utilization the these funds. DEFERRAL OF RESTRUCTURING RELATED COSTS - Also as part of the restructuring law, employees, other than officers, displaced as a result of retail competition are entitled to certain severance benefits and retraining programs, and these costs are recoverable through charges collected by the regulated distribution company. In connection with this part of the law, the Company incurred approximately $840,000 in benefit costs associated with the employees terminated as a result of the generation asset sale. This amount was deferred as a component of Other Regulatory Assets on the Consolidated Balance Sheets as of December 31, 1999. In 1999, the Company had also been incurring significant costs in connection with implementing various aspects of the electric industry restructuring. Consequently, the Company filed an accounting order request with the MPUC in 1999 to seek the deferral of certain incremental costs associated with this effort. In September 1999 the Company received an accounting order from the MPUC related to the Company's request which approved the deferral of certain incremental restructuring related costs. In connection with the accounting order, the Company also deferred, as a component of Other Regulatory Assets on the Consolidated Balance Sheets as of February 29, 2000, approximately $932,000 of restructuring costs. As a result of the February 2000 rate order received from the MPUC, the Company began recovering on March 1, 2000, the deferred restructuring costs discussed above over a three-year period. DEFERRED SPECIAL RATE CONTRACT REVENUES - Also in connection with the February 2000 rate order from the MPUC, and starting March 1, 2000, the Company was granted a deferral mechanism for the difference in actual revenues realized from customers under special rate contracts as compared to the estimated revenues from these customers utilized in setting the Company's new electric rates starting March 1, 2000. Under this deferral mechanism, the Company recorded a regulatory asset and additional revenues of approximately $1.4 million for the period from March 1, 2000 through December 31, 2000. The regulatory asset is included as a component of Other Regulatory Assets in the Consolidated Balance Sheet at December 31, 2000 and the additional revenues are included as a component of Electric Operating Revenue in the Consolidated Statements of Income for 2000. REGULATORY ASSETS AND MEETING THE REQUIREMENTS OF SFAS 71 - The Company is subject to the provisions of Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS 71). SFAS 71 allows the establishment of regulatory assets for costs accumulated for certain items other than the usual and customary capital assets, and allows the deferral of the income statement impact of those costs if they are expected to be recovered in future rates. As of December 31, 2000, the Company has regulatory assets, net of regulatory liabilities, of approximately $173.3 million. The Company continues to meet the requirements of SFAS 71 since the Company's rates are intended to recover the cost of service plus a rate of return on the Company's investment, as well as providing specific recovery of costs deferred in prior periods. The recent legislation enacted in Maine associated with industry restructuring specifically addressed the issue of cost recovery of regulatory assets stranded as a result of industry restructuring. Specifically, the legislation requires the MPUC, when retail access begins, to provide a "reasonable opportunity" for the recovery of stranded costs through the rates of the transmission and distribution company, comparable to the utility's opportunity to recover stranded costs before the implementation of retail access under the legislation. The final rate order from the MPUC effective March 1, 2000 did not result in the Company writing off any stranded costs, but if the Company had not been allowed full recovery of its stranded costs, it would be required to write-off any disallowed costs. As provided for in Emerging Issues Task Force Issue No. 97-4, "Deregulation of the Pricing of Electricity," the Company will continue to record regulatory assets in a manner consistent with SFAS 71 as long as future recovery is probable, since the Maine legislation provides the opportunity to recover regulatory assets including stranded costs through the rates of the T&D company. The Company anticipates, based on current generally accepted accounting principles, that SFAS 71 will continue to apply to the regulated T&D segments of its business. If the Company failed to meet the requirements of SFAS 71, due to legislative or regulatory initiatives, the Company would be required to apply Statement of Financial Accounting Standards No. 101, "Regulated Enterprises-Accounting for the Discontinuation of Application of FASB No. 71" (SFAS 101). If legislative or regulatory changes and/or competition result in electric rates which do not fully recover the Company's costs, a write-down of regulatory assets would be required. The Company does not anticipate any write-down of assets at this time. Note 11. Proposed Merger Agreement With Emera ---------------------------------------------- On June 29, 2000, the Company entered into a definitive merger agreement with Emera of Halifax, Nova Scotia, pursuant to which Emera will acquire all of the outstanding shares of common stock of Bangor Hydro for US$26.50 per share in cash. After the closing of the merger, each of Bangor Hydro's outstanding warrants to purchase common stock will entitle the holder to receive US$26.50 in cash, less the exercise price. For a discussion of the common stock warrants, see Note 6 of the notes to the consolidated financial statements. The equity market value of the transaction is approximately $206 million. The transaction will take the form of a merger of Bangor Hydro with a U.S. corporate subsidiary to be formed by Emera. Upon completion of the merger, Bangor Hydro will be a wholly-owned subsidiary of Emera. Bangor Hydro's outstanding debt and preferred stock will not be affected by the transaction. The transaction is subject to a number of approvals, including the approval of Bangor Hydro's shareholders, which was accomplished on October 24, 2000, and regulatory approvals from the MPUC, and the FERC, which occurred on January 5, 2001 and January 24, 2001, respectively, and the U.S. Securities and Exchange Commission (SEC) under the Public Utility Holding Company Act of 1935. Proceedings are pending at the SEC for what is anticipated to be the last major regulatory approval. The processes for all necessary regulatory approvals are expected to be complete in the first half of 2001. The MPUC order requires the Company to file an alternative rate plan with the MPUC within two months after the completion of the merger with Emera or June 30, 2001, whichever is earlier. In connection with merger related activities, the Company incurred approximately $3 million in incremental costs in 2000. These have been recorded as a component of Other Income (Expense) in the Consolidated Statements of Income for 2000. Note 12. Construction of Facilities for Casco Bay Energy -------------------------------------------------------- The Company entered into an agreement with Casco Bay whereby the Company agreed to construct various transmission facilities required to allow a generating facility being constructed in Veazie, Maine to interconnect with the Company's electrical system and deliver its output to the New England Power Pool Transmission Facility (PTF) grid. Under this agreement, Casco Bay agreed to advance funds necessary to pay for such construction. Pursuant to a FERC order approving an amendment to the NEPOOL Agreement, approximately 50% of the construction funds advanced will be refunded to Casco Bay by customers of NEPOOL over an approximately 30-year period. The Company began refunding such construction costs to Casco Bay starting in June 2000. At the end of 2000, the Company had recorded $4.1 million for PTF facilities and a corresponding Long-term Payable of $4 million. These amounts are included on the Consolidated Balance Sheets as components of Electric Plant in Service and Other Long-term Liabilities, respectively. Note 13. Storm Damage --------------------- The Company suffered widespread damage throughout its service territory to its transmission and distribution equipment during a major ice storm in January 1998. The Company's incremental costs associated with the service restoration effort were approximately $4.5 million, and these had been deferred as of December 31, 1998. The MPUC issued an order authorizing the Company to defer incremental, non-capitalized storm damage expenses for future recovery through the rates charged to customers. As discussed in Note 10, the Company began recovering these deferred costs starting on June 1, 1999, over a four-year period, as part of its annual rate adjustment pursuant to its Alternative Rate Plan. In October 1999, the Company received approximately $1.8 million in funds from the state of Maine as its share of the state's federal assistance. The $1.8 million was recorded as a reduction of the deferred ice storm costs. In connection with the Company's February 2000 rate order from the MPUC, the amortization and recovery of these deferred costs were adjusted effective March 1, 2000 to reflect the receipt of the federal funds. The deferred balance as of December 31, 2000, which amounted to $1.3 million, is included as a component of Other Regulatory Assets on the Consolidated Balance Sheets. Note 14. Derivative Financial Instruments ------------------------------------------- FUEL SWAPS - Through the advent of retail competition on March 1, 2000, the Company purchased, rather than generated itself, virtually all of the energy required to service its retail business. These purchased energy prices varied with changes in the price or availability of the underlying fuel sources, and the risk of such price volatility was not covered by a rate mechanism, such as a fuel adjustment clause. A significant portion of the Company's exposure to purchased energy price volatility had been closely matched to changes in residual oil prices. To manage the oil-related risk of energy price fluctuations, the Company had 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 transferred the risk (or the benefit) of commodity price fluctuations to the other party to the agreement for the given period of time. These were strictly financial transactions, and no delivery of the underlying commodity was taken. Settlements occurred on a monthly basis and the cash receipts/payments arising from the "swap" transactions offset corresponding increases/decreases in the Company's purchased energy costs. At December 31, 1999, the Company was a party to "swaps" covering 265,000 barrels of residual oil for the first two months of the year 2000. With the advent of retail competition in the electric utility industry starting March 1, 2000, and the Company providing only standard-offer service to customers in the retail market, the utilization of fuel swaps was no longer required (see Note 10). The Company received approximately $2.1 million in cash payments associated with swap transactions in January and February 2000. The Company entered into "swap" transactions for 1999 amounting to 1,600,000 barrels of residual oil, respectively. As a result of market movements in 1999 the Company received cash payments of approximately $1.8 associated with the swap transactions. The cash paid/received from the "swaps" was recorded as an increase/reduction in fuel for generation and purchased power expense in the Consolidated Statements of Income. The relationship between the Company's oil related purchased power costs and the index specified in the swap was highly correlated. As a result of the achievement of this high degree of correlation, the "swaps" were accounted for as hedges, and were not speculative financial instruments. INTEREST RATE SWAP - As discussed in Note 4, in connection with the $24.8 million in BERI medium term notes, BERI entered into an interest rate swap arrangement with a major financial institution to provide interest rate protection through the maturity date of the term loan. The interest rate swap fixed the LIBO interest rate on the medium term notes at 5.72%. BERI will be reimbursed for incremental interest expense incurred in excess of the 5.72% and incurs additional expense for incremental interest expense below 5.72%. Market risk is the potential loss arising from adverse changes in interest rates. The fair value of the interest rate swap at December 31, 2000 is $9,428 and represents the estimated payment that would be received to terminate the agreement. Note 15. Contingencies ---------------------- ENVIRONMENTAL MATTERS - In 1992, the Company received notice from the Maine Department of Environmental Protection 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 those 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. The Company has recorded a liability, based upon currently available information, for what it believes are the estimated environmental remediation costs that the Company expects to incur for this waste disposal site. Additional future environmental cleanup costs are not reasonably estimable due to a number of factors, including the unknown magnitude of possible contamination, the appropriate remediation methods, the possible effects of future legislation or regulation and the possible effects of technological changes. At December 31, 2000, the liability recorded by the Company for its estimated environmental remediation costs amounted to $282,000. The Company's actual future environmental remediation costs may be higher as additional factors become known. Note 16. New Accounting Pronouncement -------------------------------------- In May 1999, the Financial Accounting Standards Board voted to delay for one year the effective date of Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS 133). The new effective date for implementing this pronouncement is for fiscal years beginning after June 15, 2000. Based on current guidance, management does not believe that the adoption of SFAS 133 will have a material effect on the Company's financial statements. PricewaterhouseCoopers Report of Independent Accountants To the Stockholders and Directors of Bangor Hydro-Electric Company: In our opinion, the consolidated financial statements listed in the index appearing under Item 14(a) present fairly, in all material respects, the financial position of Bangor Hydro-Electric Company (the "Company") and its subsidiaries at December 31, 2000 and 1999, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2000 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 14(b) present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedules are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements and financial statement schedules based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. PricewaterhouseCoopers LLP Boston, MA February 2, 2001 ITEM 7A QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK ------- ---------------------------------------------------------- See Item 7, "Management's Discussion and Analysis of Results of Operations and Financial Condition - Contingencies and Disclosures About Market Risk" for a discussion of certain derivative financial instruments held by the Company. 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 ------- -------------------------------------------------- The following table sets forth the nominees and the directors whose terms continue, their ages, other positions held by them with the Company, the date when they first became a director and their business experience during the last five years (including any other directorship held by them in any company with a class of securities registered pursuant to Section 12 of the Securities Exchange Act of 1934 or subject to the requirements of Section 15(d) of that Act, or in any company registered as an investment company under the Investment Company Act of 1940 (referred to in the table as "Reporting Companies")): Name and Became Business Experience During Last 5 Years Position (Age) Director and Other Directorships ----------------------------------------------------------------------------- CLASS III (DIRECTORS WHOSE TERMS EXPIRE IN 2001) Carroll R. Lee (51) Senior Vice President & Chief Operating Officer and Director 1991 Senior Vice President and Chief Operating Officer of the Company; President of the Board of Community Health and Counseling Service, a not-for-profit supplier of home and mental health care services David M. Carlisle (62) Director 1989 President, Prentiss & Carlisle Companies, a timberland management company; Director of Bangor Savings Bank; Director of Eastern Maine Healthcare Jane J. Bush (55) Director 1990 Vice President and co-owner of Coastal Ventures, a retailing company CLASS I (DIRECTORS WHOSE TERMS EXPIRE IN 2002) Marion M. Kane (56) Director 1996 President of the Barr Foundation, a not-for-profit charitable organization that manages a charitable trust; until December 31, 1999, President of the Maine Community Foundation, a not-for-profit charitable foundation that manages a pool of individual charitable funds; Director of Maine Bank and Trust Company Norman A. Ledwin (59) Director 1996 President and Chief Executive Officer and a Director of Eastern Maine Healthcare, a healthcare organization made up of not-for- profit and for-profit entities (including Eastern Maine Medical Center, a not-for-profit regional acute care hospital facility) James E. Rier, Jr.(55) Director 1998 Former President of Rier Motors Co., an automobile dealership located in Machias, Maine CLASS II (DIRECTORS WHOSE TERMS EXPIRE IN 2003) Robert S. Briggs (57) Chairman of the Board, President & Chief Executive Officer 1985 Chairman of the Board; President and Chief Executive Officer of the Company; Director of Maine Yankee Atomic Power Company; Trustee of Eastern Maine Medical Center William C. Bullock, Jr. (64) Director 1982 Chairman of the Board and Director of Merrill Merchants Bancshares, Inc. (a reporting company) and its subsidiary, Merrill Merchants Bank; Director of Eastern Maine Healthcare Joseph H. Cyr (60) Director 1998 President of John T. Cyr & Sons, Inc., a school and charter bus company; Director of Merrill Merchants Bancshares, Inc. (a reporting company) and its subsidiary, Merrill Merchants Bank In 2000, the Board met on fourteen occasions. The Board of Directors has three standing committees: an Audit Committee, an Investment Committee and a Compensation Committee. The Audit Committee, consisting of Ms. Bush (Chair), Mr. Carlisle, Mr. Rier and Ms. Kane reviews with the independent public accountants the scope and results of their audit and other services to the Company, reviews the adequacy of the Company's internal accounting controls and reports to the Board as necessary. The Audit Committee met five times during 2000. The Compensation Committee, consisting of Mr. Bullock (Chair), Mr. Cyr and Mr. Ledwin, reviews the Company's executive compensation and compensation policies in general, and makes recommendations to the full Board of Directors. The Compensation Committee met once during 2000. The Investment Committee, consisting of Mr. Bullock (Chair), Mr. Carlisle, Ms. Kane, Mr. Briggs and other non-director members of management, oversees the investments of the Company's pension funds. The Compensation Committee met twice during 2000. The Board does not have a nominating or similar committee. Directors who are not employees of the Company appoint from their own number the members of the Audit Committee and the Compensation Committee. Other committee assignments are made by the Chairman of the Board. 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 57 President & Chief Executive Officer since January 1991 Carroll R. Lee 51 Senior Vice President and Chief Operating Officer since December, 1996 Frederick S. Samp 50 Vice President - Finance & Law since 1995; Chief Financial Officer since September, 1995 Paul A. LeBlanc 53 Vice President - Human Resources & Information Services since November, 1996 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, Vice President-Planning & Development from 1987 until 1990 and Vice President-Operations from 1990 until 1996. Mr. Samp was Corporate Counsel, Corporate Secretary and Clerk from 1985 until 1988, General Counsel, Corporate Secretary and Clerk from 1988 until 1995, and Treasurer from 1995 until 1999. Mr. LeBlanc was Vice President- Administration from 1978 until 1987, Vice President-Customer Services from 1987 until 1988 and Assistant to the President from 1988 until 1996. ITEM 11 EXECUTIVE COMPENSATION ------- ---------------------- The following table shows, for the fiscal years ending December 31, 2000, 1999, and 1998, the cash compensation paid by the Company to the Chief Executive Officer and to the other executive officers whose total salary and bonus exceeded $100,000: SUMMARY COMPENSATION TABLE - ANNUAL COMPENSATION Other Annual Name and Principal Position Year Salary Bonus Compensation* ------------------------------------------------------------------------- Robert S. Briggs 2000 $236,102 $6,564 $3,400 Chairman of the Board, President 1999 $207,549 $66,499 $3,200 & Chief Executive Officer 1998 $200,981 $41,726 $3,200 Carroll R. Lee 2000 $180,289 $5,029 $3,400 Senior Vice President & 1999 $161,149 $37,968 $3,200 Chief Operating Officer 1998 $153,645 $24,468 $3,200 Frederick S. Samp 2000 $131,206 $3,664 $3,046 Vice President-Finance & Law 1999 $112,574 $21,457 $2,527 1998 $101,807 $14,337 $2,159 Paul A. LeBlanc 2000 $121,285 $3,383 $2,800 Vice President-Human Resources 1999 $101,031 $19,197 $2,246 & Information Services 1998 $ 94,961 $12,093 $1,984 * For each named executive officer, Other Annual Compensation consists of the Company's matching contribution to a 401(k) Plan. The executive officers participate in a tax qualified defined benefit pension plan that is also applicable to all employees. In addition, the executive officers are parties to Supplemental Benefit Agreements with the Company under which additional retirement benefits are to be paid. Said agreements define the total pension amount to be paid to the executive officer by the Company, with the supplemental amount defined as the difference between this total amount due and the amount due to the executive officer under the tax qualified pension plan applicable to all employees. The total amount of pension benefit, as defined under the Supplemental Benefit Agreements, is a function of the executive officer's age at retirement and his average total compensation over a three-year period. Under the Supplemental Benefit Agreements, no pension amount would be due until the executive officer reaches age 55. At age 55, the executive officer would be entitled to receive 50% of his or her average total compensation over a three-year period. The total pension amount to be paid upon retirement would increase proportionately until a retirement age of 62, at which point the executive officer would be entitled to receive upon retirement 75% of his or her average total compensation over a three-year period. The following table sets forth estimated annual benefit amounts payable upon retirement after age 55 to the executive officers: Age at Retirement ----------------------------------------------------------------------------- Average Total Compensation 55 56 57 58 59 60 61 62+ $100,000 $50,000 $53,000 $57,000 $60,000 $64,000 $68,000 $72,000 $75,000 $150,000 75,000 79,500 85,500 90,000 96,000 102,000 108,000 112,500 $200,000 100,000 106,000 114,000 120,000 128,000 136,000 144,000 150,000 $250,000 125,000 132,500 142,500 150,000 160,000 170,000 180,000 187,500 $300,000 150,000 159,000 171,000 180,000 192,000 204,000 216,000 225,000 Compensation covered under the defined plan applicable to all employees is total basic compensation exclusive of overtime, bonuses, and other extra, contingent or supplemental compensation, and inclusive of compensation deferred pursuant to the Company's Section 401(k) Plan. Compensation covered under the tax qualified pension plan is limited to the amount set forth in IRC Section 415. Subject to this limitation, it is essentially the same as the amount shown as "Salary" in the Summary Compensation Table above. Compensation covered by the Supplemental Benefit Agreements is total compensation inclusive of bonuses, and other, contingent or supplemental compensation, and compensation deferred pursuant to the Company's Section 401(k) Plan. It is essentially the same as the amount shown as "Salary" and "Bonus" in the Summary Compensation Table above. "Average Total Compensation" for both plans is computed using the average of the total annual compensation actually paid by the Company to the Executive during the three (3) consecutive calendar years in which the Executive's total compensation from the Company was the highest. The total annual pension amounts shown in the Pension Plan Table above are payable for the remainder of the executive officer's life after retirement. If the executive officer's spouse survives the executive officer, the spouse will receive an annual benefit for the remainder of her life equal to 50% of the annual benefit to the executive officer. The total annual pension amounts shown in the Pension Plan Table are not subject to any deduction for Social Security or other offset amounts. The named executive officers are parties to agreements under which in the event 1) of a change of control of the Company as defined in the agreements and 2) the covered party leaves the employment of the Company within one year after the change of control, he would be entitled to receive a payment equal to two years' salary based upon his average salary over the past three years. He would also be entitled to receive the Company's standard health, life insurance and disability benefits for a period of two years. The executive officers also participate in a long-term disability income plan which is also applicable to all employees. Under the plan, after 90 days of disability, employees are entitled to receive 66 2/3% of their basic monthly earnings up to a maximum monthly benefit of $5,000. Directors who are not employees of the Company are paid a fee of $500 per meeting for attendance at regular or special meetings of the Board, and $500 per meeting for attendance at committee meetings (unless the committee meeting is held the same day as another meeting for which a full meeting fee is paid, in which case the fee is $250). The directors are also paid an annual retainer of $6,000. Directors who are employees of the Company receive no fee for their services as directors. ITEM 12 SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT ------- -------------------------------------------------------------- (a) Security Ownership of Certain Beneficial Owners The following table sets forth as of December 31, 2000 information with respect to persons known to management to be the beneficial owners of more than 5% of any class of voting securities of the Company: Name and Address Title Percentage of Beneficial Owners of Class No. of Shares of Shares -------------------- -------- ------------- --------- GAMCO Investors, Inc., Common Stock 599,700 8.16%(1) Gabelli Funds, LLC and Related Entities One Corporate Center Rye, New York 10580 FMR Corp. Common Stock 505,200 6.86%(2) 82 Devonshire Street Boston, Massachusetts 02109 Dimensional Fund Advisors Inc. Common Stock 387,300 5.26%(3) 1299 Ocean Avenue, 11th Floor Santa Monica, California 90401 (1) Ten entities and two individuals were included in schedule 13D/A filed with the SEC on February 15, 2001. In addition to the two entities listed above, Gabelli Associates Limited, Gabelli Associates Fund, Gabelli Performance Partnership, L.P., Gabelli Fund, LDC, Gabelli Advisors, Inc., Gabelli Foundation, Inc., Gabelli Group Capital Partners, Inc., Gabelli Asset Management Inc., Marc J. Gabelli and Mario J. Gabelli were included. GAMCO Investors, Inc. is the beneficial owner of 440,100 of Bangor Hydro common stock, 5.98% of the class. (2) According to the 13G/A filed with the SEC on February 13, 2001. (3) According to the 13G filed with the SEC on February 2, 2001. (b) Security Ownership of Management The following table sets forth as of December 31, 2000 information with respect to the beneficial ownership of equity securities by directors, nominees for the office of director and named executive officers: Title of Class Name of Beneficial Owner Beneficially Owned* -------------------------------------------------------------------- Common Robert S. Briggs 6,644 Preferred Robert S. Briggs 28 Common William C. Bullock, Jr. 7,000 Common Jane J. Bush 303 Common David M. Carlisle 2,443 Common Joseph H. Cyr 1,747 Common Marion M. Kane 260 Common Paul A. LeBlanc 455 Common Norman A. Ledwin 180 Common Carroll R. Lee 1,965 Common James E. Rier, Jr. 300 Common Frederick S. Samp 816 Common Directors & Executive Officers as a group (11) 22,113 Preferred Directors & Executive Officers as a group (11) 28 * The directors and executive officers of the Company as a group own a beneficial interest in less than 1% of the Company's Common and Preferred Stock. (c) Changes in Control See Item 7, "Management's Discussion and Analysis of Results of Operations and Financial Condition - Recent Events Affecting The Electric Utility Industry And The Company - Proposed Merger Agreement with Emera" for a discussion of the Company's pending acquisition by Emera. The Company is unaware of any other arrangements regarding changes in control, including any pledge by any person of securities of the registrant or any of its parents, the operation of which may at a subsequent date result in a change in control of the Company. ITEM 13 CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS ------- ---------------------------------------------- COMPENSATION COMMITTEE INTERLOCKS - During 2000, Mr. Briggs, the Chairman of the Company's Board of Directors and its President and Chief Executive Officer, served as a Trustee of Eastern Maine Medical Center, a hospital facility located in Bangor, Maine. Mr. Ledwin, who serves on the Board's Compensation Committee, is President, Chief Executive Officer and a Director of Eastern Maine Healthcare, the organization that owns and operates Eastern Maine Medical Center. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS - During 2000, the Company made payments to Eastern Maine Healthcare, its subsidiaries and affiliates, of $655,124. Mr. Ledwin, who serves on the Board of Directors and the Board's Compensation Committee, is President, Chief Executive Officer and a Director of Eastern Maine Healthcare. Eastern Maine Healthcare owns and operates Eastern Maine Medical Center, the second largest hospital in the State of Maine and the largest in the region served by the Company, as well as several other health care organizations in the region. The Company provides health care benefits to its employees through a self insured managed care plan. An independent plan administrator negotiates on behalf of the Company the rates for health care services paid to individual providers under the plan, including Eastern Maine Healthcare and its affiliates. PART IV ------- ITEM 14 EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ------- ---------------------------------------------------- ON FORM 8-K ----------- (a) Consolidated Financial Statements of the Company covered by the Report of the of Independent Auditors (See Item 8): Consolidated Statements of Income for the Years Ended December 31, 2000, 1999 and 1998 Consolidated Balance Sheets - December 31, 2000 and 1999 Consolidated Statements of Common Stock Investment for the Years ended December 31, 2000, 1999 and 1998 Consolidated Statements of Capitalization - December 31, 2000 and 1999 Consolidated Statements of Cash Flows for the Years Ended December 31, 2000, 1999 and 1998 Notes to Consolidated Financial Statements Report of Independent Accountants (b) Schedules Schedule VIII - Reserve for Doubtful Accounts 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 The Company has no current reports on Form 8-K. 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 /s/ Marion M. Kane -------------------- ------------------ Robert S. Briggs Marion M. Kane President and Director Chairman of the Board /s/ Norman A. Ledwin --------------------------- -------------------- William C. Bullock, Jr. Norman A. Ledwin Director Director /s/ Jane J. Bush /s/ James E. Rier, Jr. ---------------- ---------------------- Jane J. Bush James E. Rier, Jr. Director Director /s/ Carroll R. Lee --------------------- ------------------ David M. Carlisle Carroll R. Lee Director Director, Senior Vice President and Chief Operating Officer /s/ Joseph H. Cyr /s/ Frederick S. Samp ----------------- --------------------- Joseph H. Cyr 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 21, 2001. SCHEDULE VIII RESERVE FOR DOUBTFUL ACCOUNTS ----------------------------- Additions ----------------------------- Balance at Charged to Charged to Balance at Beginning Costs and Other End Of Period Expenses Accounts Deductions of Period ------------- ------------- ------------- --------------- -------------
2000 Reserve for Doubtful Accounts $ 1,075,000 $ 1,275,016 $ - $ 1,589,016 (C) $ 761,000 ------------- ------------- ------------- ------------- ------------- 1999 Reserve for Doubtful Accounts $ 1,075,000 $ 1,475,395 $ - $ 1,475,395 (B) $ 1,075,000 ------------- ------------- ------------- ------------- ------------- 1998 Reserve for Doubtful Accounts $ 1,450,000 $ 1,345,536 $ - $ 1,720,536 (A) $ 1,075,000 ------------- ------------- ------------- ------------- ------------- NOTE: (A) Accounts written off, less recoveries. For 1998 includes reduction in reserve for doubtful accounts of $375,000. (B) Accounts written off, less recoveries. (C) Accounts written off, less recoveries. For 2000 includes reduction in reserve for doubtful accounts of $314,000.
EXHIBIT INDEX Exhibits Filed Herewith ------------------------ Exhibit No. Description of Exhibit NONE 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 Articles of Amendment Form 10-K, 1995, Exhibit 3(a) changing Corporate Clerk 3.4 By-Laws of the Company Form S-2, Reg. No. 33-63500, Exhibit 4.4 3.5 Articles of Amendment Form 10-K, 1998, Exhibit 3(a) Allowing Use of Similar Name 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 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 4.7 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 4.8 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 4.9 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 4.10 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 4.11 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 4.12 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 4.13 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 4.14 Loan Agreement by and Form 10-Q, 3rd Quarter 1995, Finance Authority of Exhibit 4.1 Maine and Bangor Hydro- Electric Company 4.15 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 4.16 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 4.17 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). 4.18 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). 4.19 Supplemental Indenture Form 10-K, 1995, Exhibit 4(a) Dated as of October 1, 1995 (Identified as Exhibit 10(a)) to General and Refunding Mortgage and Deed of Trust dated as of June 1, 1995 (Bangor Hydro-Electric Company to Chemical Bank). 4.20 TERM LOAN AGREEMENT Form 10-Q, First Quarter 1998, dated as of March 31, 1998 Exhibit 4(a) among BANGOR ENERGY RESALE, INC., BANKBOSTON, N.A. and the certain other lending institutions and BANKBOSTON, N.A., as Agent, including all Exhibits thereto 4.21 GUARANTY, dated as of March 31, Form 10-Q, First Quarter 1998, 1998, by BANGOR HYDRO Exhibit 4(b) -ELECTRIC COMPANY, in favor of (a) BANKBOSTON, N.A., as Agent, for itself and the other lending institutions which are or may become parties to a Term Loan Agreement, dated as of March 31, 1998 4.22 Warrant to Purchase Form 10-Q, Second Quarter 1998, Common Stock Granted to Exhibit 4(a) the Municipal Review Committee, Inc. on June 26, 1998 4.23 Warrant to Purchase Form 10-Q, Second Quarter 1998, Common Stock Dated Exhibit 4(b) Granted to PERC Management Company Limited Partnership on June 26, 1998 4.24 Warrant to Purchase Form 10-Q, Second Quarter 1998, Common Stock Granted to Exhibit 4(c) Energy National, Inc. on June 26, 1998 4.25 Supplemental Indenture Form 10-Q, Second Quarter 1998, Dated as of June 29, 1998 Exhibit 4(d) between the Company and Citibank, N.A. 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 Employee Stock Ownership Form S-7, Reg. No. 2-59747, Plan, including related Exhibit 5(a)(2) trust agreements, dated June 1, 1977 10.14 Sample of binder relating Form S-7, Reg. No. 2-59747, to contingent liability Exhibit 5(a)(4) for nuclear incidents 10.15 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 10.16 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 10.17 Third Amendment dated Form 10-K, 1983, Exhibit 10.2 as of November 1, 1982 to Preliminary Quebec Interconnection Support Agreement 10.18 Second Amendment dated Form 10-K, 1983, Exhibit 10.3 as of November 1, 1982 to Agreement With Respect to Use of Quebec Interconnection 10.19 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) 10.20 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) 10.21 Fourth Amendment Form 10-Q, 1st Quarter 1983, dated as of March 1, Exhibit 10.1 1983, to Preliminary Quebec Interconnection Support Agreement 10.22 Amendment dated as of Form 10-Q, 2nd Quarter 1983, September 1, 1981 Exhibit 10.3 to New England Power Pool Agreement 10.23 Amendment dated as of Form 10-Q, 2nd Quarter 1983, June 1, 1982 to New Exhibit 10.4 England Power Pool Agreement 10.24 Amendment dated as of Form 10-Q, 2nd Quarter 1983, June 15, 1983 to New Exhibit 10.5 England Power Pool Agreement 10.25 Amendment dated as of Form 10-Q, 3rd Quarter 1983, October 1, 1983 to Exhibit 10.1 New England Power Pool Agreement 10.26 Amendment No. 1 to the Form 10-K, 1983, Exhibit 10(b) Maine Yankee Power Contract 10.27 Amendment No. 2 to the Form 10-K, 1983, Exhibit 10(c) Maine Yankee Power Contract 10.28 Additional Power Con- Form 10-K, 1983, Exhibit 10(d) tract between Maine Yankee and its sponsors, including the Company 10.29 Preliminary Support Form 10-K, 1984, Exhibit 10(b) Agreement - Phase 2 of Hydro-Quebec Inter- connection 10.30 Amendment dated September 1, Form 10-K, 1985, Exhibit 10(b) 1985 to Agreement with respect to Use of Quebec Interconnection 10.31 Energy Contract dated Form 10-K, 1985, Exhibit 10(c) March 1983 between NEPOOL and Hydro-Quebec re: Hydro-Quebec Phase I interconnection project 10.32 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 10.33 Interconnection Agreement Form 10-K, 1985, Exhibit 10(e) dated March 1983 between NEPOOL and Hydro-Quebec re: Hydro-Quebec Phase I interconnection project 10.34 Amendment dated September 1 Form 10-K, 1985, Exhibit 10(f) 1985 to NEPOOL Agreement re: Hydro-Quebec Phase II interconnection project 10.35 Firm Energy Contract dated Form 10-K, 1985, Exhibit 10(g) October 14, 1985 between New England utilities and Hydro-Quebec re: Hydro- Quebec Phase II interconnection project 10.36 Boston Edison AC Facilities Form 10-K, 1985, Exhibit 10(h) Support Agreement dated June 1, 1985 re: Hydro-Quebec Phase II interconnection project 10.37 Phase II New England Form 10-K, 1985, Exhibit 10(i) Power AC Facilities Support Agreement dated June 1, 1985 re: Hydro- Quebec Phase II interconnection project 10.38 Phase II Massachusetts Form 10-K, 1985, Exhibit 10(j) Transmission Facilities Support Agreement dated June 1, 1985 re: Hydro- Quebec Phase II interconnection project 10.39 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 10.40 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 10.41 Amendment No. 3 dated Form 10-K, 1985, Exhibit 10(m) October 1, 1984 to Maine Yankee Power Contract 10.42 Amendment No. 1 dated Form 10-K, 1985, Exhibit 10(n) August 1, 1985 to Maine Yankee Capital Funds Agreement 10.43 Amendments dated August 1, Form 10-K, 1985, Exhibit 10(o) 1985, August 15, 1985, and January 1, 1986 to NEPOOL Agreement 10.44 Third Amendment to Vermont Form 10-Q, 1st Quarter 1986, Transmission Line Support Exhibit 10.2 Agreement 10.45 First Amendment to Hydro- Form 10-Q, 1st Quarter 1986, Quebec Phase I Intercon- Exhibit 10.3 nection Agreement 10.46 First Amendment to Hydro- Form 10-Q, 2nd Quarter 1986, Quebec Phase II Exhibit 10.1 Massachusetts Trans- mission Facilities Support Agreement 10.47 First Amendment to Hydro- Form 10-Q, 2nd Quarter 1986, Quebec Phase II New Exhibit 10.2 Hampshire Transmission Facilities Support Agreement 10.48 First Amendment to Hydro- Form 10-Q, 2nd Quarter 1986, Quebec Phase II New England Exhibit 10.3 Power AC Facilities Support Agreement 10.49 First Amendment to Form 10-Q, 2nd Quarter 1986, Hydro-Quebec Phase II Exhibit 10.4 Boston Edison Company AC Facilities Support Agreement 10.50 Amendment Number 3 to Form 10-Q, 3rd Quarter 1986, Hydro-Quebec Phase l Exhibit 10.1 Terminal Facility Support Agreement 10.51 Amendment Number 3 to Form 10-Q, 3rd Quarter 1986, Hydro-Quebec Phase I Exhibit 10.2 Vermont Transmission Line Support Agreement 10.52 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. 10.53 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 10.54 Power Purchase Agreement Form 10-K, 1986, Exhibit 10(i) dated June 9, 1986 and Amendment No. 1 thereto dated January 14, 1987, between the Company and Bangor-Pacific Hydro Associates (formerly West Enfield Associates) 10.55 Power Sale Agreement dated Form 10-K, 1986, Exhibit 10(l) August 1, 1986, and First Amendment thereto, between the Company and Unitil Power Corp. re Wyman No. 4 10.56 Third Amendment to Pre- Form 10-K, 1987, Exhibit 10(a) liminary Quebec Intercon- nection Support Agreement - Phase II 10.57 Fourth Amendment to Pre- Form 10-K, 1987, Exhibit 10(b) liminary Quebec Intercon- nection Support Agreement - Phase II 10.58 Fifth Amendment to Pre- Form 10-K, 1987, Exhibit 10(c) liminary Quebec Intercon- nection Support Agreement - Phase II 10.59 Sixth Amendment to Pre- Form 10-K, 1987, Exhibit 10(d) liminary Quebec Intercon- nection Support Agreement - Phase II 10.60 Seventh Amendment to Pre- Form 10-K, 1987, Exhibit 10(e) liminary Quebec Intercon- nection Support Agreement - Phase II 10.61 Amendment to New England Form 10-K, 1987, Exhibit 10(f) Power Pool Agreement dated March 1, 1988 10.62 Second Amendment to Credit Form 10-K, 1987, Exhibit 10(h) Agreement, dated as of July 22, 1987, among the Company and the Banks named therein 10.63 Dividend Reinvestment and Form 10-K, 1987, Exhibit 10(i) Common Stock Purchase Plan Effective as of December 1, 1987 10.64 Ninth Amendment to Form 10-K, 1988, Exhibit 10(b) Preliminary Quebec Interconnection Support Agreement - Phase II 10.65 Tenth Amendment to Form 10-K, 1988, Exhibit 10(c) Preliminary Quebec Interconnection Support Agreement - Phase II 10.66 Second Amendment to Form 10-K, 1988, Exhibit 10(d) Massachusetts Trans- mission Facilities Support Agreement 10.67 Third Amendment to Form 10-K, 1988, Exhibit 10(e) Massachusetts Trans- mission Facilities Support Agreement 10.68 Fourth Amendment to Form 10-K, 1988, Exhibit 10(f) Massachusetts Trans- mission Facilities Support Agreement 10.69 Fifth Amendment to Form 10-K, 1988, Exhibit 10(g) Massachusetts Trans- mission Facilities Support Agreement 10.70 Sixth Amendment to Form 10-K, 1988, Exhibit 10(h) Massachusetts Trans- mission Facilities Support Agreement 10.71 Second Amendment to Form 10-K, 1988, Exhibit 10(i) New Hampshire Trans- mission Facilities Support Agreement 10.72 Third Amendment to Form 10-K, 1988, Exhibit 10(j) New Hampshire Trans- mission Facilities Support Agreement 10.73 Fourth Amendment to Form 10-K, 1988, Exhibit 10(k) New Hampshire Trans- mission Facilities Support Agreement 10.74 Fifth Amendment to Form 10-K, 1988, Exhibit 10(l) New Hampshire Trans- mission Facilities Support Agreement 10.75 Sixth Amendment to Form 10-K, 1988, Exhibit 10(m) New Hampshire Trans- mission Facilities Support Agreement 10.76 Second Amendment to Form 10-K, 1988, Exhibit 10(n) Phase II AC New England Power Facilities Sup- port Agreement 10.77 Third Amendment to Form 10-K, 1988, Exhibit 10(o) Phase II AC New England Power Facilities Sup- port Agreement 10.78 Fourth Amendment to Form 10-K, 1988, Exhibit 10(p) Phase II AC New England Power Facilities Sup- port Agreement 10.79 Fifth Amendment to Form 10-K, 1988, Exhibit 10(q) Phase II AC New England Power Facilities Sup- port Agreement 10.80 Second Amendment to Form 10-K, 1988, Exhibit 10(r) Phase II Boston Edison AC Facilities Support Agreement 10.81 Third Amendment to Form 10-K, 1988, Exhibit 10(s) Phase II Boston Edison AC Facilities Support Agreement 10.82 Fourth Amendment to Form 10-K, 1988, Exhibit 10(t) Phase II Boston Edison AC Facilities Support Agreement 10.83 Fifth Amendment to Form 10-K, 1988, Exhibit 10(u) Phase II Boston Edison AC Facilities Support Agreement 10.84 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 10.85 401 (k) Plan for Non- Form 10-K, 1988, Exhibit 10(x) Union Employees 10.86 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 10.87 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 10.88 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. 10.89 Purchase Agreement between Form 10-Q, 3rd Quarter 1995, Babcock-Ultrapower Exhibit 10.1 Jonseboro and Bangor Hydro- Electric Company 10.90 Purchase Agreement between Form 10-Q, 3rd Quarter 1995, Babcock-Ultrapower West Exhibit 10.2 Enfield and Bangor Hydro- Electric Company 10.91 ASSIGNMENT OF CONTRACTS Form 10-Q, 1st Quarter 1998, AND ENTITLEMENTS, made March Exhibit 10(a) 31, 1998 by and between Bangor Hydro-Electric Company and Bangor Energy Resale, Inc. 10.92 Rate Agreement made October 30, Form 10-Q, 1st Quarter 1998, 1997, by and between Bangor Exhibit 10(b) Hydro-Electric Company and Bangor Energy Resale, Inc. 10.93 Management and Support Services Form 10-Q, 1st Quarter 1998, Agreement made March 31, 1998 Exhibit 10(c) by and between Bangor Hydro- Electric Company and Bangor Energy Resale, Inc. 10.94 Surplus Cash Agreement Form 10-Q, 2nd Quarter 1998, dated as of June 26, 1998 Exhibit 10(a) among the Company, Penobscot Energy Recovery Company Limited Partnership and the Municipal Review Committee, Inc. 10.95 Guaranty Agreement dated Form 10-Q, 2nd Quarter 1998, as of June 1, 1998 Exhibit 10(b) between the Company and The Chase Manhattan Bank 10.96 Amendment No. 2 to Form 10-Q, 2nd Quarter 1998, Purchase Power Agreement Exhibit 10(c) dated as of June 26, 1998 between the Company and Penobscot Energy Recovery Company Limited Partnership 10.97 Amended and Restated Form 10-Q, 2nd Quarter 1998, Revolving Credit And Exhibit 10(d) Term Loan Agreement dated as of June 19, 1998 between the Company and BankBoston, N.A. and Fleet National Bank 10.98 Asset Purchase Agreement Form 8-K, September 25, 1998 dated as of September 25, Exhibit 2 1998 between Bangor Hydro- Electric Company and PP&L Global, Inc. (schedules and exhibits omitted). 10.99 Asset Purchase Implementation Form 10-K, 2000, Exhibit 10(a) Agreement, dated as of May 27, 1999, by and among Bangor Hydro- Electric Company, Penobscot Hydro Co., Inc. and Penobscot Hydro, LLC 10.100 33rd Amendment to the NEPOOL Form 10-K, 2000, Exhibit 10(b) Agreement dated December 1, 1996 10.101 Form of Agreement with Form 10-K, 2000, Exhibit 10(c) certain Executive Officers providing benefits upon a change of control 10.102 Form of Agreement with Form 10-K, 2000, Exhibit 10(d) certain Executive Officers providing supplemental death and retirement benefits 10.103 Agreement and Plan of Merger by Form 8-K, June 29, 2000, and Among Bangor Hydro-Electric Exhibit 2.1 Company and NS Power Holdings Incorporated dated as of June 29, 2000