-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, JZYOc4BKv2f2s5MMa5ieckmDXZCWhnGbpdpjipX6rrgpw6p6OLwxszgutK1vJecR 9JRY5dm2GaOlTzDoK3lBSg== 0000009548-99-000002.txt : 19990331 0000009548-99-000002.hdr.sgml : 19990331 ACCESSION NUMBER: 0000009548-99-000002 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 2 CONFORMED PERIOD OF REPORT: 19981231 FILED AS OF DATE: 19990330 FILER: COMPANY DATA: COMPANY CONFORMED NAME: BANGOR HYDRO ELECTRIC CO CENTRAL INDEX KEY: 0000009548 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 010024370 STATE OF INCORPORATION: ME FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: SEC FILE NUMBER: 001-10922 FILM NUMBER: 99578306 BUSINESS ADDRESS: STREET 1: 33 STATE ST CITY: BANGOR STATE: ME ZIP: 04401 BUSINESS PHONE: 2079455621 MAIL ADDRESS: STREET 1: PO BOX 932 CITY: BANGOR STATE: ME ZIP: 04401 10-K 1 1998 FORM 10-K FOR BANGOR HYDRO-ELECTRIC COMPANY FORM 10-K SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the Fiscal year ended DECEMBER 31, 1998 Commission File No. 0-505 BANGOR HYDRO-ELECTRIC COMPANY - ---------------------------------------------------------------------------- (Exact Name of Registrant as specified in its charter) MAINE 01-0024370 -------------------------- ------------------------- (State of Incorporation) (I.R.S. Employer ID No.) 33 STATE STREET, BANGOR, MAINE 04401 ---------------------------------------- ---------- (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code 207-945-5621 ----------------- Securities registered pursuant to Section 12(b) of the Act: Title of each class Name of exchange on which registered COMMON STOCK, $5 PAR VALUE NEW YORK STOCK EXCHANGE - -------------------------- ----------------------- Securities registered pursuant to Section 12(g) of the Act: Common Stock, $5 Par value (7,363,424 shares outstanding at March 17, 1999) -------------------------------------------------- 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 17, 1999 of the voting stock held by non-affiliates of the registrant was $99.2 million. The information required by Part III Items 10, 11, 12 and 13 is incorporated by reference from the registrant's proxy statement which will be filed with the Securities and Exchange Commission within 120 days of the close of the registrant's fiscal year ended December 31, 1998. FORM 10-K FOR THE FISCAL YEAR ENDED DECEMBER 31, 1998 PAGE Cover Page 1 Index 2 PART I: Items 1 through 2 - Business; Properties 5 - General 5 - Certain Issues Facing the Company 7 - Construction Program 8 - Rates and Regulation 8 - Seabrook 10 - Joint Ventures 11 - Employees 13 - Power Supply Sources 14 - Company-owned Generation 14 - Power Purchase Contracts 15 - Maine Yankee 17 - Environmental Matters 20 - Executive Officers of the Company 21 Item 3: Legal Proceedings 22 Item 4: Submission of Matters to a Vote of Security Holders 22 PART II: Item 5: Market for Registrant's Common Equity and Related Stockholder Matters 23 Item 6: Selected Financial Data 25 Item 7: Management's Discussion and Analysis of Results of Operations and Financial Condition 27 Item 8: Financial Statements & Supplementary Data 37 - Consolidated Statements of Income 37 - Consolidated Balance Sheets 38 - Consolidated Statements of Capitalization 40 - Consolidated Statements of Cash Flows 41 - Consolidated Statements of Common Stock Investment 42 - Notes to Consolidated Financial Statements 43 1) Nature of Operations and Summary of Significant Accounting Policies 43 2) Income Taxes 45 3) Common and Preferred Stock and Earnings Per Share 47 4) Lending Agreements and Monetization of Power Sale Contract 48 5) Postretirement Benefits 50 6) Jointly Owned Facilities and Power Supply Commitments 53 7) Recovery of Seabrook Investment and Sale of Seabrook Interest 60 8) Unaudited Quarterly Financial Data 61 9) Fair Value of Financial Instruments 61 10) Industry Restructuring and Rate Regulation 61 11) Sale of Property at Graham Station 65 12) Storm Damage 65 13) Derivative Financial Instruments 65 14) Contingencies 67 15) New Accounting Pronouncements 67 Report of Independent Accountants 69 Item 9: Changes in and Disagreements with Audit Firms on Financial Disclosures 70 PART III: Item 10: Directors and Executive Officers of the Registrant 70 Item 11: Executive Compensation 70 Item 12: Security Ownership of Certain Beneficial Owners and Management 70 Item 13: Certain Relationships and Related Transactions 70 PART IV: Item 14: Exhibits, Financial Statement Schedules, and Reports on Form 8-K 71 Signatures 72 Report of Independent Accountants 73 Schedule VIII - Reserves for Doubtful Accounts and Insurance 74 EXHIBIT INDEX: Exhibits Filed Herewith 75 Exhibits Incorporated Herein by Reference 76 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, 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, the Year 2000 issue, and other circumstances that could affect revenues and costs. PART I - ------ ITEMS 1 THROUGH 2 BUSINESS; PROPERTIES - --------------------------------------- GENERAL ------- The Company is a public utility engaged in the generation, purchase, transmission, distribution and sale of electric energy, with a service area of approximately 5,275 square miles having a population of approximately 192,000 people. The Company serves approximately 106,000 customers in portions of the counties of Penobscot, Hancock, Washington, Waldo, Piscataquis and Aroostook. The Company also sells energy to other utilities for resale. The Company has four material wholly-owned subsidiaries, Penobscot Hydro Co., Inc. ("PHC"), Bangor Var Co., Inc. ("Bangor Var Co."), Penobscot Natural Gas Company, Inc. ("Penobscot Gas"), and Bangor Energy Resale, Inc. PHC was incorporated in 1986 to own the Company's 50% interest in a joint venture, Bangor-Pacific Hydro Associates ("Bangor-Pacific"), which redeveloped the West Enfield hydroelectric project (the "West Enfield Project"). Bangor Var Co. 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 Penobscot Hydro Co. and Bangor Var Co., see "Joint Ventures." Penobscot Gas is a corporation organized under Maine law in 1998. It was formed to be a general partner whose sole function is to own Bangor Hydro's interest in Bangor Gas Company, LLC ("Bangor Gas"). Bangor Gas is a limited liability company organized under Maine law in 1997. It was formed to be a local natural gas distribution company in the greater Bangor, Maine area. For a further discussion of Penobscot Gas and Bangor Gas, 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 - Bangor Gas Joint Venture". 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 Item 7, "Management's Discussion and Analysis of Results of Operations and Financial Condition - Recent Events Affecting The Electric Utility Industry And The Company - Monetization of Power Sale Contract". In 1998, 30.4% of the Company's kilowatt hour ("KWH") sales were to residential customers, 30.5% were to commercial customers, 38.5% were to industrial customers and 0.7% 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. The maximum peak electric demand that the Company's system experienced during the 1998-1999 winter, as of March 17, 1999, was approximately 278.97 megawatts ("MW") on December 14, 1998. At that time the Company had approximately 338.70 MW of generating capacity and firm purchased power, comprised of 101 MW from Company-owned generating units, 9.6 MW from Hydro- Quebec, 53.4 MW from non-utility power producers, and 175.0 MW from short term economy purchases. The Company owns 7% of the common stock of Maine Yankee Atomic Power Company, 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. NEPOOL provides for joint planning and operation of generating and transmission facilities in New England, and governs generating capacity reserve obligations and provisions regarding the use of major transmission lines. The Company, as a member of NEPOOL, has a capability responsibility which involves carrying an allocated share of a New England capacity requirement which is determined for each period based on certain regional reliability criteria. 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 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 the 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 rates, accounting, service standards, territory served, the issuance of securities and various other matters. The Company is also subject to the jurisdiction of the Federal Energy Regulatory Commission ("FERC") as to certain matters, including licensing of its hydroelectric stations and rates for wholesale purchases and sales of energy and capacity and transmission services. Maine Yankee is subject to extensive regulation by the Nuclear Regulatory Commission ("NRC"). See "Rates and Regulation." The principal executive offices of the Company are located at 33 State Street, Bangor, Maine 04401; telephone (207) 945-5621. CERTAIN ISSUES FACING THE COMPANY --------------------------------- CHANGES IN THE ELECTRIC UTILITY INDUSTRY AND IN REGULATION - Pursuant to "An Act to Restructure the State's Electric Industry", enacted in 1997 by the Maine Legislature, effective March 1, 2000, the Company will no longer be permitted to engage directly in the generation and sale of electric energy. The Company will remain regulated as a provider of electricity transmission and distribution services. As part of the restructuring process, the Company reached agreement on September 25, 1998 to sell substantially all Company- owned generation units to PP&L Global, Inc., a subsidiary of PP&L Resources, Inc. 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 - Agreement on Sale of Company's Generating Assets" and Note 10 to the Consolidated Financial Statements included in Item 8, below. 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. YEAR 2000 ISSUE - 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 the Year 2000 Issue on the Company. 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. RESUMPTION OF COMMON STOCK DIVIDENDS - In response to financial pressures experienced by the Company during the last several years, the Board of Directors reduced the level of common stock dividends in 1995 and then suspended the declaration of such dividends in 1997. Given the significant progress that has been made in resolving several of the uncertainties which have been facing the Company, as discussed herein, management expects that the Board of Directors could consider the resumption of common stock dividends sometime in 1999. The projected effects on the Company's financial condition of the pending generation asset sale and restructuring regulatory proceedings before the MPUC, as well as capital needs associated with investment opportunities the Company may elect to pursue, are all factors that the Board of Directors will consider in determining whether, and when, to reinstate common stock dividends. The Board will also take into account provisions in the Company's debt instruments restricting dividends and repurchases of equity securities, as well as the levels of the Company's indebtedness from time to time. Additionally, any future dividend policy will necessarily reflect the fundamental changes taking place in the electric utility industry, and the Company's need to retain financial flexibility to take advantage of opportunities as they occur and to respond to unanticipated developments. 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 $45-65 million in the period 1999 through 2001. RATES AND REGULATION -------------------- RATE MATTERS - On February 9, 1998, the MPUC issued a final order on the Company s request to increase its rates originally filed in March, 1997. Of the approximately $22 million increase in annual revenue ultimately requested by the Company, the MPUC authorized an increase of approximately $13.2 million annually. While there are many factors that explain the difference between the MPUC allowance and the Company's requested increase, much of that difference is attributable to the proposed accounting treatment of various costs and the deferral of other costs for future consideration, including the deferral of certain costs associated with Maine Yankee. While those accounting recommendations will affect the timing of receipt of revenues by the Company and will require the Company to finance the payment of the associated costs, they should not significantly affect the Company s earnings during the period that the new rates are effective. The MPUC order is based upon a determination that the Company should be allowed to earn an annual return of 12.75% on common equity. It also includes an "Alternative Rate Plan" under which the Company's rates will be subject to certain reconciliations based upon actual expenditures by the Company and an annual adjustment beginning on May 1, 1999 to account for inflation with an offset for assumed increase in productivity. Other than those adjustments, the Company will not change its rates unless its return on equity exceeds or falls short of the allowed return by more than 350 basis points. If the Company's return on equity falls outside of that bandwidth, 50% of the excess or shortfall will be adjusted for in the Company's rates. On February 16, 1999, the Company submitted its 1999 filing to the MPUC under the Alternative Rate Plan. If approved, the Company will implement a rate increase of approximately 2% effective May 1, 1999. The Company is not seeking an increase due to inflation. Rather, the entire amount of the increase is due to adjustments for specific cost items. The largest of these is for deferred costs relating to a severe ice storm in January, 1998 at a rate of $1.46 million annually over a four year period. The remainder of the request consists of adjustments contemplated in the MPUC's decision in the Company's last rate case, discussed above, but for which amounts were not known at the time. On July 24, 1998, the Company filed with the MPUC proposed rates to be effective March 1, 2000 for retail transmission and distribution service, including the recovery of the Company's stranded costs. This filing was made pursuant to the 1997 Maine restructuring legislation. The 1997 Maine restructuring legislation requires the MPUC to provide transmission and distribution utilities, including the Company, a "reasonable opportunity" to recover its stranded costs that is comparable to the opportunity that it had prior to the implementation of industry restructuring. The Company cannot predict the outcome of the MPUC decision, which is expected in the third quarter of 1999, subject to later updating prior to March 1, 2000. The Company is also engaged in numerous other MPUC proceedings relating to various aspects of industry restructuring. OTHER REGULATION - The MPUC regulates numerous other matters affecting the Company, including financing, construction of generation and transmission facilities, credit, collection, conservation and demand side management programs, low income rate subsidies and purchases from non-utility power producers. Maine Yankee is subject to extensive regulation by the NRC. Under its continuing jurisdiction, the NRC may, after appropriate proceedings, require modification of nuclear power generating units for which operating or nonoperating licenses have already been issued, or impose new conditions on such permits or licenses. The FERC regulates rates for sales of electricity to other utilities. In addition, all the Company's hydroelectric projects are licensed by the FERC. Under the Federal Power Act, upon not less than two years' notice the United States is empowered to take over and thereafter to maintain and operate a licensed hydroelectric project at or following the time a license expires. If the United States elects this option, it must pay the licensee its net investment in the project, not to exceed fair market value. If the United States does not elect this option, the FERC may issue a new license to the existing licensee upon such terms and conditions as are authorized or required under the then-existing laws and regulations. It may also, alternatively, issue a new license to a new licensee that has filed a competing license application. In choosing between competing license applications, the FERC must issue a license to the applicant whose proposal is best adapted to serve the public interest. As part of the restructuring process, the Company reached agreement on September 25, 1998 to sell substantially all Company-owned generation units, including such FERC- regulated hydroelectric units, to PP&L Global, Inc., a subsidiary of PP&L Resources, Inc. 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 - Agreement on Sale of Company's Generating Assets" and Note 10 to the Consolidated Financial Statements included in Item 8, below. The following table sets forth certain information with regard to such licenses. Licensed Issue Date of Current Expiration Project Capacity Original License Date ------- -------- ---------------- ------------------ Ellsworth 8,900 KW April 12, 1977 December 31, 2018 Howland 1,875 KW September 12, 1980 September 30, 2000 Medway 3,400 KW March 29, 1979 March 31, 1999* Milford 6,400 KW December 31, 1969 March 31, 2038 Orono 2,332 KW November 10, 1977 Original license expired September 25, 1985 currently operating on year-to-year license. Stillwater 1,950 KW August 10, 1978 March 31, 2038 Veazie 8,400 KW February 18, 1965 March 31, 2038 West Enfield** 13,000 KW February 3, 1970 June 26, 2024 - ------------------ * An "annual license" will be automatically issued at the expiration of the current license, pending the processing of the application for a permanent license. ** Through PHC, the Company has a 50% ownership interest in Bangor-Pacific, which owns and operates the West Enfield Project. SEABROOK -------- GENERAL - The Company was a participant in Seabrook from 1978 to 1986, with an ownership interest of 2.17%, or 25 MW, in each of the two 1150 MW units. Unit 2 was effectively canceled in 1984. In late 1984, following a lengthy MPUC investigation, the conclusion of which cast doubt on the wisdom of the Maine utilities' continued participation in Seabrook, the Company began efforts to sell its interest in the project. An agreement for the sale of Seabrook to EUA Power Corp. was reached in mid-1985 and was consummated in November 1986. In 1985, the MPUC approved an agreement among the Company, the MPUC Staff and the Public Advocate addressing the recovery through rates of the Company's investment in Seabrook ("Seabrook Stipulation"). Although implementation of the Seabrook Stipulation significantly improved the Company's financial condition, substantial write-offs were required. In August 1989, a comprehensive settlement agreement entered into by current and former joint owners of Seabrook became effective. Under the agreement, the signatories, representing virtually all of the ownership interests in Seabrook, relinquished claims against the lead owner, Public Service Company of New Hampshire, arising out of Seabrook. As a part of the settlement, former joint owners, including the Company, were relieved of certain contingent liabilities. JOINT VENTURES -------------- WEST ENFIELD - In 1986, the Company formed PHC, a wholly-owned subsidiary, which owns the Company's 50% ownership interest in Bangor-Pacific, a joint venture with a development subsidiary of Pacific Lighting Corporation. Bangor-Pacific undertook the redevelopment of an old 3.8 MW hydroelectric plant which the Company owned on the Penobscot River in Enfield and Howland, Maine, into a 13 MW facility, the West Enfield Project, and now operates the facility. Construction costs were shared equally by the Company and the other joint venturer until Bangor-Pacific completed its financing and took over ownership of the project, which occurred in January 1987. Commercial operation of the redeveloped West Enfield Project began in April 1988. Bangor-Pacific financed the cost of the redevelopment through the private placement of $40 million of 9.45% and 10.26% fixed rate amortizing term notes due 1996 and 2008, respectively, and $5 million of floating rate amortizing term notes due 1996 (collectively, the "Notes"). The Notes are secured by a mortgage on the West Enfield Project and a security interest in a 50-year power contract between the Company and Bangor-Pacific. The holders of the Notes are without recourse to the joint venture partners or their parent companies except that each partner has agreed to make payments in an amount equal to 50% of any amounts due and unpaid on the Notes but not exceeding distributions received from Bangor-Pacific in the preceding twelve-month period. Under the power contract between the Company and Bangor-Pacific, if the West Enfield Project operates as anticipated, payments by the Company to Bangor-Pacific are estimated at $7.5 million annually (without consideration of any distributions by the joint venture to the partners). In 1998, the Company paid approximately $7.3 million to Bangor-Pacific under this power contract. The Company would be required to make payments under the contract, regardless of whether any power were delivered, of approximately $4 million per year. However, the Company has the right to terminate the contract upon thirty-days' written notice if the failure to deliver power continues for a period of 12 consecutive months. PHC accounts for its investment in Bangor-Pacific under the equity method. PHC's financial results are included in the Company's consolidated financial statements. BANGOR GAS - In 1998, the Company formed Penobscot Natural Gas Company ("Penobscot Gas") to be a 50% general partner in Bangor Gas Company, LLC, (Bangor Gas), which is constructing a natural gas distribution system in the Bangor, Maine area. Sempra Energy Utility Ventures, a subsidiary of Sempra Energy, owns the other 50% interest in Bangor Gas. In the second quarter of 1998, Bangor Gas received unconditional authority from the MPUC to provide natural gas service to the greater Bangor area. In October, 1998 the Company received authorization from the MPUC to invest approximately $1.2 million in Bangor Gas. Los Angeles based Sempra Energy is a joint-venture of Pacific Enterprises and Enova Corporation. Pacific Enterprises is the parent company of Southern California Gas Company, the nation's largest natural gas distribution company. Enova is the parent of San Diego Gas and Electric Company. Together, the two companies provide natural gas to approximately six million customers in California. Pacific Enterprises and the Company worked together in a partnership to develop the West Enfield Hydro Project in 1986. Gas service to Maine will be made economically feasible for the first time by the Maritimes and Northeast Pipeline Project, slated for completion in late 1999. The new pipeline will extend from the Sable Offshore Energy Project near Sable Island, Nova Scotia, through the state of Maine and interconnect with the Tennessee Gas Pipeline in Dracut, Massachusetts. The route, as proposed, comes near the Bangor area, providing an opportunity for retail gas distribution in the greater Bangor marketplace. Company officials estimate the cost to build and implement the new Bangor Gas system to be approximately $40 million. The Company is not obligated but has the opportunity to make material capital contributions to the joint-venture in the near term. Penobscot Gas accounts for its investment in Bangor Gas under the equity method. Penobscot Gas's financial results are included in the Company's consolidated financial statements. NEPOOL/HYDRO-QUEBEC - The NEPOOL member utilities and Hydro-Quebec, a utility operating within the province of Quebec, Canada ("Hydro-Quebec"), have constructed facilities required to interconnect the electric systems in New England with the electric system of Hydro-Quebec. The initial stage of the interconnection consists of a completed and operational 450 kilovolt ("KV") transmission line from the Hydro-Quebec system to a terminal having an approximate rating of 690 MW at the Comerford Generating Station ("Comerford") on the Connecticut River in New Hampshire. The subsequent stage, HQ-II, completed in 1990, increased the interconnection transfer capability to approximately 2000 MW by means of a transmission line from Comerford to a terminal facility at the Sandy Pond Substation in Massachusetts. In 1990, the Company formed Bangor Var Co., a wholly owned corporate subsidiary, the sole function of which is to own a 50% interest in Chester SVC Partnership ("Chester"), a general partnership which owns the static var compensator ("SVC"), electrical equipment which supports the HQ-II transmission line. A wholly-owned subsidiary of Central Maine Power Company ("CMP") owns the other 50% interest in Chester. Chester has financed the acquisition and construction of the SVC through the issuance of $33 million in principal amount of 10.48% senior notes due 2020, and up to $3.2 million principal amount of additional notes due 2020 (collectively, the "SVC Notes"). The holders of the SVC Notes are without recourse to the partners or their parent companies and may only look to Chester and to the collateral for payment. Bangor Var Co. accounts for its investment in Chester under the equity method. Bangor Var Co.'s financial results are included in the Company's consolidated financial statements. The New England utilities which participate in HQ-II have agreed under a FERC-approved contract to bear the cost of Chester, on a cost-of-service basis, which includes a return on and of all capital costs. As part of the electric industry restructuring process in the State of Maine, the Company reached agreement on September 25, 1998 to sell substantially all Company-owned generation units to PP&L Global, Inc. As part of this transaction, the Company will be assigning substantially all of its rights under the NEPOOL/Hydro-Quebec agreements to PP&L Global and PP&L Global will assume a substantial portion of the Company's related liabilities. 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 - Agreement on Sale of Company's Generating Assets". EMPLOYEES --------- At December 31, 1998, the Company had 434 full time employees approximately 50% of whom were represented by a local union affiliated with the International Brotherhood of Electrical Workers (AFL-CIO). Union membership is divided into two bargaining units, 179 employees engaged in electrical, line and meter related functions and 40 employees engaged in customer service and credit related functions. The present contract with electrical, line and meter related workers expires December 31, 1999. The present contract with customer service and credit related workers also expires December 31, 1999. The Company believes that its relations with its employees are satisfactory. POWER SUPPLY SOURCES -------------------- GENERAL - In order to meet its load growth and reserve obligations under NEPOOL, the Company, in addition to utilizing its own generating capacity, acquires capacity and energy through contracts with other utilities and independent generation facilities and through joint ownership of generating facilities. The Company estimates that it has, or can acquire, sufficient generating capacity, through a combination of wholly-owned and jointly-owned generating facilities and purchased power contracts, to meet its anticipated load growth through the date of implementation of retail access in Maine, scheduled to occur on March 1, 2000. The Company's sources of generation for electric sales to its customers (net of off-system sales to other utilities) for 1998, 1997 and 1996 by type of fuel is shown below. Source 1998 1997 1996 ------ ---- ---- ---- Hydroelectric (Company*)....... 15% 13% 17% Nuclear Generation (Maine Yankee) 0% 0% 19% Oil (Company)................... 5% 4% 2% Biomass/Refuse (purchased)...... 6% 6% 6% NEPOOL/other purchases.......... 74% 77% 56% ---- ---- ---- Total....................... 100% 100% 100% ==== ==== ==== - ------------------ * Includes purchases from the West Enfield Project, in which the Company has a 50% ownership interest. COMPANY-OWNED GENERATION ------------------------ The Company, as a tenant in common with other utilities, owns 8.33%, or approximately 50 MW, of William F. Wyman Unit No. 4 ("Wyman 4"), a 600 MW oil-fired generating unit in Yarmouth, Maine, constructed and operated by CMP as the lead owner. The Company is entitled to 8.33% of the energy produced by Wyman 4 and pays the same percentage of the unit's operating expenses. The Company owns two oil-fired generating units located at its Graham Station in Veazie, Maine ("Graham"), currently in deactivated reserve status, having a total capacity of 47 MW, as well as eleven internal combustion generation units located at three stations having a total capacity of 21 MW. The Company also owns seven hydroelectric stations having a total capacity of about 30 MW (excluding PHC's ownership interest in the West Enfield Project). All of the Company's hydroelectric stations are licensed under the Federal Power Act. See "Rates and Regulation." As part of the electric industry restructuring process in the State of Maine, the Company reached agreement on September 25, 1998 to sell substantially all Company-owned generation units, including all of its hydroelectric projects and Wyman 4, to PP&L Global, Inc. On February 3, 1999, the MPUC issued an order approving the Company's sale of substantially all of its generation assets to PP&L Global, Inc. and in a vote taken March 10, 1999, the FERC approved the transaction. 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 - Agreement on Sale of Company's Generating Assets". In addition, the Company owns approximately 600 miles of transmission lines and approximately 3,600 miles of distribution lines to serve its customers. Other properties consist of office, garage and warehouse facilities at various locations in its service area. POWER PURCHASE CONTRACTS ------------------------ The following chart sets forth information concerning the Company's major power purchase contracts exclusive of Maine Yankee. Contracted Quantity of Seller Term of Contract Capacity or Energy - ---------- -------------------- -------------------------- Bangor-Pacific* August 21, 1986 through Total output of energy (Hydroelectric) May 31, 2024, at which from facility with name time Company can either plate rating of not more purchase the facility than 16 MW at its fair market value or extend the contract for an additional 15 years (if the West Enfield Project's FERC license is also extended) Penobscot Energy January 21, 1984 through Total output of firm Recovery Company February 28, 2018 energy; minimum annual ("PERC")(Refuse) delivery of 105,000,000 KWH up to a maximum of 166,440,000 KWH per calendar year Great Northern No Fixed Term Approximately 20 MW Paper Co. (Cogeneration) New England November 1, 1994 through 30 MW and associated energy Power Company October 31, 1999 from two designated nuclear units New Brunswick June 8, 1997 through 60 MW system purchase of Power December 31, 1999 capacity and energy Great Bay Power November 1, 1998 through 10 MW and associated energy Corporation February 29, 2000 from a designated nuclear unit United May 1, 1998 through 35 MW and associated energy Illuminating February 29, 2000 from a designated oil-fired unit - --------------------- * Through PHC, the Company has a 50% ownership interest in Bangor-Pacific, which owns and operates the West Enfield Project. For further details with respect to certain of these contracts, see Note 6 of the Notes to Consolidated Financial Statements. The Company purchases energy from, and sells energy to, New Brunswick Electric Power Commission utilizing the transmission facilities of Maine Electric Power Company, Inc. ("MEPCO"), in which the Company owns a 14.2% equity interest. MEPCO owns and operates a 345 KV transmission line running from Wiscasset, Maine to the Maine/New Brunswick border. The Company interconnects with this line in Orrington, Maine. The Company also purchases energy on a short-term basis from time to time when it is economical to do so to displace higher cost energy from other sources. MAINE YANKEE ------------ GENERAL - The Company 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 its nuclear generating plant at Wiscasset, Maine (the "Plant") and to begin decommissioning the Plant. As reported in detail in the Company's Annual Reports on Form 10-K for the years ended December 31, 1996 and December 31, 1997, its Quarterly Reports on Form 10-Q for the quarters ended March 31, 1997, June 30, 1997 and September 30, 1997 and its Reports on Form 8-K dated May 27, 1997 and February 19, 1997, the Plant experienced a number of operational and regulatory problems and has been shut down since December 6, 1996. The decision to close the Plant permanently was based on an economic analysis of the costs, risks and uncertainties associated with operating the Plant compared to those associated with closing and decommissioning it. The Plant's operating license from the NRC was scheduled to expire on October 21, 2008. The plant is currently in the process of being decommissioned, and the Company is obligated to pay its pro rata share of Maine Yankee's plant closure and decommissioning costs. MAINE YANKEE RATE CASE SETTLEMENT - On January 19, 1999, various parties submitted an offer of settlement with the FERC that, if accepted by FERC, will finally settle a number of outstanding rate recovery issues with respect to the Company's ownership of Maine Yankee. On March 10, 1999, the presiding Administrative Law Judge certified the uncontested settlement and recommended that the FERC accept it. For a more complete discussion of the recent events associated with Maine Yankee, see Note 6 to the Consolidated Financial Statements included in Item 8, below. LOW-LEVEL WASTE DISPOSAL. The federal Low-Level Radioactive Waste Policy Amendments Act (the "Waste 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. Subsequently, the states of Maine, Texas and Vermont entered into a compact for the disposal of low-level waste at a site in Texas. The compact provides for Texas to take Maine=s low-level waste over a 30-year period for disposal 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; or, 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 before several sessions of the Congress before finally being approved on September 2, 1998, and signed by the President on September 21, 1998. However, on October 22, 1998, the Texas Natural Resources Conservation Commission voted to deny a permit for the proposed west Texas site for the facility. Since the Maine Yankee Plant has permanently stopped operating, the compact is less beneficial to Maine Yankee than it would have been if the Plant had remained in operation, due to the new schedule for Maine Yankee's shipments and the uncertainty associated with the schedule for opening a Texas facility. Although other potential sites in Texas have been proposed by various parties, the Company cannot predict whether or when a facility in Texas will be licensed and built. Maine Yankee intends to utilize its on-site storage facility as well as dispose of low-level waste at an active South Carolina site or other available sites in the interim and continue to cooperate with the State of Maine in pursuing all appropriate options. The Company is unable to predict whether or when the state of Maine may 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. Like other nuclear plant operators, Maine Yankee entered into a contract with the United States Department of Energy ("DOE") for disposal of its spent nuclear fuel, as required by the Nuclear Waste Policy Act of 1982, pursuant to which a fee of one dollar per megawatt-hour was assessed against net generation of electricity and paid to the DOE quarterly. Under this Act, the DOE was given the responsibility for disposal of spent nuclear fuel produced in private nuclear reactors. In addition, Maine Yankee is obligated to make a payment with respect to generation prior to April 7, 1983 (the date current DOE assessments began). Maine Yankee elected under terms of its DOE contract to make a single payment of this obligation prior to the first delivery of spent fuel to DOE, which was scheduled to begin by January 31, 1998. The payment would consist of $50.4 million (all of which Maine Yankee previously collected from its customers, but for which a reserve was not funded), which is the approximate one-time fee charge, plus interest accrued at the 13- week treasury-bill rate compounded on a quarterly basis from April 7, 1983, through the date of the actual payment. Current costs incurred by Maine Yankee under this contract are recoverable under the terms of its Power Contracts with its sponsoring utilities, including the Company. Maine Yankee has accrued and billed $82.8 million of interest cost for the period April 7, 1983, through December 31, 1998. Maine Yankee has formed a trust to provide for payment of its long-term spent fuel obligation, and is funding the trust with deposits at least semiannually which began in 1985, with currently projected annual deposits of approximately $1.3 million through December 2003. Deposits are expected to total approximately $78.2 million, with the total liability, including interest due at the time of disposal, estimated to be approximately $168.7 million at December 31, 2003. Maine Yankee estimates that trust fund deposits plus estimated earnings will meet this total liability if funding continues without material changes. Maine Yankee's spent fuel is currently stored in the spent fuel pool at the Plant site. Federal legislation enacted in December 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 1997, the two branches of the United States Congress approved separate bills to comprehensively reform the federal spent nuclear fuel program. In the spring of 1998, House and Senate members resolved differences between the bills, which would have required the DOE to establish an interim storage facility and begin accepting spent fuel from nuclear power plants by 2003. On June 2, 1998, the Senate fell short of the 60 votes needed to end debate on the bill and the bill was not brought to a vote in the House. In 1994, several nuclear utilities other than Maine Yankee filed suit against the DOE. The utilities sought a declaration from the United States Court of Appeals for the District of Columbia Circuit that the Nuclear Waste Policy Act of 1982 required the DOE to take responsibility for spent nuclear fuel in 1998. In July 1996, the court held that the DOE was obligated Ato start disposing of [spent nuclear fuel] no later than January 31, 1998". The DOE did not appeal the decision, but announced in December 1996 that it anticipated it would be unable to start accepting spent nuclear fuel for disposal by January 31, 1998. A large number of nuclear utilities and state regulators filed a new lawsuit against the DOE in January 1997 seeking to force the DOE to honor its obligation to store spent nuclear fuel and seeking other appropriate relief. In November 1997, the U.S. Court of Appeals for the District of Columbia Circuit confirmed the DOE's obligation. On February 19, 1998, Maine Yankee filed a petition in the same court seeking to compel the DOE to take Maine Yankee's spent fuel from the Plant site "as soon as physically possible," alleging that removing the spent fuel on the DOE's indicated schedule would delay the decommissioning of the Maine Yankee Plant indefinitely. On May 5, 1998, the Court dismissed Maine Yankee' lawsuit, as well as that of the other nuclear utilities and state regulators, saying that petitioners' failure to pursue remedies under the standard contract rendered their appeal not appropriate at that time for review. On June 2, 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. On November 3, 1998, the Court granted summary judgment in favor of Maine Yankee, ruling that the DOE had violated its contractual obligations and leaving the amount of damages incurred by Maine Yankee for later determination by the Court. Maine Yankee expects the hearing on its claim to take place in late 1999. Maine Yankee intends to pursue its claim for damages vigorously, but as an alternative to DOE disposal is considering construction of an independent spent-fuel storage installation ("ISFSI") 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 is 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 --------------------- 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 ("MDEP") under various Maine environmental statutes. Although the Company is actively engaged in complying with these federal and state acts and statutes, the costs of which are significant, it has not, to date, encountered material difficulties in connection with such compliance. 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. As to the only other site which has been listed by the Department of Environmental Protection as an Uncontrolled Hazardous Substance Site, the Company was informed that it is considered a de minimis generator. 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 these waste disposal sites. 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, 1998, the liability recorded by the Company for its estimated environmental remediation costs amounted to $331,000. The Company s actual future remediation costs may be higher as additional factors become known. The Company estimates that during 1999 it will spend approximately $352,000 in operations expenses and $143,000 in capital expenditures to comply with environmental standards for air, water and hazardous materials. EXECUTIVE OFFICERS OF THE COMPANY --------------------------------- The following are the present executive officers of the Company with all positions and offices held. There are no family relationships between any of them nor are there any arrangements pursuant to which any were selected as officers. Name Age Office and Year First Elected - ---- --- ----------------------------- Robert S. Briggs 55 President & Chief Executive Officer since January 1991 Carroll R. Lee 49 Senior Vice President and Chief Operating Officer since December, 1996 Frederick S. Samp 48 Vice President - Finance & Law since 1995; Treasurer since 1995; Chief Financial Officer since 1995 Paul A. LeBlanc 51 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 and General Counsel, Corporate Secretary and Clerk from 1988 until 1995. 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 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, 1998, there were 6,328 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 - ------------- ---- --- --------- 1997 - ---- First Quarter................ $9 1/2 $6 $.00 Second Quarter............... 6 1/4 4 7/8 .00 Third Quarter................ 6 3/8 5 1/4 .00 Fourth Quarter............... 6 11/16 5 1/16 .00 1998 - ---- First Quarter................ $8 5/8 $6 1/8 $.00 Second Quarter............... 9 1/8 7 11/16 .00 Third Quarter................ 10 15/16 7 15/16 .00 Fourth Quarter............... 12 13/16 9 .00 1999 - ---- First Quarter (through March 17, 1998).. $14 5/16 $12 11/16 $.00 The cash dividend on common stock was suspended prior to April 20, 1997. Approximately 70% 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. See Item 1, above, for a discussion of Certain Items Facing the Company, including their potential impact on the Company's dividend policy. Item 6 Selected Financial Data SIX YEAR STATISTICAL SUMMARY Bangor Hydro-Electric Company
1998 1997 1996 1995 1994 1993 - --------------------------------------------------------------------------------------------------------------------------------- MEGAWATT HOURS (MWH) GENERATED AND PURCHASED Hydro Generation (Company) 275,379 262,377 321,532 275,810 271,616 275,694 Nuclear Generation (Maine Yankee) - - 348,719 13,606 456,871 395,665 Oil (Company) 96,476 69,580 26,912 50,706 35,759 47,115 Biomass/Refuse 156,051 159,990 163,279 177,558 190,218 281,260 NEPOOL/Other Purchases 1,522,125 1,583,093 1,359,116 1,540,530 958,363 937,431 - --------------------------------------------------------------------------------------------------------------------------------- Total Generated & Purchased 2,050,031 2,075,040 2,219,558 2,058,210 1,912,827 1,937,165 Less Line Losses and Company Use 139,028 147,298 141,426 140,128 136,908 135,561 - --------------------------------------------------------------------------------------------------------------------------------- Remainder - MWH sold 1,911,003 1,927,742 2,078,132 1,918,082 1,775,919 1,801,604 ================================================================================================================================= CLASSIFICATION OF SALES - MWH Residential 522,836 533,161 536,490 513,076 516,470 515,242 Commercial 532,344 523,043 512,433 511,720 507,285 500,488 Industrial 654,330 680,226 647,985 686,386 611,876 615,314 Lighting 8,901 8,780 8,945 9,547 9,416 9,590 Wholesale 2,704 3,841 4,486 10,961 11,705 10,311 - --------------------------------------------------------------------------------------------------------------------------------- Total MWH Billed to Customers 1,721,115 1,749,051 1,710,339 1,731,690 1,656,752 1,650,945 Unbilled Sales - Net Increase (Decrease) 1,040 33,011 2,998 4,658 6,366 2,001 - --------------------------------------------------------------------------------------------------------------------------------- Total Delivered Sales (MWH) 1,722,155 1,782,062 1,713,337 1,736,348 1,663,118 1,652,946 (Less) Interruptible Sales 248,091 265,438 237,553 295,818 231,128 254,359 - --------------------------------------------------------------------------------------------------------------------------------- Total Firm Delivered Sales (MWH) 1,474,064 1,516,624 1,475,784 1,440,530 1,431,990 1,398,587 Off-System Sales 188,848 145,680 364,795 181,734 112,801 148,658 - --------------------------------------------------------------------------------------------------------------------------------- Total Energy Sales (MWH) 1,911,003 1,927,742 2,078,132 1,918,082 1,775,919 1,801,604 ================================================================================================================================= ELECTRIC OPERATING REVENUES AND EXPENSES (000'S) OPERATING REVENUES Residential $ 71,396 $ 67,532 $ 66,805 $ 66,061 $ 64,008 $ 64,244 Commercial 60,802 55,965 54,168 55,030 53,410 53,599 Industrial 42,034 41,356 38,947 39,929 37,040 39,508 Lighting 2,207 2,065 2,032 2,051 2,010 1,915 Wholesale 235 310 314 859 937 903 - --------------------------------------------------------------------------------------------------------------------------------- Total Revenue From Customers $ 176,674 $ 167,228 $ 162,266 $ 163,930 $ 157,405 $ 160,169 Unbilled Sales-Net Increase (Decrease) 481 2,375 408 210 1,450 (237) - --------------------------------------------------------------------------------------------------------------------------------- Total Revenue $ 177,155 $ 169,603 $ 162,674 $ 164,140 $ 158,855 $ 159,932 (Less) Interruptible Revenue 11,064 11,215 9,537 11,149 8,450 8,876 - --------------------------------------------------------------------------------------------------------------------------------- Total Firm Revenue $ 166,091 $ 158,388 $ 153,137 $ 152,991 $ 150,405 $ 151,056 Off-System Revenue 14,630 13,615 18,384 14,098 12,750 15,326 - --------------------------------------------------------------------------------------------------------------------------------- Total Operating Revenues $ 191,785 $ 183,218 $ 181,058 $ 178,238 $ 171,605 $ 175,258 ================================================================================================================================= OPERATING EXPENSES Fuel for Generation and Purchased Power $ 82,027 $ 92,792 $ 78,477 $ 98,684 $ 104,132 $ 116,386 Operating and Maintenance Expense 34,448 32,471 32,441 35,711 33,498 29,474 Depreciation and Amortization 31,891 35,104 29,965 20,544 10,333 6,447 Taxes 11,642 3,168 10,249 6,306 8,803 8,866 - --------------------------------------------------------------------------------------------------------------------------------- Total Operating Expenses $ 160,008 $ 163,535 $ 151,132 $ 161,245 $ 156,766 $ 161,173 ================================================================================================================================= SUMMARY OF OPERATIONS (000'S) Operating Revenue $ 195,144 $ 187,324 $ 187,374 $ 184,914 $ 174,098 $ 177,972 Operating Expenses 160,008 163,535 151,132 161,245 156,766 161,173 Other Income (including equity AFDC) 1,292 1,292 1,466 760 1,308 (2,657)* Interest Expense (net of borrowed AFDC) 24,963 25,467 26,425 20,092 11,183 8,805 - --------------------------------------------------------------------------------------------------------------------------------- Net Income (Loss) $ 11,465 $ (386) $ 11,283 $ 4,337 $ 7,457 $ 5,337 * Less Preferred Dividends 1,244 1,376 1,537 1,702 1,652 1,646 - --------------------------------------------------------------------------------------------------------------------------------- Earnings (Loss) on Common Stock $ 10,221 $ (1,762) $ 9,746 $ 2,635 $ 5,805 $ 3,691 * ================================================================================================================================= SELECTED FINANCIAL DATA Total Assets (000's) $ 605,688 $ 600,583 $ 556,629 $ 566,076 $ 381,250 $ 373,521 ELECTRIC PLANT (000'S) Total Electric Plant $ 372,782 $ 358,878 $ 341,526 $ 323,664 $ 303,637 $ 281,606 Depreciation Reserve 101,633 96,595 87,736 81,934 75,667 71,184 - --------------------------------------------------------------------------------------------------------------------------------- Net Electric Plant $ 271,149 $ 262,283 $ 253,790 $ 241,730 $ 227,970 $ 210,422 ================================================================================================================================= CAPITALIZATION (000'S) Short-Term Debt $ 12,000 $ 34,000 $ 32,500 $ 35,000 $ 27,000 $ 36,000 Long-Term Debt 263,028 221,643 274,221 288,075 116,367 119,126 Redeemable Preferred Stock 7,604 9,137 10,670 12,070 13,740 15,168 Preferred Stock 4,734 4,734 4,734 4,734 4,734 4,734 Common Equity 118,864 106,558 108,321 103,192 105,658 93,944 - --------------------------------------------------------------------------------------------------------------------------------- Total $ 406,230 $ 376,072 $ 430,446 $ 443,071 $ 267,499 $ 268,972 ================================================================================================================================= CAPITAL STRUCTURE RATIOS (%) Short-Term Debt 3.0% 9.1% 7.5% 7.9% 10.1% 13.4% Long-Term Debt 64.7% 58.9% 63.7% 65.0% 43.5% 44.3% Preferred Stock 3.0% 3.7% 3.6% 3.8% 6.9% 7.4% Common Stock 29.3% 28.3% 25.2% 23.3% 39.5% 34.9% - --------------------------------------------------------------------------------------------------------------------------------- Total 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% ================================================================================================================================= MISCELLANEOUS STATISTICS Shares Outstanding (Average) 7,363,424 7,363,424 7,336,174 7,264,360 6,947,746 5,862,411 Shares Outstanding (Year End) 7,363,424 7,363,424 7,363,424 7,301,557 7,185,143 6,225,394 Number of Stockholders (Year End) 6,868 6,868 7,734 8,250 7,705 7,511 Basic Earnings (Loss) per Common Share $ 1.39 $ (.24) $ 1.33 $ 0.36 $ 0.84 $ 0.63 * Diluted Earnings (Loss) per Common Share $ 1.33 $ (.24) $ 1.33 $ 0.36 $ 0.84 $ 0.63 * Dividends Declared per Common Share $ - $ - $ 0.72 $ 0.87 $ 1.32 $ 1.32 Book Value per Common Share $ 16.14 $ 14.47 $ 14.71 $ 14.13 $ 14.71 $ 15.09 Return on Common Equity 9.11% (1.64)% 9.09% 2.51% 5.55% 3.99%* Ratio of AFDC to Common Stock Earnings 11% (48)% 12% 48% 45% 143%* Ratio of Earnings to Fixed Charges 1.59 0.86 1.50 1.14 1.49 1.04* Payout Ratio - - 54% 242% 157% 210%* Percentage of Construction Expenditures Funded Internally 100% 100% 100% 100% 86% 72% ================================================================================================================================= RESIDENTIAL CUSTOMER DATA Average Number of Customers 90,888 90,433 89,769 86,194 85,041 84,211 Kilowatt-Hours per Customer 5,753 5,896 5,976 5,953 6,073 6,118 Revenue per Customer $ 785.54 $ 746.76 $ 744.19 $ 766.42 $ 752.67 $ 762.89 Revenue per Kilowatt-Hour in cents 13.65 12.67 12.45 12.88 12.39 12.47 ================================================================================================================================= MISCELLANEOUS SYSTEM DATA Net System Capability at Time of Peak (MW) Firm 381.54 344.44 373.04 330.01 340.45 341.17 System Peak Demand (MW) 281.63 277.06 274.32 267.98 275.84 267.42 Reserve Margin at Time of Peak 35.5% 24.3% 36.0% 23.2% 23.4% 27.6% System Load Factor 75.4% 79.5% 77.0% 79.9% 73.5% 76.4% ================================================================================================================================= * Includes the reserve established on certain licensing activites in 1993 ($5.6 million after taxes or $.95 per common share). (See note 6).
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Item 7 RECENT EVENTS AFFECTING THE ELECTRIC UTILITY INDUSTRY AND THE COMPANY RESTRUCTURING THE INDUSTRY-In 1997, the Maine Legislature enacted "An Act to Restructure the State's Electric Industry", some of the principal provisions of which are as follows: (1) Beginning on March 1, 2000, all consumers of electricity shall have the right to purchase generation services directly from competitive electricity suppliers who will not be subject to rate regulation. (2) The Company must divest of most of its generation related assets and business functions. As discussed below, the Company has reached agreement for the sale of many of those assets and is preparing for an anticipated closing of that transaction. (3) Billing and metering services will be subject to competition beginning March 1, 2002, but the legislation permits the Maine Public Utilities Commission (MPUC) to establish an earlier date, no sooner than March 1, 2000. (4) The Company will continue to provide transmission and distribution services and continue to be subject to regulation by the MPUC. (5) Maine electric utilities will be permitted a reasonable opportunity to recover legitimate, verifiable and unmitigable costs that are otherwise unrecoverable as a result of retail competition in the electric utility industry ("stranded costs"). Under the restructuring law, the Company, as a transmission and distribution utility, will be prohibited from engaging in the generation and sale of electric energy. The law permits the Company to establish an independent affiliate to engage in retail electricity marketing activities, but only on a limited basis and subject to stringent rules governing the relationship among the regulated utility, its independent marketing affiliate and other competitors. In light of those restrictions, the Company does not believe it will be involved in the generation and sale of energy after March 1, 2000 and that its basic business will continue to be as a regulated transmission and distribution utility. The Company may also pursue appropriate opportunities in other regulated or unregulated business activities that are compatible with the Company's basic business and are not burdened with the restrictions that will apply to electricity marketing activities. Much of the Company's focus and resources over the near term will be devoted to facilitating the implementation of the restructuring law. Many of the Company s basic business processes will have to be adapted to meet the requirements of the changed business environment. In addition, the MPUC will soon be deciding a number of issues relating to restructuring that will have an impact on the Company's future earnings, including the procedures for future rate regulation and the levels of stranded costs for which recovery will be allowed. For a more complete discussion of the industry restructuring legislation and the current MPUC proceedings to determine the Company's stranded cost recovery, see Note 10 to the Consolidated Financial Statements. AGREEMENT ON SALE OF COMPANY'S GENERATING ASSETS-On September 25, 1998, the Company and PP&L Global, Inc., a Pennsylvania corporation and a subsidiary of PP&L Resources, Inc., reached an agreement for PP&L Global to acquire most of the Company's electric generating assets with a combined base load capacity of 89.2 megawatts and certain transmission rights for a sale price of $89 million. The proposed sale is a result of the Company's effort to comply with Maine s electric utility restructuring legislation, which took effect in September 1997. The Company began seeking proposals from prospective bidders to purchase its generation and generation-related assets in early 1998 and as part of the auction process, received final bids from various bidders in August 1998. The electric utility restructuring law requires all of Maine's investor-owned electric utilities to divest all of their non-nuclear generation assets and generation-related business before March 1, 2000. The law was enacted to foster competition in an open market in which retail consumers will choose among competitive energy providers of the electricity that flows through the wires. The management of the "wires" or transmission and distribution business will remain the regulated function of the existing utilities. Pursuant to the agreement, the Company has agreed to sell to PP&L Global (i) its Ellsworth, Howland, Milford, Medway, Orono, Stillwater and Veazie hydroelectric facilities, which are all situated along the Penobscot River Basin and Union River in Maine, (ii) the 50% ownership interest owned by Penobscot Hydro Co., Inc., a wholly owned subsidiary of the Company, in Bangor-Pacific Hydro Associates, which owns a 13 megawatt hydroelectric generating facility located in Enfield and Howland, Maine, (iii) the Company s 8.33% joint ownership interest in the William F. Wyman Unit No. 4 oil-fired steam plant located in Yarmouth, Maine, (iv) the Company's designs, applications and other rights with respect to the potential development of the Basin Mills hydroelectric project, to be located in Bradley and Orono, Maine, (v) the Company s designs, applications and other rights with respect to the potential development of a high-voltage transmission line from Orring- ton, Maine, to New Brunswick, Canada, and (vi) certain of the Company's rights to transmission capacity, including its rights as a participant in the regional utilities agreements with Hydro-Quebec. The sale is subject to certain closing conditions as set forth in the agreement, including receipt of approvals by federal and state regulatory agencies. The MPUC has already given approvals for the sale, and other outstanding governmental proceedings should be resolved within the next few months. In addition, third-party consents to the sale of certain of the assets will be required, and the Company cannot predict whether or on what terms such consents can be obtained. The Company anticipates that most of the net after-tax proceeds from the sale will be used to retire outstanding debt. The Company expects that a portion of the sale value will be applied to reduce the Company s stranded costs for regulatory purposes, which should lower the amounts that would otherwise be collected in the future from customers. SALE OF PROPERTY AT GRAHAM STATION-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 property is to be utilized by Casco Bay Energy, which plans to construct a $221 million gas-fired power plant that will produce 520 megawatts of electricity. The plant will be powered by the proposed Maritimes & Northeast gas transmission line and regional transmission system. The Company realized a net gain from the sale of $4.5 million, which has been deferred (reflected as a component of Other Deferred Credits on the Consolidated Balance Sheet at December 31, 1998) in anticipation that it will likely be utilized as a future reduction to the Company s recoverable stranded costs. 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 to the Company in January 1999 and has been 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. Management does not expect the future remediation costs at the site to exceed this amount. 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 nuclear generating plant in Wiscasset, Maine. The plant is currently in the process of being decommissioned, and the Company is obligated to pay its prorata share of Maine Yankee's plant closure and decommissioning costs. On January 19, 1999, various interested parties submitted an offer of settlement with the Federal Energy Regulatory Commission (FERC) that, if accepted by FERC, will finally settle a number of outstanding rate recovery issues with respect to the Company s ownership of Maine Yankee. For a more complete discussion of the recent events associated with Maine Yankee, see Note 6 to the Consolidated Financial Statements. AMENDED AND RESTATED REVOLVING CREDIT AND TERM LOAN AGREEMENT-As reported in the 1997 Form 10-K, during 1997 the Company negotiated amendments to the credit agreement with its lending banks in order to resolve potential violations of certain financial covenants. As a result of those amendments, the Company reported that during 1998 or beyond, future cash needs might exceed the borrowing capacity under the credit facility, and accordingly, the Company might be required to find new sources of financing. 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. Under current projections of cash needs, the new facilities should provide adequate borrowing capacity. The Company was in compliance with all financial covenants associated with the new credit agreement as of December 31, 1998. The credit agreement also provided for the issuance of a letter of credit required to support $4.2 million of the Company's Pollution Control Revenue Bonds. To secure the existing letter of credit related to the Pollution Control Revenue Bonds, until the new letter of credit could be issued, the Company deposited approximately $4.6 million of the proceeds from this financing with a third party trustee. The new letter of credit was issued in October 1998, and the $4.6 million deposited with the third party trustee was released to the Company. These funds were utilized to repay amounts outstanding under the Company s revolving credit facility. MONETIZATION OF POWER SALE CONTRACT-As reported in the 1997 Form 10-K, the Company had been negotiating a transaction for the monetization of a power sale contract with UNITIL Power Corp. (UNITIL), a New Hampshire based electric utility. The Company provided power to UNITIL at significantly above-market rates, with the contract term ending in the year 2003. Based upon projections of wholesale electricity markets, it was expected that the rates charged under the UNITIL contract would remain at above-market levels for the remainder of the contract term. Therefore, the assignment of the Company s rights under the contract had a positive present cash value. On March 31, 1998, the Company completed a transaction with a financial institution that provided a loan of approximately $23.3 million in net proceeds secured by the value of the UNITIL contract. Also as reported in the 1997 Form 10-K, beginning in early 1997, the Company failed to comply with certain financial covenants under its bank lending agreements and received temporary waivers from the lending banks. By using a portion of the proceeds of the UNITIL monetization to pay down a portion of the bank obligations, the Company was able to negotiate permanent waivers of the earlier financial covenant violations. At the time the Company filed its 1997 Form 10-K, the monetization of the UNITIL contract had not been completed and the financial covenant violations had, therefore, not been waived permanently. As discussed in the 1997 Form 10-K, all debt under the bank credit facilities, including certain medium term notes, was classified as a current liability on the Company s Consolidated Balance Sheets as of December 31, 1997. As a result of the permanent waivers that became effective upon completion of the UNITIL monetization, $22 million of medium term notes, previously classified as a current liability, were reclassified as a long-term liability as of March 31, 1998. RESTRUCTURING OF POWER PURCHASE CONTRACT-As previously reported in the 1997 Form 10-K, the Company had been working to restructure a power purchase contract with the Penobscot Energy Recovery Company (PERC), its last remaining high-priced non-utility generator contract that offered a potential for substantial savings. 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. This major restructuring involved several separate components which are more fully explained in Note 6 to the Consolidated Financial Statements. Depending upon a number of assumptions, including the ultimate cost of the warrants and markets for solid waste disposal, it is projected that the restructuring will result in cost savings to Bangor Hydro over the next twenty years with a net present value of $25-40 million. The anticipated savings resulting from this transaction were used to reduce the level of electric rates approved by the MPUC in the Company's recent general rate case by approximately $2.4 million on an annual basis. The Company has deferred, as a regulatory asset, the $6.25 million in payments to PERC, approximately $1.5 million in costs associated with the contract restructuring, and $2 million for the estimated fair value of the warrants. As discussed above, the Company is currently recovering PERC restructuring costs in rates. The $2 million in warrants have also increased additional paid-in capital on the Consolidated Balance Sheets. STORM DAMAGE-As discussed in the 1997 Form 10-K, 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 have been deferred and included in Other Deferred Charges on the Company s Consolidated Balance Sheets 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. The Company is seeking to begin recovery of those deferred costs on May 1, 1999 as part of its annual rate adjustment pursuant to its Alternative Rate Plan (see Note 10). BANGOR GAS JOINT VENTURE-The Company and Energy Pacific, LLC, now Sempra Energy, have formed a joint-venture company, Bangor Gas Company, LLC, (Bangor Gas), that, in the second quarter of 1998, received unconditional authority from the MPUC to provide natural gas service to the greater Bangor area. In October 1998 the Company received authorization from the MPUC to invest approximately $1.2 million in Bangor Gas. Los Angeles based Sempra Energy is a joint-venture of Pacific Enterprises and Enova Corporation. Pacific Enterprises is the parent company of Southern California Gas Company, the nation's largest natural gas distribution company. Enova is the parent of San Diego Gas and Electric Company. Together, the two companies provide natural gas to approximately six million customers in California. Pacific Enterprises and the Company worked together in a partnership to develop the West Enfield Hydro Project in 1986. Gas service to Maine will be made economically feasible for the first time by the Maritimes and Northeast Pipeline Project, slated for completion in late 1999. The new pipeline will extend from the Sable Offshore Energy Project near Sable Island, Nova Scotia, through the state of Maine and interconnect with the Tennessee Gas Pipeline in Dracut, Massachusetts. The route, as proposed, comes near the Bangor area, providing an opportunity for retail gas distribution in the greater Bangor marketplace. Company officials estimate the cost to build and implement the new Bangor Gas system to be approximately $40 million. The Company is not obligated but has the opportunity to make material capital contributions to the joint-venture in the near term. COMMON STOCK DIVIDENDS-At its March 19, 1997 meeting, the Board of Directors determined that the payment of common stock dividends should be suspended, and to date, no additional common stock dividend has been declared. IMPACT OF THE YEAR 2000 ISSUE-The "Year 2000" problem exists because some computer programs and embedded microchips may not properly recognize a year that begins with "20" instead of "19", and therefore may fail or create erroneous results. The Company is actively engaged in identifying, assessing, and responding to the implications of this problem for its operations. The Company has identified all of its information technology systems and is assessing and testing its Year 2000 compliance. The Company has established a structured approach which inventories and prioritizes its electrical systems, client server and network applications, desktop and personal computer systems, and facilities. The Company s goal is that most, if not all, computer programs and embedded chips that support its mission critical operations will be compliant by mid-year 1999. The Company's business is dependent upon external parties, such as suppliers and business partners, for the reliable delivery of its products and services. The Company has inquired in writing to its suppliers and service providers with regard to their Year 2000 compliancy, and has established appropriate follow-up procedures. The Company has also identified the third parties with which it has a material relationship in order to establish their Year 2000 status in a timely fashion, and is continuing to do so. In addition to normal suppliers and business partners, the Company has a risk that power will not be available on the New England Power Pool (NEPOOL) grid for purchase and distribution to the Company s customers if electrical system failures occur due to the Year 2000 issue. This is a significant risk, since the Company purchases a substantial portion of its energy, which is received through the NEPOOL grid. The Company is working to mitigate this risk by participation on the Independent System Operator (ISO) subcommittees and in the NEPOOL/ISO New England Year 2000 Joint Oversight Committee which has been given responsibility for operational reliability of the NEPOOL Control Area. This group is in the early stages of assessing NEPOOL/ISO s Year 2000 problem and has a goal of ensuring the NEPOOL Control Area is Year 2000 compliant by July 1, 1999. In addition, the Company is participating in and complying with North American Electric Reliability Council (NERC) Year 2000 reporting and guidelines. NERC has been given authority from the President's Council on Year 2000 via the Department of Energy and has the responsibility for guidance and oversight for the nation's electrical systems. The Company began an initial information technology awareness plan in 1992 with the year 2000 in mind. There was an immediate development of a long-term (five-year) technology plan to address the year 2000 as well as other issues such as obsolete applications, hardware, and infrastructure. Implementation of this five-year plan began in 1994 with two mission critical projects for replacing the Customer Information System and implementing a new Geographical Information System. In addition, the Company began replacement of its Financial Information Systems in 1995. These major projects and the advancement of technology in general drove infrastructure upgrades. In addition to the major applications mentioned above, the Company has continually updated its transmission and distribution systems, substations, and metering devices and has become increasingly more reliant on various technologies. Due to the nature of the technological architecture and the fact that the Company has kept pace with technologies, many of the enterprise information systems are stated to be compliant by the vendors and the Company does not believe it will need to expend funds to implement totally new enterprise systems. The Company does, however, have other hardware and software that is not compliant and will need to be replaced or upgraded. In addition, the Company will also be conducting comprehensive testing to help ensure a compliant environment exists and conducting vendor inquiries. The Company has also begun comprehensive contingency planning for its own operations and continues to monitor the integrated contingency planning efforts of NERC and the Northeast Power Coordinating Council. The estimated cost to conduct testing, develop or modify contingency plans, and replace non-compliant technologies is approximately $2 million, with most of these costs to be incurred during 1999. Approximately $850,000 of these estimated costs are expected to be capitalized, instead of being charged to expense, since the costs relate principally to investments in new equipment and technologies and not the modification of existing systems. To date, approximately $408,000 has been expended in connection with the Year 2000 issue, of which $320,000 has been capitalized and $88,000 charged to expense. Time and cost estimates are based on currently available information and could be affected by the ability to correct all relevant computer codes and equipment, and the Year 2000 readiness of the Company's business partners, among other factors. There is no certainty as to whether the Company will be able to solve its potential Year 2000 issues. Consequently, the Company is in the process of identifying and verifying realistic failure scenarios which will require contingency plans. While its analysis has not been completed, the Company anticipates establishing a prioritized list of potential failures with a formal contingency plan for each one deemed critical to its ongoing operations during 1999. Based on information reviewed to date, the Company believes its plans of action are adequate for Year 2000 compliance of its critical systems and to reduce the risk of external impacts to its operations. Nevertheless, achieving Year 2000 compliance is subject to the risks and uncertainties described above and adverse effects, should they occur, could be material despite the Company's efforts to prevent or mitigate them. 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, 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, the Year 2000 issue 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 1998, 1997 and 1996 as they affect the Company s liquidity. Net cash provided by operations was $30.9 million in 1998, $36.4 million in 1997 and $44.8 million in 1996. Negatively impacting cash flows from operations in the 1998 period were the approximately $7.7 million in costs incurred to restructure the PERC purchased power contract, approximately $4.5 million in incremental costs incurred in connection with the January 1998 ice storm, as well as $2.3 million in costs incurred related to selling the Company s generation assets. Cash flows were also reduced by the effect of a large customer, who prepaid its electric usage for a one-year period in the third quarter of 1997. Finally, reducing cash flows from operations in the 1998 period was approximately $1.5 million in costs incurred associated with the new revolving credit facility, term loan and the $24.8 million in medium term notes. Offsetting these cash flow reductions was the beneficial impact of the 3.8% temporary rate increase on July 1, 1997, the 5.83% rate increase effective February 1998, and the reduction in Maine Yankee related costs incurred in 1998 as a result of the shutdown of the plant in 1997. Also impacting cash flows from operations was the previously discussed Graham Station property sale proceeds. While the Company did realize a $4.5 million gain on sale of the property, the full $6.2 million in proceeds were required to be deposited with a third party trustee. 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. The principal reason for the decrease in cash flows from operations in 1997 was the impact of Maine Yankee. The Company incurred approximately $10.7 million in additional Maine Yankee operating and replacement power costs in 1997 as compared to 1996. Also, the Company incurred $2.7 million in Maine Yankee refueling outage costs in 1997. The Company s cash flows were improved with the 3.8% temporary rate increase effective July 1, 1997. Positively impacting cash flows in the 1997 period was the payment of $545,000 in income taxes, as compared to $2.3 million in income tax payments in 1996. The Company made approximately $2 million less in interest payments in 1997 as compared to 1996. Also enhancing cash flows from operations in 1997 was an improvement in accounts receivable collections for one of the Company s largest customers. In the third quarter of the 1997, the Company received $2.6 million from a large customer, who prepaid its electric usage for a one-year period. Finally, in the 1996 period, the Company expended $1.7 million to terminate a demand-side management contract. Over the last three years, capital expenditures have been $18.2 million in 1998, $17.5 million in 1997 and $18.8 million in 1996. In 1998, approximately $2.6 million of the capital expenditures was related to implementing new geographic and financial information systems, $.9 million was related to the Company s power production facilities, $7.3 million was for its distribution system, and $6.2 million was 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 $65 million over the next three years (excluding capital expenditures related to the previously discussed gas fired power plant being developed by Casco Bay Energy, which will be reimbursed), although it may be necessary to adjust the budget for capital expenditures on a year-to-year basis. No common dividends were paid in 1998. Dividends paid on common stock were lower in 1997 as compared to 1996 due to the suspension of the common dividend, beginning with the first quarter of 1997. The reduction in preferred dividends paid in 1998 and 1997 resulted from sinking fund payments made on the Company's 8.76% mandatory redeemable preferred stock. 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 contract monetization. In 1998 the Company made a sinking fund payment of $1.5 million on its 8.76% mandatory redeemable preferred stock. As discussed in more detail in Note 3 to the Consolidated Financial Statements, the Company also made approximately $94,000 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. As previously discussed, 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 discussed above. Also, as previously discussed, the Amended and Restated Revolving Credit and Term Loan Agreement provided a two-year term loan of $45 million. In 1997 the Company repaid $14 million of principal on its outstanding medium term notes and made $1.9 million in sinking fund payments on its 12.25% first mortgage bonds. In 1997, the Company also made a sinking fund payment of $1.5 million on its 8.76% mandatory redeemable preferred stock. The Company also made approximately $94,000 in make whole provision payments under the 8.76% preferred stock purchase agreement. In 1996, the Company made a $12 million payment on its medium term notes, $1.6 million in sinking fund payments on its 12.25% first mortgage bonds, $3 million in sinking fund payments on its 8.76% mandatory redeemable preferred stock, and approximately $188,000 in make whole provision payments. Capital and operating needs in 1998, 1997 and 1996 were met through internally generated funds, the Company's revolving credit line, and, for 1998, the new medium term notes. As a result of the Amended and Restated Revolving Credit and Term Loan Agreement, the new facilities should provide adequate borrowing capacity for the Company's operation, maintenance and construction funding requirements. The Company has $181.1 million of first mortgage bond and other long-term debt sinking fund requirements and maturities in the period 1999-2003. The Company also has $1.5 million of mandatory annual sinking fund payments and $94,000 of annual payments under the make whole provision on its redeemable preferred stock. RESULTS OF OPERATIONS Earnings (loss) per common share were $1.39, $(.24), and $1.33 for the years ended 1998, 1997 and 1996, respectively. Earned return on average common equity was 9.1% in each of 1998 and 1996. The improvement in 1998 earnings is attributable largely to the February 1998 rate increase authorized by the MPUC designed to increase annual revenues by approximately $13.2 million. Negatively impacting earnings in 1997 was the previously discussed shutdowns of Maine Yankee. Positively impacting earnings in 1997 and 1996 was the 1995 buyout of two high-cost power purchase contracts from non-utility generating plants. Electric operating revenue for 1998 increased by $7.8 million as compared to 1997 principally due to the 3.8% temporary rate increase effective on July 1, 1997 and the additional 5.83% rate increase effective February 1998. Also benefitting 1998 revenues was a $1 million increase in off-system sales (sales related to power pool and interconnection agreements and resales of purchased power). Offsetting these positive factors somewhat was a 3.4% reduction in total kilowatt-hour (KWH) sales (excluding off-system sales) in 1998 as compared to 1997, due primarily to decreased usage by the Company s largest special contract customers and the fact that 1998 was the warmest year on record, which along with the January 1998 ice storm, resulted in reduced electricity sales. Also decreasing electric operating revenues in 1998 as compared to 1997 was the recording in 1997 of $335,000 in revenues from the sale of air emission allowances to a coal fired generating facility, and $350,000 in revenue recognized under a shared savings distribution agreement with another utility. Effective January 1, 1997 the Company renegotiated the revenue sharing portion of a special rate contract with its largest industrial customer. The rate for this customer is based in part on a revenue sharing arrangement whereby the revenues for service vary depending on the price and volume of product sold by the industrial customer to its customers. Under the revised revenue sharing formula, the revenues from the revenue sharing were reduced by approximately $3.2 million in 1997 as compared to 1996. Electric operating revenue for 1997 decreased by $49,000 as compared to 1996. There was a $4.9 million decrease in off-system sales in 1997, and revenue sharing (discussed above) decreased by $3.2 million in 1997. Electric operating revenue associated with KWH sales, excluding off-system sales, increased by $6.9 million or 4.26% in 1997 as compared to 1996, due to the impact of the 3.8% temporary rate increase effective July 1, 1997, and an overall 4.0% increase in total KWH sales in 1997, excluding off-system sales. These increases were offset by the effect of adjusting prices downward to some customers in order to retain sales that would otherwise be lost to competitive pressures. Of the 4.0% total increase in KWH sales in 1997, approximately 68% was related to increased usage by the Company s largest special contract customers. Fuel for generation and purchased power expense decreased by $10.8 million in 1998 as compared to 1997. The principal reason for the reduction was lower expenses associated with the permanent shutdown of the Maine Yankee nuclear power plant in 1998, as compared to maintaining the plant in an operating mode in the first five months of 1997. Also, in connection with the Company's recent rate order (see the 1997 Form 10-K for discussion of the rate order), the Company was ordered to defer, for future recovery, the excess of actual Maine Yankee related costs incurred during 1998 over the Maine Yankee costs included in the rate order. In the 1998 period, Maine Yankee related expenses, including the cost of replacement power, were approximately $7.3 million lower than in 1997. The Company also recorded a $2 million benefit in 1998 related to savings realized from the previously discussed PERC contract restructuring. Also, in December 1997 the Company charged to expense $1.9 million of previously deferred Maine Yankee refueling costs, as a result of the Company's February 1998 rate order, which disallowed recovery of these deferred costs. The Company realized positive cash settlements under its fuel hedge program (for a more complete discussion of the Company s fuel hedge program, see Note 13 to the Consolidated Financial Statements) in 1997 as compared to negative cash settlements in 1998. This change is due principally to the spot price of residual oil decreasing significantly (over 25%) in 1998 as compared to 1997, increased hedge volume (covering replacement power for the Maine Yankee closure) in 1998, and the Company's hedge in 1998 was at a higher fixed cost than in 1997. Also offsetting the previously discussed decreases to some extent was the $1.0 million increase in off-system sales in the 1998 period, as well as the impact of the 3.4% reduction in KWH sales in 1998 as compared to 1997. The $14.3 million increase in fuel for generation and purchased power expense in 1997, as compared to 1996, was principally due to the Maine Yankee shutdown. The increased expense in 1997 was also attributable to the 4.0% increase in KWH sales in 1997 (excluding off-system sales), a reduction in the Company's hydroelectric power generation in 1997, as well as an overall increase in the price of purchased power in 1997 as compared to 1996. Also, the Company realized greater benefits/cash settlements under its fuel hedge program in 1996 as compared to 1997, due principally to the spot price of residual oil decreasing significantly in 1997 (as compared to 1996), and the Company's hedge in 1997 was at a higher fixed cost than in 1996. Finally, in 1997, as discussed above, the Company charged to expense $1.9 million of previously deferred Maine Yankee refueling costs. Offsetting these increases was the $4.9 million reduction in off-system sales in 1997. Also, in 1997 the Company deferred approximately $719,000 in Maine Yankee related costs in connection with the February 1998 rate order discussed above. Other operation and maintenance (O&M) expense increased by $2.0 million in 1998 as compared to 1997. O&M payroll expense increased by $1.5 million due principally to significantly less payroll charged to the Company's capital program in 1998. The lower capital labor was primarily a result of service restoration efforts associated with the January 1998 ice storm. The Company was ordered by the MPUC to defer incremental non-capital costs related to the ice storm, but the non-incremental labor costs were charged principally to other O&M in the first quarter of 1998. The increase from 1997 to 1998 was also impacted by a 3% wage rate increase for union employees in 1998 and various nonunion wage rate increases. Also affecting the greater other O&M expense in 1998 was a $680,000 increase in postretirement medical and pension and active employee medical costs in 1998 as compared to 1997. Depreciation and amortization expense decreased $438,000 in 1998 as compared to 1997. Effective February 1998, in connection with the Company's most recent rate order, the Company lengthened the depreciable lives of its large information system capital projects from seven to ten years, and began amortizing its $3.6 million overaccumulated depreciation reserve ($1.6 million of amortization in 1998), thus reducing depreciation expense. These decreases were offset to some extent by the impact of 1998 property additions. The increases in depreciation and amortization expense in 1997 as compared to 1996 was principally caused by the termination, on December 31, 1996, of the amortization of the remaining balance of the overaccumulated reserve for depreciation. This amortization, which reduced annual depreciation expense, amounted to $1.8 million in 1996. The depreciation expense increase in 1997, as well as in 1996, was also affected by the growth in the Company s electric plant in service, including the effect of the implementation of large information system projects, which have shorter useful lives than traditional utility equipment. The Company's expenses over the period 1996-1998 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 collect from customers (thus the term "regulatory assets"). Although there are a number of such authorized amortizations, the major ones are the allowable recovery of the Company's 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 be returned to its level prior to the temporary rate order. Effective with the latest 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 $2.9 million in 1998 as compared to $6.1 million in 1997. 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 1998 and 1997. Also impacting amortization of contract buyouts and restructuring was the start of the amortization of the previously discussed PERC contract restructuring on July 1, 1998, resulting in $500,000 of amortization in 1998. Property and other taxes increased in 1998 due to increases in property taxes, as a result of increases in property levels and property tax rates, and due to the previously mentioned increase in O&M labor costs in 1998, associated payroll taxes increased in 1998. Property and other taxes decreased during 1997, due primarily to funds received related to a property tax abatement with one of the municipalities in the Company's service territory and receipts under the state of Maine s personal property tax reimbursement program, offset by the effect of increases in property levels and property tax rates. The increase in income taxes was principally a function of greater earnings in 1998 as compared to 1997. The decrease in income taxes in 1997 as compared to 1996 was primarily a function of the operating loss in 1997 and earnings in 1996. Income tax expense in 1997 was increased by $184,000 in investment tax credits (ITC) recorded in 1996 for financial reporting purposes, which were subsequently unable to be utilized when the 1996 federal income tax return was filed in 1997. Income tax expense in 1996 was reduced by the utilization of $947,000 of federal and state ITC. The increase in allowance for funds used during construction (AFDC) in 1998 as compared to 1997 was due primarily to recording carrying costs on deferred ice storm and incremental Maine Yankee related costs. AFDC related to construction work in progress was lower in 1998 due to reduced construction activity. The 1997 decrease in AFDC was principally a function of lower levels of construction work in progress. The decreases in other income in 1998 and 1997 was due primarily to the write-off of start-up costs associated with non-core business ventures by the Company. The increase in long-term debt interest expense in 1998 was due primarily to the previously discussed issuance of the $24.8 million of medium term notes on March 31, 1998 and the $45 million term loan issued in June 1998, offset by the previously discussed principal repayments in 1997 and 1998 on various long-term debt issues. Long-term debt interest expense decreased $1 million in 1997 as compared to 1996 due to $14 million in principal repayments on the medium term notes in 1997, as well as $1.9 million in sinking fund payments on the Company s 12.25% first mortgage bonds. Other interest expense decreased due principally to a $10.9 million reduction in the weighted average short-term borrowings in 1998 as compared to 1997, as well as a slight decrease in the weighted average interest rate (including fees) on the borrowings. These decreases were offset to some extent by a $337,000 increase in the amortization of debt issuance costs in 1998. The decrease in other interest expense in 1997 was principally a function of a $2.4 million reduction in weighted average short-term borrowings outstanding in 1997 as compared to 1996, offset by an approximately 1/2% increase in the weighted average short-term debt interest rate (including fees) in 1997. CONTINGENCIES AND RISK MANAGEMENT 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. As to the only other site which has been listed by the Department of Environmental Protection as an Uncontrolled Hazardous Substance Site, the Company was informed that it is considered a de minimis generator. 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 these waste disposal sites. 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, 1998, the liability recorded by the Company for its estimated environmental remediation costs amounted to $331,000. The Company's actual future environmental remediation costs may be higher as additional factors become known. RISK MANAGEMENT-The Company's major financial market risk exposures are changing interest rates and changes in purchased energy prices. 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 combination of both fixed and variable rate debt instruments and derivative financial instruments, including an interest rate swap and interest rate caps (see Notes 4 and 13). The Company manages purchased energy price risk through the use of swaps (see Note 13). The Company does not hold or issue derivatives for trading purposes. NEW ACCOUNTING PRONOUNCEMENTS In June 1998, the Financial Accounting Standards Board issued Statement No. 133, "Accounting for Derivative Instruments and Hedging Activities" (FASB 133), and is effective for fiscal years beginning after June 15, 1999. FASB 133 establishes accounting and reporting standards for derivative instruments and for hedging activities. It requires that an entity recognize all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. Changes in the derivatives fair value should be recognized currently in earnings unless the derivative is designated as a hedge. When designated as a hedge, the change in fair value should be recognized currently in changes in equity. FASB 133 also requires a company to formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment. The affects of the adoption of FASB 133 on the Company s financial statements are currently not known. The Company believes that its fuel and interest rate swap agreements will qualify for hedge accounting treatment under FASB 133. In April 1998, the American Institute of Certified Public Accountants issued Statement of Position 98-5, "Reporting on the Costs of Start-up Activities" (SOP 98-5). The Company is required to adopt SOP 98-5 for fiscal year 1999. SOP 98-5 defines start-up activities as onetime activities an entity undertakes when it opens a new facility, introduces a new product line or service, conducts business in a new territory or with a new class of customer or beneficiary, initiates a new process in an existing facility or commences some new operation. SOP 98-5 covers accounting for organization costs and requires that any such costs should be expensed as incurred in the same manner as other start-up costs. The statement requires entities to expense previously capitalized costs in the year of adopting SOP 98-5. The Company does not believe the application of this statement will have a material impact on the financial statements. BANGOR HYDRO-ELECTRIC COMPANY Item 8 CONSOLIDATED STATEMENTS OF INCOME Financial Statements & Supplementary Data For the Years Ended December 31, 1,998 1997 1996 ELECTRIC OPERATING REVENUE (Note 1): $ 195,144,007 $ 187,324,379 $ 187,373,630 -------------- --------------------------- OPERATING EXPENSES: Fuel for generation and purchased power (Notes 1 and 3) $ 82,026,860 92,791,842 $ 78,476,864 Other operation and maintenance (Notes 1 and 5) 34,448,324 32,471,149 32,440,649 Depreciation and amortization (Note 1) 9,749,229 10,187,102 7,429,719 Amortization of Seabrook Nuclear Project (Note 7) 1,699,050 1,699,050 1,699,050 Amortization of contract buyouts and restructuring (Note 6) 20,442,441 23,218,500 20,836,561 Taxes - Local property and other 5,549,049 5,124,146 5,367,045 Income (Note 2) 6,093,286 (1,956,303) 4,882,453 -------------- --------------------------- $ 160,008,239 163,535,486 $ 151,132,341 -------------- --------------------------- OPERATING INCOME $ 35,135,768 23,788,893 $ 36,241,289 OTHER INCOME AND (DEDUCTIONS): Allowance for equity funds used during construction (Note 1) 430,028 285,972 368,056 Other, net of applicable income taxes (Notes 1 and 2) 862,723 1,005,849 1,097,931 -------------- --------------------------- INCOME BEFORE INTEREST EXPENSE $ 36,428,519 25,080,714 $ 37,707,276 -------------- --------------------------- INTEREST EXPENSE: Long-term debt (Notes 4 and 13) $ 22,906,021 22,638,201 $ 23,651,316 Other (Note 4) 2,750,863 3,392,169 3,529,002 Allowance for borrowed funds used during construction (Note 1) (693,682) (562,966) (755,708) -------------- --------------------------- $ 24,963,202 25,467,404 $ 26,424,610 -------------- --------------------------- NET INCOME (LOSS) $ 11,465,317 (386,690)$ 11,282,666 DIVIDENDS ON PREFERRED STOCK (Note 3) 1,244,488 1,375,888 1,537,202 -------------- --------------------------- EARNINGS (LOSS) APPLICABLE TO COMMON STOCK $ 10,220,829 (1,762,578)$ 9,745,464 ============== =========================== EARNINGS (LOSS) PER COMMON SHARE, based on the weighted average number of shares outstanding of 7,363,424 in 1998 and 1997 and 7,336,174 in 1996 (Note 3): Basic $ 1.39 $ (0.24)$ 1.33 Diluted 1.33 (0.24) 1.33 ============== =========================== DIVIDENDS DECLARED PER COMMON SHARE $ - $ - $ 0.72 ============== =========================== The accompanying notes are an integral part of these consolidated financial statements. BANGOR HYDRO-ELECTRIC COMPANY CONSOLIDATED BALANCE SHEETS December 31, ASSETS 1998 1997 INVESTMENT IN UTILITY PLANT: Electric plant in service, at original cost (Notes 6 and 10) $ 352,975,549 $ 341,008,967 Less - Accumulated depreciation and amortization (Notes 1 and 6) 101,633,446 96,594,713 --------------------------- $ 251,342,103 $ 244,414,254 Construction work in progress (Note 1) 13,929,940 12,011,246 --------------------------- $ 265,272,043 $ 256,425,500 Investments in corporate joint ventures (Notes 1 and 6) - Maine Yankee Atomic Power Company $ 5,438,520 $ 5,531,912 Maine Electric Power Company, Inc. 438,753 326,005 --------------------------- $ 271,149,316 $ 262,283,417 --------------------------- OTHER INVESTMENTS, at cost (Note 6) $ 5,881,986 $ 5,274,213 --------------------------- FUNDS HELD BY TRUSTEE at cost (Notes 4,9 and 11) $ 29,867,605 $ 21,195,772 --------------------------- CURRENT ASSETS: Cash and cash equivalents (Notes 1 and 9) $ 2,945,946 $ 936,796 Accounts receivable, net of reserve ($1,075,000 in 1998 and $1,450,000 in 1997) 17,558,084 16,614,977 Unbilled revenue receivable (Note 1) 12,086,003 11,605,163 Inventories, at average cost: Materials and supplies 2,909,219 2,759,091 Fuel oil 16,233 34,771 Prepaid expenses 1,129,259 1,206,596 Deferred Maine Yankee refueling costs (Note 1 & 10) - 285,894 --------------------------- Total current assets $ 36,644,744 $ 33,443,288 --------------------------- DEFERRED CHARGES: Investment in Seabrook Nuclear Project, net of accumulated amortization of $30,173,196 in 1998 and $28,474,146 in 1997 (Notes 7 and 10) $ 28,668,879 $ 30,367,929 Costs to terminate/restructure purchased power contracts, net of accumulated amortization of $80,058,702 in 1998 and $59,616,261 in 1997 (Notes 6 and 10) 136,979,490 147,632,924 Maine Yankee decommissioning costs (Notes 6 and 10) 50,054,620 60,923,840 Deferred regulatory assets (Notes 2, 5 and 10) 32,995,632 32,551,381 Demand-side management costs (Note 10) 778,742 1,705,311 Other (Notes 10 and 12) 12,666,813 5,204,718 --------------------------- Total deferred charges $ 262,144,176 $ 278,386,103 --------------------------- Total Assets $ 605,687,827 $ 600,582,793 =========================== The accompanying notes are an integral part of these consolidated financial statements. BANGOR HYDRO-ELECTRIC COMPANY CONSOLIDATED BALANCE SHEETS December 31, 1998 1997 STOCKHOLDERS' INVESTMENT AND LIABILITIES CAPITALIZATION (see accompanying statement): Common stock investment (Note 3) $ 118,864,092 $106,558,488 Preferred stock (Note 3) 4,734,000 4,734,000 Preferred stock subject to mandatory redemption, exclusive of sinking fund requirements (Notes 3 and 9) 7,604,150 9,137,160 Long-term debt, net of current portion (Notes 4, 9 and 13) 263,027,692 221,642,897 ---------------------------- Total capitalization $ 394,229,934 $342,072,545 ---------------------------- CURRENT LIABILITIES: Notes payable - banks (Note 4) $ 12,000,000 $ 34,000,000 ---------------------------- Other current liabilities - Current portion of long-term debt and sinking fund requirements on preferred stock (Notes 3, 4 and 9) $ 27,109,119 $ 52,172,468 Accounts payable 13,895,673 13,170,952 Dividends payable 294,593 327,443 Accrued interest 3,474,369 3,666,641 Deferred revenue (Note 1) - 1,570,995 Customers' deposits 328,923 296,706 Current income taxes payable 85,685 7,768 ---------------------------- Total other current liabilities $ 45,188,362 $ 71,212,973 ---------------------------- Total current liabilities $ 57,188,362 $105,212,973 ---------------------------- COMMITMENTS AND CONTINGENCIES (Notes 6, 12 and 14) DEFERRED CREDITS AND RESERVES (Note 2): Deferred income taxes - Seabrook $ 14,880,241 $ 15,765,811 Other accumulated deferred income taxes 63,774,505 55,858,652 Maine Yankee decommissioning liability (Note 6) 50,054,620 60,925,586 Deferred regulatory liability (Note 10) 9,618,159 9,972,246 Unamortized investment tax credits 1,720,708 1,962,014 Accrued pension and postretirement benfit costs (Note 5) 7,770,149 7,034,204 Other (Note 11) 6,451,149 1,778,762 ---------------------------- Total deferred credits and reserves $ 154,269,531 $153,297,275 ---------------------------- Total Stockholders' Investment and Liabilities $ 605,687,827 $600,582,793 ============================ The accompanying notes are an integral part of these consolidated financial statements. BANGOR HYDRO-ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF CAPITALIZATION December 31, 1998 1997 Common Stock Investment (Notes 1 and 3): Common stock, par value $5 per share- Authorized -- 10,000,000 shares Outstanding -- 7,363,424 shares in 1998 and 1997 $ 36,817,120 $ 36,817,120 Amounts paid in excess of par value 59,054,203 56,969,428 Retained earnings 22,992,769 12,771,940 - ------------------------------------------------------------------------------ Total common stock investment $ 118,864,092 $ 106,558,488 - ------------------------------------------------------------------------------ Preferred Stock, Non-participating, cumulative, par value $100 per share, authorized 600,000 shares (Notes 3 and 9): Not redeemable or redeemable solely at the option of the issuer- 7%, Noncallable, 25,000 shares authorized and outstanding $ 2,500,000 $ 2,500,000 4-1/4%, Callable at $100, 4,840 shares authorized and outstanding 484,000 484,000 4%, Series A, Callable at $110, 17,500 shares authorized and outstanding 1,750,000 1,750,000 - ------------------------------------------------------------------------------ $ 4,734,000 $ 4,734,000 - ------------------------------------------------------------------------------ Subject to mandatory redemption requirements- 8.76%, Callable at 103.15% if called on or prior to December 27, 1999, 150,000 shares authorized and 90,000 shares outstanding in 1998 and 105,000 out- standing in 1997 $ 9,198,064 $ 10,731,074 Less-Sinking fund requirements 1,593,914 1,593,914 - ------------------------------------------------------------------------------ $ 7,604,150 $ 9,137,160 - ------------------------------------------------------------------------------ LONG-TERM DEBT (Notes 4, 9 and 13): First Mortgage Bonds- 6.75% Series due 1998 $ - $ 2,500,000 10.25% Series due 2019 15,000,000 15,000,000 10.25% Series due 2020 30,000,000 30,000,000 8.98% Series due 2022 20,000,000 20,000,000 7.38% Series due 2002 20,000,000 20,000,000 7.30% Series due 2003 15,000,000 15,000,000 12.25% Series due 2001 3,742,897 5,521,451 - ------------------------------------------------------------------------------ $ 103,742,897 $ 108,021,451 Less-Sinking fund requirements and current maturity in 1997 1,675,205 4,278,554 - ------------------------------------------------------------------------------ $ 102,067,692 $ 103,742,897 - ------------------------------------------------------------------------------ Variable rate demand pollution control revenue bonds Series 1983 due 2009 $ 4,200,000 $ 4,200,000 - ------------------------------------------------------------------------------ Other Long-Term Debt- Finance Authority of Maine - Taxable Electric Rate Stabilization Revenue Notes, 7.03% Series 1995A, due 2005 $ 113,700,000 $ 126,000,000 Medium Term Notes, Variable interest rate - LIBO rate plus 2%, due 2000 - 34,000,000 Medium Term Notes, Variable interest rate - LIBO rate plus 2%, due 2000 45,000,000 - Medium Term Notes, Variable interest rate - LIBO rate plus 1.125%, due 2002 21,900,000 - - ------------------------------------------------------------------------------ $ 180,600,000 160,000,000 Less: Current portion of long-term debt 23,840,000 46,300,000 - ------------------------------------------------------------------------------ $ 156,760,000 $ 113,700,000 - ------------------------------------------------------------------------------ Total long-term debt $ 263,027,692 $ 221,642,897 - ------------------------------------------------------------------------------ Total Capitalization $ 394,229,934 $ 342,072,545 ============================================================================== The accompanying notes are an integral part of these consolidated financial statements. Bangor Hydro-Electric Company CONSOLIDATED STATEMENT OF CASH FLOWS
For the Years Ending December 31, 1998 1997 1996 -------------- -------------- -------------- Cash Flows From Operations: Net Income (Loss) $ 11,465,317 $ (386,690)$ 11,282,666 Adjustments to reconcile net income (loss)to net cash provided by (used in) operations: Depreciation and amortization 9,749,229 10,187,102 7,429,719 Amortization of Seabrook Nuclear Project (Note 7) 1,699,050 1,699,050 1,699,050 Amortization of costs to terminate/restructure power contracts (Note 6) 20,442,441 23,218,500 20,836,561 Other amortizations 2,035,505 1,784,625 2,126,963 Allowance for equity funds used during construction (Note 1) (430,028) (285,972) (368,056) Deferred income tax provision (Note 2) 6,118,180 (1,766,249) 4,495,490 Deferred investment tax credits, net (Note 2) (241,306) (216,574) (175,464) Changes in assets and liabilities: Cost to restructure purchased power contract (Note 6) (7,704,185) - - Cost to terminate demand-side management contract - - (1,702,678) Payment received related to terminate purchased power contract (Note 6) - 1,000,000 1,000,000 Deferred incremental Maine Yankee costs (Notes 1 and 10) (793,608) (718,877) - Deferred incremental ice storm costs (Note 12) (4,200,423) - - Deposit of Graham Station property sale proceeds with trustee (Note 11) (6,200,000) - - Deferred costs associated with generation asset sale (Note 10) (2,317,688) - - Deferred fuel revenue and Maine Yankee refueling costs (Note 1) (1,285,101) 1,172,497 514,464 Accounts receivable, net and unbilled revenue (1,423,947) 1,700,647 (2,872,894) Accounts payable 724,721 (261,642) 2,905,952 Accrued interest (192,272) (52,746) (1,188,433) Current and deferred income taxes 121,153 344,790 (722,833) Accrued postretirement benefit costs (Note 5) 600,699 547,237 1,411,000 Other current assets and liabilities, net (22,036) 906,745 (85,138) Other, net (Note 4) 2,786,259 (2,499,289) (1,744,820) - ------------------------------------------------------------------------------------------------------- Net Cash Provided By (Used In) Operations $ 30,931,960 $ 36,373,154 $ 44,841,549 - ------------------------------------------------------------------------------------------------------- Cash Flows From Investing: Construction expenditures $ (18,240,226)$ (17,525,312)$ (18,816,194) Allowance for borrowed funds used during construction (Note 1) (693,682) (562,966) (755,708) - ------------------------------------------------------------------------------------------------------- Net Cash (Used In) Provided By Investing $ ($18,933,908)$ ($18,088,278)$ ($19,571,902) - ------------------------------------------------------------------------------------------------------- Cash Flows From Financing: Dividends on preferred stock $ (1,216,434)$ (1,349,620)$ (1,481,020) Dividends on common stock - (1,325,416) (5,273,157) Payments on long-term debt (53,478,554) (15,853,515) (13,645,737) Payments on mandatory redeemable preferred stock (1,593,914) (1,593,915) (3,187,828) Issuances: Common stock dividend reinvestment plan (Note 3) - - 668,215 Long-term debt, net of capital reserve fund requirements (Note 4) 68,300,000 - - Short-term debt, net (Note 4) (22,000,000) 1,500,000 (2,500,000) - ------------------------------------------------------------------------------------------------------- Net Cash (Used In) Provided by Financing $ (9,988,902)$ (18,622,466)$ (25,419,527) - ------------------------------------------------------------------------------------------------------- Net Change in Cash and Cash Equivalents $ 2,009,150 $ (337,590)$ (149,880) Cash and Cash Equivalents - Beginning of Year 936,796 1,274,386 1,424,266 - ------------------------------------------------------------------------------------------------------- Cash and Cash Equivalents - End of Year $ 2,945,946 $ 936,796 $ 1,274,386 ======================================================================================================= The accompanying notes are an integral part of these consolidated financial statements.
Bangor Hydro-Electric Company CONSOLIDATED STATEMENTS OF COMMON STOCK INVESTMENT
Amounts Paid in Common Excess of Retained Total Common Stock Par Value Earnings Stock Investment BALANCE DECEMBER 31, 1995 $ 36,507,785 $ 56,610,548 $ 10,073,347 $ 103,191,680 Issuance of 61,867 shares of common stock 309,335 358,880 - 668,215 Net income - - 11,282,666 11,282,666 Cash dividends on- Preferred stock - - (1,448,170) (1,448,170) Common stock - $.72 per share - - (5,284,293) (5,284,293) Other (Note 3) - - (89,032) (89,032) ------------ ------------ ------------ --------------- BALANCE DECEMBER 31, 1996 $ 36,817,120 $ 56,969,428 $ 14,534,518 $ 108,321,066 Net loss - - (386,690) (386,690) Cash dividends declared on- Preferred stock - - (1,314,984) (1,314,984) Other (Note 3) - - (60,904) (60,904) ------------ ------------ ------------ --------------- 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 ============ ============ ============ =============== The accompanying notes are an integral part of these consolidated financial statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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 generation, purchase, transmission, distribution and sale 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 106,000 customers in portions of the Maine counties of Penobscot, Hancock, Washington, Waldo, Piscataquis, and Aroostook. The Company is subject to the regulatory authority of the Maine Public Utilities Commission (MPUC) as to retail rates, accounting, service standards, territory served, the issuance of securities and other matters. The Company is also subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC) as to certain matters, including licensing of its hydro-electric stations, rates for wholesale purchases and sales of energy and capacity and transmission services. The Company is a member of the New England Power Pool, and is interconnected with other New England utilities to the south and with New Brunswick Power Corporation to the north. BASIS OF CONSOLIDATION-The Consolidated Financial Statements of the Company include its wholly owned subsidiaries, Penobscot Hydro Co., Inc. (PHC), Bangor Var Co., Inc. (BVC), Bangor Energy Resale, Inc. (BERI), and Penobscot Natural Gas Co., Inc. (Penobscot Gas). The operations of PHC consist solely of a 50% interest in Bangor-Pacific Hydro Associates (Bangor-Pacific), the owner and operator of the redeveloped West Enfield hydroelectric station. PHC accounts for its investment in Bangor-Pacific under the equity method. BVC was incorporated in 1990 to own the Company's 50% interest in the Chester SVC Partnership (Chester), a partnership which owns certain facilities used in the Hydro-Quebec Phase II transmission project in which the Company is a participant. BVC accounts for its investment in Chester under the equity method. 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). The operations of Penobscot Gas consist solely of a 50% interest in Bangor Gas Company, LLC, which is developing a natural gas local distribution company in the greater Bangor, Maine area. See Note 6 for additional information with respect to these investments. All 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 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. ACCOUNTING FOR DEFERRED MAINE YANKEE REFUELING COSTS-Prior to the receipt of the most recent rate order from the MPUC (see Note 11), the Company was allowed to defer Maine Yankee refueling costs and amortize these costs over the period of Maine Yankee's refueling cycle. The unamortized refueling costs are presented on the Consolidated Balance Sheets as Deferred Maine Yankee Refueling Costs. With the previously mentioned rate order, the Company was not allowed recovery, in its new rates effective February 13, 1998, of the deferred Maine Yankee Refueling Costs. Consequently the Company charged to operations $1.9 million of such unrecoverable costs at December 31, 1997. 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 overaccumulated depreciation (discussed below), was approximately 2.5% in 1998, 3.0% in 1997, and 2.4% in 1996. 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 $1.6 million in amortization in 1998 which reduced depreciation expense. A similar study conducted in 1989 determined the Company's reserve for depreciation was over-accumulated by $11.4 million. The agreement on base rates with the MPUC which became effective on October 1, 1990, contained a provision to amortize the remaining balance of the over-accumulated reserve for depreciation account over a six-year period. This amortization ended in 1996. 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 $7.0 million in 1998, $5.7 million in 1997 and $6.5 million in 1996. EQUITY RESERVE FOR LICENSED HYDRO PROJECTS-The FERC requires that a reserve be maintained equal to one-half of the earnings in excess of a prescribed rate of return on the Company's investment in licensed hydro property, beginning with the twenty-first year of the project operation under license. The required reserve for licensed hydro projects is classified in retained earnings and had a balance of approximately $3 million and $1.9 million at December 31, 1998 and 1997, respectively. ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFDC)-In accordance with regulatory requirements of the MPUC, the Company capitalizes as AFDC financing costs related to portions of its construction work in progress, at a rate equal to its weighted cost of capital, into utility plant with offsetting credits to other income and interest. This cost is not an item of current cash income, but is recovered over the service life of plant in the form of increased revenue collected as a result of higher depreciation expense and return. In addition, carrying costs on certain regulatory assets were also capitalized in 1998 and included in AFDC in the Consolidated Statements of Income. The average AFDC (carrying costs) rates computed by the Company were 9.1% in 1998, 8.7% for 1997 and 8.6% in 1997. 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 $23.8 million, $24.6 million and $26.7 million in 1998, 1997 and 1996, respectively. Cash paid for income taxes was approximately $655,000, $545,000 and $2.3 million in 1998, 1997 and 1996, respectively. Noncash 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 exposures are changing interest rates and changes in purchased energy prices. 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 combination of both fixed and variable rate debt instruments and derivative financial instruments, including an interest rate swap and interest rate caps (see Notes 4 and 13). The Company manages purchased energy price risk through the use of swaps (see Note 13). 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 1998 Consolidated Financial Statements. 2. INCOME TAXES In accordance with Statement of Financial Accounting Standards No. 109 "Accounting for Income Taxes" (FAS 109), the Company recorded net additional deferred income tax liabilities of approximately $23 million as of December 31, 1998 and $22.1 million as of December 31, 1997. 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 ($32.6 million and $32.1 million as of December 31, 1998 and 1997, 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 ($8.6 million and $8.8 million as of December 31, 1998 and 1997, respectively), and the establishment of deferred tax assets on unamortized investment tax credits ($1.0 million as of December 31, 1998 and $1.2 million as of December 31, 1997). These latter amounts have been recorded as deferred regulatory liabilities at December 31, 1998 and 1997. 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, 1998 and 1997: 1998 1997 - ------------------------------------------------------------------------------- Deferred Income Tax Liabilities: Excess book over tax basis of electric plant in service $ 53,209,720 $ 51,559,302 Costs to terminate purchased power contracts 50,851,911 58,026,033 Deferred incremental ice storm costs 2,119,432 - Investment in jointly owned companies 2,036,802 1,405,388 Deferred incremental Maine Yankee costs 697,692 293,302 Deferred demand-side management costs 318,927 685,447 Other 287,215 407,745 - ------------------------------------------------------------------------------- $109,521,699 $112,377,217 - ------------------------------------------------------------------------------- Deferred Income Tax Assets: Net operating loss carryforward $ 27,159,196 $ 39,757,653 Deferred taxes provided on alternative minimum tax 7,314,289 6,447,244 Deferred state income tax benefit 2,881,091 1,987,659 Reserve for Basin Mills investment 2,835,939 2,825,592 Postretirement benefit costs other than pensions 2,362,537 2,122,130 Unamortized investment tax credit 1,017,397 1,160,073 Reserve for bad debts 719,981 873,007 Accrued pension costs 324,064 458,869 Other 1,132,700 886,338 - ------------------------------------------------------------------------------- $ 45,747,194 $ 56,518,565 - ------------------------------------------------------------------------------- Total other accumulated deferred income taxes $ 63,774,505 $ 55,858,652 =============================================================================== The individual components of federal and state income taxes reflected in the Consolidated Statements of Income for 1998, 1997 and 1996 are stated in the table below. Year Ended December 31, - ----------------------------------------------------------------------- 1998 1997 1996 ---------- ----------- --------- Current: Federal $ 725,466 $ 524,373 $ 1,804,206 State 195,876 141,581 526,576 - ----------------------------------------------------------------------- $ 921,342 $ 665,954 $ 2,330,782 - ----------------------------------------------------------------------- Deferred: Federal-Other $ 5,089,469 $ (661,330) $ 4,034,809 State-Other 1,442,801 (690,829) 861,136 Federal-Seabrook (341,917) (341,917) (331,076) State-Seabrook (72,173) (72,173) (69,379) - ----------------------------------------------------------------------- $ 6,118,180 $(1,766,249) $ 4,495,490 - ----------------------------------------------------------------------- Investment Tax Credits, Net $ (385,805) $ (140,379) $(1,122,798) - ----------------------------------------------------------------------- Total Provision $ 6,653,717 $(1,240,674) $ 5,703,474 Allocated to Other Income (560,431) (715,629) (821,021) - ----------------------------------------------------------------------- Charged to Operating Expense $6,093,286 $(1,956,303) $ 4,882,453 ======================================================================= The table below reconciles an income tax provision (benefit), calculated by multiplying income (loss) 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 (benefit) 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. 1998 1997 1996 - ----------------------------------------------------------------------- Amount % Amount % Amount % ------------------------------------------- (Dollars in Thousands) ------------------------------------------- Federal income tax provision at statutory rate $6,342 35.0% $(569) 35.0% $5,860 34.5% Less (Plus) permanent reductions in tax expense resulting from statutory exclusions from taxable income: Dividend received deduction related to earnings of associated companies 40 .2 29 (1.8) 116 .7 Equity component of AFDC 151 .8 100 (6.2) 127 .8 Amortization of equity component of AFDC on recoverable Seabrook investment (160) (.9) (160) 9.8 (157) (.9) Other (28) (.1) (80) 5.1 (68) (.5) - ------------------------------------------------------------------------- Federal income tax provision before effect of timing differences $6,339 35.0 $(458) 28.1% $5,842 34.4% 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) 9.3 (149) (.9) Book depreciation greater than tax depreciation (88) (.5) (79) 4.8 (90) (.5) Equity earnings in excess of dividends 201 1.1 217 (13.3) (6) - State income tax liability deducted for federal income tax purposes 498 2.8 (186) 11.4 314 1.9 Reversal of excess deferred income taxes 124 .7 173 (10.6) 101 .6 Amortization of investment tax credits 241 1.3 217 (13.3) 175 1.0 Investment tax credits flowed through - - (184) 11.3 540 3.2 Other 282 1.5 46 (2.9) 164 .9 - ---------------------------------------------------------------------------- Federal income tax provision $5,232 28.9% $(511) 31.4 $4,793 28.2% ============================================================================ 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 1998 the Company recorded $144,499 of state of Maine ITC and $213,322 of amortization of deferred ITC. In 1997 the Company recorded $108,140 of state of Maine ITC and $216,574 of amortization of deferred ITC. Income tax expense in 1997 was increased by $184,000 in ITC recorded in 1996 for financial reporting purposes, which were subsequently unable to be utilized when the 1996 federal income tax return was filed in 1997. In 1996 the Company recorded the utilization of approximately $540,000 of ITC, which were utilized to reduce income taxes payable upon an Internal Revenue Service (IRS) examination of the Company's 1993 and 1994 federal income tax returns and to reduce federal alternative minimum income taxes, which were flowed- through for financial reporting purposes as a reduction of income tax expense. The Company in 1996 also recorded $407,000 of state of Maine ITC and $175,000 of amortization of deferred ITC. ITC available of about $3.2 million ($2.2 million which is attributable to PHC and $955,000 to BVC) have not been utilized or recorded and, subject to review by the IRS, may be used prior to their expiration, which occurs between 2001 and 2005. At December 31, 1998, the Company had federal and state alternative minimum tax credits of approximately $7.3 million for the reduction of future tax liabilities. In 1998, 1997 and 1996 the Company utilized approximately $31.9 million, $21.5 million and $32.6 million, respectively, of tax net operating loss carryforwards to reduce its regular income tax liability. At December 31, 1998, the Company had, for income tax reporting purposes, approximately $66.6 million of tax net operating loss carryforwards that expire in 2010. These net operating losses were principally due to the Company deducting for income tax reporting purposes the costs of the purchased power contract terminations in 1995, which were deferred for financial reporting purposes (see Note 6). 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 462,660 (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. Except for the holders of the 8.76% issue, which does not carry general voting rights, the currently outstanding preferred stock has general voting rights of one vote per share. With regard to payment of dividends or assets available in the event of liquidation, preferred stock ranks prior to common stock. REDEEMABLE PREFERRED SHARES-December 27, 1989, the Company issued to an institutional investor $15 million of nonvoting preferred stock carrying an annual dividend rate of 8.76%. These shares have a maturity of fifteen years with a mandatory sinking fund of $1.5 million per year starting in 1995. The agreement to issue this series of preferred stock contains a provision where- by, if the Company pays a dividend that is considered a return of capital for federal income tax purposes, the Company is required to make a payment (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, pending any review by the IRS (for 1995 only), 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. This obligation is being recognized over the remaining life of the issue through a direct charge to retained earnings, which amounted to approximately $61,000 in each of 1998 and 1997. In each of 1998 and 1997 the Company made $1.5 million sinking fund payments, as well as approximately $94,000 under the make whole provision. EARNINGS PER SHARE-The following table reconciles basic and diluted earnings per common share assuming all common stock warrants (see Note 6 for discussion of warrants issued in connection with the PERC purchased power contract restructuring) were converted to common shares in accordance with Statement of Financial Accounting Standards No. 128, "Earnings per Share": 1998 1997 1996 - --------------------------------------------------------------------------- Earnings (loss) applicable to common stock $10,220,829 $(1,762,578) $9,745,464 - --------------------------------------------------------------------------- Average common shares outstanding 7,363,424 7,363,424 7,336,174 Plus: incremental shares from assumed conversion of warrants 329,778 - - - --------------------------------------------------------------------------- Average common shares outstanding plus assumed warrants converted 7,693,202 7,363,424 7,336,174 - --------------------------------------------------------------------------- Basic earnings (loss) per common share $ 1.39 $ (0.24) $ 1.33 =========================================================================== Diluted earnings (loss) per common share $ 1.33 $ (0.24) $ 1.33 =========================================================================== 4. LENDING AGREEMENTS AND MONETIZATION OF POWER SALE CONTRACT As previously reported, during 1997 the Company negotiated amendments to the credit agreement with its lending banks in order to resolve potential violations of certain financial covenants. As a result of those amendments, the Company reported that during 1998 or beyond, future cash needs might exceed the borrowing capacity under the credit facility, and accordingly, the Company might be required to find new sources of financing. 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. Amounts outstanding under the existing credit agreement, including $11 million of notes payable and $30 million of medium term notes, were fully repaid upon the execution of the amended credit agreement. The amended credit agreement is secured by $82.5 million of non-interest bearing First Mortgage Bonds. The revolving credit portion of the new 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 new term loan is the earlier of two years or when the Company completes any portion of its generation asset sale (see Note 10). In addition, the medium term notes require principal payments of $3 million each on September 30, 1999, December 31, 1999 and March 31, 2000. Interest on the term loans is determined similarly to the revolving credit portion of the new credit agreement but with a different risk premium. 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 financial covenants which are not significantly different than the covenants contained in the previous credit agreement. The Company was in compliance with all covenants associated with the new credit agreement during 1998. The credit agreement also provided for the issuance of a letter of credit required to support $4.2 million of the Company's Pollution Control Revenue Bonds. To secure the existing letter of credit related to the Pollution Control Revenue Bonds, until the new letter of credit could be issued, the Company deposited approximately $4.6 million of the proceeds from this financing with a third party trustee. The new letter of credit was issued in October 1998, and the $4.6 million deposited with the third party trustee was released to the Company. These funds were utilized to repay amounts outstanding under the Company's revolving credit facility. As reported in the 1997 Form 10-K, the Company had been negotiating a transaction for the monetization of a power sale contract with UNITIL Power Corp. (UNITIL), a New Hampshire based electric utility. The Company provided power directly to UNITIL at significantly above-market rates, with the contract term ending in the year 2003. On March 31, 1998, the Company completed a transaction with a financial institution and one of its wholly owned subsidiaries, Bangor Energy Resale, Inc. (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 is 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 U.S. Treasury and Agency obligations, repurchase agreements and short-term bank and corporate obligations. 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 banks reported "base rate" and (b) one-half of one percent (1/2%) above the federal funds effective interest rate. Also in connection with the loan agreement, BERI was required to purchase an interest rate cap or swap to provide interest rate protection through the maturity date of the term loan. This was accomplished in April 1998, when BERI entered into an interest rate swap agreement with the same financial institution. The interest rate swap fixed the LIBO interest rate on the medium term notes at 5.72%. The agreement also contains certain financial covenants. BERI was in compliance with all financial covenants during 1998. Also as previously reported, beginning in early 1997, the Company failed to comply with certain financial covenants under its bank lending agreements and received temporary waivers from the lending banks. By using a portion of the proceeds of the UNITIL monetization to pay down a portion of the bank obligations, the Company was able to negotiate permanent waivers of the earlier financial covenant violations. At the time the Company filed its 1997 Form 10-K, the monetization of the UNITIL contract had not been completed and the financial covenant violations had, therefore, not been waived permanently. As discussed in the 1997 Form 10-K, all debt under the bank credit facilities, including certain medium term notes, was classified as a current liability on the Company's Consolidated Balance Sheets as of December 31, 1997. As a result of the permanent waivers that became effective upon completion of the UNITIL monetization, $22 million of medium term notes, previously classified as a current liability, were reclassified as a long-term liability as of March 31, 1998. 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 beginning on July 1, 1998. The amount held in the capital reserve fund will be used to pay the final installments of principal and interest due in 2005. The assets in the capital reserve fund are held by a third party trustee and invested in a guaranteed 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. In August 1995, the Company entered into agreements with three banks to cap the LIBO rate on the $60 million term loan at 7.25%, with the cost to cap the interest rate amounting to $624,000. In 1998 the Company prepaid the remaining outstanding balance of the $60 million term loan, but the interest rate cap remains in place because the benefits of the cap are also applicable to the new $45 million term loan. The interest rate cap costs are continuing to be amortized over the life of the $60 million term loan, which matched the term of the interest rate cap. Certain information related to total short-term borrowings under the Credit Agreements and the lines of credit is as follows: 1998 1997 1996 - -------------------------------------------------------------------- Total credit available at end of period $30,000,000 $54,000,000 $54,000,000 Letter of credit secured under the revolving credit facility $ 4,200,000 $ 4,200,000 $ 4,200,000 Unused credit at end of period $13,800,000 $15,800,000 $17,300,000 Borrowings outstanding at end of period $12,000,000 $34,000,000 $32,500,000 Effective interest rate 7.2% 8.3% 7.7% (exclusive of fees) on borrowings outstanding at end of period Average daily outstanding borrowings for the period $20,369,863 $31,236,301 $33,609,973 Weighted daily average annual interest rate 7.9% 8.1% 7.6% Highest level of borrowings outstanding at any month-end during the period $37,500,000 $36,500,000 $41,500,000 ===================================================================== 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. Sinking fund requirements and current maturities of the first mortgage bonds and other long-term debt for the five years subsequent to December 31, 1998 are: Sinking Fund Requirements Current Maturities Total - --------------------------------------------------------------------------- 1999 $1,675,205 $ 23,840,000 $ 25,515,205 2000 1,886,702 58,460,000 60,346,702 2001 180,990 21,340,000 21,520,990 2002 - 41,560,000 41,560,000 2003 - 32,200,000 32,200,000 - --------------------------------------------------------------------------- $3,742,897 $177,400,000 $181,142,897 - --------------------------------------------------------------------------- 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 following tables detail the components of pension expense for 1998, 1997 and 1996, the funded status of the plan, the amounts recognized in the Company's Consolidated Financial Statements and the major assumptions used to determine these amounts. There were no employer contributions to the plan in 1998, 1997 or 1996. The plan's assets are composed of fixed income securities, equity securities and cash equivalents. Total pension expense included the following components: 1998 1997 1996 ----------------------------------------------------------------------------- Service cost-benefits earned during the period $ 1,190,152 $ 1,046,466 $ 991,569 Interest cost on projected benefit obligation 3,058,307 2,861,434 2,781,366 Expected return on plan assets (3,737,267) (3,513,402) (3,382,910) Total of amortized obligations and the net gain (loss) deferred (375,946) (375,946) (375,946) - ------------------------------------------------------------------------------- Total pension expense $ 135,246 $ 18,552 $ 14,079 =============================================================================== 1998 1997 1996 - ------------------------------------------------------------------------------- Significant assumptions used were- Discount rate 7.0% 7.5% 7.25% Rate of increase in future compensation levels 4.0% 5.0% 5.0% Expected long-term rate of return on plan assets 9.0% 9.0% 9.0% - ------------------------------------------------------------------------------- The following table sets forth the plan's funded status at December 31, 1998 and 1997: 1998 1997 - ------------------------------------------------------------------------------- Change in Projected Benefit Obligation Balance as of December 31, 1997 and 1996 $ 44,557,086 $ 39,369,783 Service cost 1,190,152 1,046,466 Interest cost 3,058,307 2,861,434 Benefits paid (3,069,692) (3,064,931) Gains and losses 1,709,136 4,344,334 - ------------------------------------------------------------------------------- Balance as of December 31, 1998 and 1997 $ 47,444,989 $ 44,557,086 - ------------------------------------------------------------------------------- Change in Plan Assets Balance as of December 31, 1997 and 1996 $ 48,323,318 $ 44,143,680 Benefits paid (3,069,692) (3,064,931) Actual return 3,114,389 7,244,569 - ------------------------------------------------------------------------------- Balance as of December 31, 1998 and 1997 $ 48,368,015 $ 48,323,318 - ------------------------------------------------------------------------------- Funded Status $ 923,026 $ 3,766,232 Unrecognized net transition asset (2,254,825) (3,187,150) Unrecognized prior service cost 3,427,646 3,984,025 Unrecognized gain (2,889,973) (5,221,987) - ------------------------------------------------------------------------------- Accrued pension balance at December 31, 1998 and 1997$ (794,126)$ (658,880) =============================================================================== The discount rate and rate of increase in future compensation levels used to determine pension obligations, effective January 1, 1999, are 6.75% and 4%, respectively, and were used to calculate the plan's funded status at December 31, 1998. At December 31, 1997, the Company changed to the 83-Group Annuity Mortality Table to calculate the plan's funded status. 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 Post- retirement Benefits Other Than Pensions" (FAS 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 FAS 106 over the pay-as-you-go amount in 1993 through February 28, 1994, and to include such excess as a regulatory asset pending inclusion in the new base rates, effective March 1, 1994. This regulatory asset, which amounted to $705,283 at February 28, 1994, is being recovered, beginning March 1, 1994, over a ten-year period. The Company, also in accordance with the final accounting ruling, is amortizing the unrecognized transition obligation of $10,023,200 over a 20-year period. In 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 $1.3 million in 1998, $1.1 million in 1997 and $490,000 in 1996. 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 1998, 1997 and 1996 and the major assumptions used to determine these amounts are shown in the following tables: 1998 1997 1996 - ------------------------------------------------------------------------------- Service cost of benefits earned $ 401,856 $ 342,739 $ 326,809 Interest cost on accumulated postretirement benefit obligation 1,060,671 994,936 928,423 Actual return on plan assets (10,608) (9,395) (21,000) Amortization of unrecognized transition obligation 501,200 501,200 501,200 Other deferrals, net (14,392) (11,605) - - ------------------------------------------------------------------------------- Net periodic postretirement benefit cost $ 1,938,727 $ 1,817,875 $ 1,735,432 =============================================================================== 1998 1997 1996 - ------------------------------------------------------------------------------- Significant assumptions used were- Discount rate 7.0% 7.5% 7.25% Health care cost trend rate, employees less than age 65- Near-term 8.0% 8.5% 9.0% Long-term 5.0% 4.5% 4.5% Health care cost trend rate, employees greater than age 65- Near-term 8.0% 6.8% 7.0% Long-term 5.0% 4.5% 4.5% Rate of return on plan assets 5.0% 5.0% 5.0% - ------------------------------------------------------------------------------- The following table sets forth the benefit plan's funded status at December 31, 1998 and 1997: 1998 1997 - ------------------------------------------------------------------------------- Change in Accumulated Postretirement Benefit Obligation Balance as of December 31, 1997 and 1996 $ 16,234,790 $ 13,238,720 Service cost 401,856 342,739 Interest cost 1,060,671 994,936 Claims paid (1,292,715) (1,052,060) Gains and losses 2,669,027 2,710,455 - ------------------------------------------------------------------------------- Balance as of December 31, 1998 and 1997 $ 19,073,629 $ 16,234,790 - ------------------------------------------------------------------------------- Change in Plan Assets Balance as of December 31, 1997 and 1996 $ 283,731 $ 240,878 Employer contributions 1,338,027 1,105,122 Retiree contributions 45,757 42,259 Claims paid (1,292,715) (1,052,060) Actual return, less expenses (53,392) (52,468) - ------------------------------------------------------------------------------- Balance as of December 31, 1998 and 1997 $ 321,408 $ 283,731 - ------------------------------------------------------------------------------- Funded Status $ (18,752,221)$ (15,951,059) Unrecognized net transition obligation 7,016,000 7,517,200 Unrecognized loss 4,760,198 2,058,535 - ------------------------------------------------------------------------------- Accrued postretirement benefit cost balance at December 31, 1998 and 1997 $ (6,976,023)$ (6,375,324) =============================================================================== The discount rate used to determine postretirement benefit obligations, effective January 1, 1998, and the Plan's funded status at December 31, 1998, was 6.75%. At December 31, 1997, the Company changed to the 83-Group Annuity Mortality Table to calculate the plan's funded status. 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 $ 367,015 $ (282,659) Effect on postretirement benefit obiliation 3,432,472 (2,712,012) - ----------------------------------------------------------------------------- The estimates of the Company's accrued pension and postretirement benefit costs involve the utilization of significant assumptions. Any change in these assumptions could impact the liabilities in the near term. 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 $330,000 in 1998, $295,000 in 1997 and $290,000 in 1996. 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. 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 28 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 are also filed with the FERC. On November 6, 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 non-operating status of the Plant. By Order dated January 14, 1998, the FERC accepted Maine Yankee's new rates for filing, subject to refund after a minimum suspension period, and set Maine Yankee's Amendatory Agreements, rates, and issues concerning the prudence of the Plant shutdown decision for hearing. By Complaint dated December 9, 1997, the Maine Office of the Public Advocate (OPA) sought a FERC investigation of Maine Yankee's actions leading to the decision to shut down the Plant, including actions associated with the management and operation of Maine Yankee since 1993. The MPUC had initiated an investigation in Maine earlier, raising generally similar issues. By decision dated May 4, 1998, the FERC consolidated the OPA Complaint with the comprehensive rate proceeding. In addition, the Secondary Purchasers intervened in the FERC proceeding, raising similar prudence issues and other issues unique to their status as indirect purchasers from Maine Yankee. In support of its request for an increase in decommissioning collections, Maine Yankee submitted with its initial filing a 1997 decommissioning cost study performed by TLG Services, Inc. (TLG). During 1998, Maine Yankee engaged in an extensive competitive bid process to hire a Decommissioning Operations Contractor (DOC) to perform certain major decontamination and dismantlement activities at the Plant on a fixed-price, turnkey basis. As a result of that process, a consortium headed by Stone & Webster Engineering Corporation (Stone & Webster) was selected to perform such activities under a fixed-price contract. The contract provides for, among other undertakings, construction of an independent spent fuel storage installation (ISFSI) and completion of major decommissioning activities and site restoration by the end of 2004. The DOC process resulted in fixing certain costs that had been estimated in the earlier decommissioning cost estimate performed by TLG. Since the filing of the rate request, Maine Yankee and the active intervenors, including among others the MPUC Staff, the OPA, the Company and other owners, the Secondary Purchasers, and a Maine environmental group (the Settling Parties), engaged in extensive discovery. More recently, those parties participated in settlement discussions that resulted in an Offer of Settlement filed by those parties with the FERC on January 19, 1999, which, if approved by the FERC, would result in full settlement of all issues raised in the consolidated FERC proceeding, including decommissioning cost issues and issues pertaining to the prudence of the management, operation, and decision to permanently cease operation of, the Plant. Approval of the settlement would also resolve the issues raised by the Secondary Purchasers by limiting the amounts they will pay for decommissioning the Plant and by settling other points of contention affecting individual Secondary Purchasers. The Offer of Settlement provides for Maine Yankee to collect $33.6 million in the aggregate annually, effective January 15, 1998: (1) $26.8 million for estimated decommissioning costs, and (2) $6.8 million for ISFSI-related costs. The original filing with FERC on November 6, 1997 called for an aggregate annual collection rate of $36.4 million for decommissioning and the ISFSI, based on the TLG estimate. The amount collected annually could be reduced to approximately $26 million if Maine Yankee is able to (1) use in connection with the construction of the ISFSI funds held in trust under Maine law for spent-fuel disposal, and (2) access approximately $6.8 million being held by the state of Maine for eventual payment to the state of Texas pursuant to a compact for low-level nuclear waste disposal, the future of which is now in question after rejection of the selected disposal site in west Texas by a Texas regulatory agency. Both would require authorizing legislation in Maine, which Maine Yankee intends to pursue. The Offer of Settlement also provides for recovery of all unamortized investment (including fuel) in the Plant, together with a return on equity of 6.50%, effective January 15, 1998, on equity balances up to maximum allowed equity amounts. The Settling Parties also agreed in the proposed settlement 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. As a separate part of the Offer of Settlement, the Company, the other two Maine owners of Maine Yankee, the MPUC Staff, and the OPA entered into a further 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 Maine Agreement). Under the Maine Agreement, the Company would continue to recover its Maine Yankee costs in accordance with its most recent Alternative Rate Plan (ARP) order (see Note 10) from the MPUC without any adjustment reflecting the outcome of the FERC proceeding. To the extent that the Company has collected from its retail customers a return on equity in excess of the 6.50% contemplated by the Offer of Settlement, no refunds would be required, but such excess amounts would be credited to the customers to the extent required by the ARP. The final major provision of the Maine Agreement requires 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 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, up to a maximum cumulative amount of $41 million. The Company's share of that amount would be $5.74 million for the period. The Maine Agreement, which was approved by the MPUC on December 22, 1998, also sets forth the methodology for calculating such replacement power costs. The Company believes that the Offer of Settlement, including the Maine Agreement, constitutes a reasonable resolution of the issues raised in the Maine Yankee FERC proceeding, and that approval of the Offer of Settlement by the FERC would eliminate significant uncertainties concerning the Company's future financial performance. Although all of the active parties to the proceeding have agreed to support or, with respect to certain individual provisions, not oppose, the Offer of Settlement, the Company cannot predict with certainty whether or in what form it will be approved by the FERC. Summary Financial Information for Maine Yankee and MEPCO
- ------------------------------------------------------------------------------------------------------------------ Maine Yankee MEPCO - ------------------------------------------------------------------------------------------------------------------ (Dollars in Thousands) - ------------------------------------------------------------------------------------------------------------------ 1998 1997 1996 1998 1997 1996 ---------- ----------- ---------- --------- --------- --------- Operations: As reported by investee- Operating Revenue $ 110,608 $ 238,586 $ 185,661 $ 3,514 $ 24,473 $ 55,391 - ------------------------------------------------------------------------------------------------------------------ Depreciation & decommissioning collections $ 57,617 $ 33,625 $ 32,952 $ 364 $ 222 $ 845 Interest and Preferred Dividends 15,958 18,031 15,922 77 67 61 Other expenses, net 32,117 179,317 130,150 2,125 23,112 54,265 - ------------------------------------------------------------------------------------------------------------------ Operating expenses $ 105,692 $ 230,973 $ 179,024 $ 2,566 $ 23,401 $ 55,171 - ------------------------------------------------------------------------------------------------------------------ Earnings Applicable to Common Stock $ 4,916 $ 7,613 $ 6,637 $ 948 $ 1,072 $ 220 ================================================================================================================== Amounts Reported by the Company- Purchased power costs $ 7,185 $ 16,764 $ 12,839 $ - $ - $ - Equity in net income (215) (524) (449) (123) (15) (15) - ------------------------------------------------------------------------------------------------------------------ Net purchased power expense $ 6,970 $ 16,240 $ 12,390 $ (123) $ (15) $ (15) ================================================================================================================== Financial Position: As reported by investee- Plant in service $ 687 $ 687 $ 409,865 $ 23,633 $ 23,510 $ 23,146 Accumulated depreciation - - (225,735) (22,899) (22,618) (22,545) Other assets 1,182,611 1,367,456 417,931 4,781 3,470 10,126 - ------------------------------------------------------------------------------------------------------------------ Total assets $1,183,298 $ 1,368,143 $ 602,061 $ 5,515 $ 4,362 $ 10,727 Less- Preferred stock 16,800 17,400 18,000 - - - Long-term debt 68,433 143,665 103,332 220 420 620 Other liabilities and deferred credits 1,018,575 1,128,128 409,392 2,079 1,578 9,110 - ------------------------------------------------------------------------------------------------------------------ Net assets $ 79,490 $ 78,950 $ 71,337 $ 3,216 $ 2,364 $ 997 ================================================================================================================== Company's reported equity- Equity in net assets $ 5,564 $ 5,527 $ 4,994 $ 457 $ 336 $ 142 Adjust Company's estimated to actual (125) 5 20 (18) (10) (17) - ------------------------------------------------------------------------------------------------------------------ Equity in net assets as reported $ 5,439 $ 5,532 $ 5,014 $ 439 $ 326 $ 125 ==================================================================================================================
Maine Yankee's most recent estimate of the total costs of decommissioning and plant closure, excluding funds already collected, is $715.0 million (undiscounted). The Company's share of this estimated cost is $50.1 million and is recorded as a regulatory asset and decommissioning liability at December 31, 1998. The regulatory asset was recorded for the full amount of the decommissioning and plant closure costs due to the recent 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 most recent rate order (see Note 10) for Maine Yankee non-decommissioning plant closure costs. Accumulated decommissioning funds at December 31, 1998 had an adjusted market value of $212.7 million of which the Company's share was approximately $14.9 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 above. In connection with the Company's generation asset sale (see Note 10), the Company has reached an agreement to sell certain of its rights to MEPCO transmission capacity. Wyman 4-The Company owns 8.33% (50 MW) of the oil-fired 600 MW Wyman Unit No. 4 in Yarmouth, Maine. The Company's proportionate share of the direct expenses of this unit is included in the corresponding operating expenses in the Consolidated Statements of Income. See Note 10 for a discussion of an agreement to sell the Company's generating assets. Included in the Company's utility plant are the following amounts with respect to this unit: 1998 1997 1996 - ------------------------------------------------------------------------- Electric plant in service $ 16,887,608 $ 16,886,776 $ 16,885,690 Accumulated depreciation (9,851,639) (9,389,542) (8,927,440) - ------------------------------------------------------------------------- $ 7,035,969 $ 7,497,234 $ 7,958,250 ========================================================================= 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 Company's generation asset sale, an agreement has been reached to sell the Company's rights as a participant in the regional utilities agreement with Hydro-Quebec (see Note 10). 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 principal amount of additional notes due 2020 (collectively, the SVC Notes). The holders of the SVC Notes are without recourse against the partners or their parent companies and may only look to Chester and to the collateral for payment. The New England utilities which participate in Phase 2 have agreed under a FERC approved contract to bear the cost of Chester, on a cost of service basis, which includes a return on and of all capital costs. Information relating to the operations and financial position of Chester appears at the top of page 33. PENOBSCOT NATURAL GAS COMPANY-In 1998 the Company formed Penobscot Gas, whose sole function is 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, a joint venture of Pacific Enterprises and Enova Corporation, owns the other 50% interest in Bangor Gas. In the second quarter of 1998, Bangor Gas received unconditional authority from the MPUC to provide natural gas service to the greater Bangor area, and in October 1998 the Company received authorization from the MPUC to invest approximately $1.2 million in Bangor Gas. Gas service to Maine will be made economically feasible for the first time by the Maritimes and Northeast Pipeline Project, slated for completion in late 1999. The new pipeline will extend from the Sable Offshore Energy Project near Sable Island, Nova Scotia, through the state of Maine and interconnect with the Tennessee Gas Pipeline in Dracut, Massachusetts. The route, as proposed, comes near the Bangor area, providing an opportunity for retail gas distribution in the greater Bangor marketplace. Company officials estimate the cost to build and implement the new Bangor Gas system to be approximately $40 million. The Company is not obligated but has the opportunity to make material capital contributions to the joint-venture in the near term. Summary Financial Information for Bangor-Pacific and Chester
- ---------------------------------------------------------------------------------------------------------------- Bangor-Pacific Chester - ---------------------------------------------------------------------------------------------------------------- (Dollars in Thousands) - ---------------------------------------------------------------------------------------------------------------- 1998 1997 1996 1998 1997 1996 --------- --------- --------- --------- --------- --------- Operations: As reported by investee- Operating Revenue $ 7,309 $ 7,057 $ 8,252 $ 4,535 $ 4,642 $ 4,782 - ---------------------------------------------------------------------------------------------------------------- Depreciation $ 868 $ 870 $ 866 $ 1,075 $ 1,075 $ 1,075 Interest expense 3,082 3,294 3,501 2,737 2,859 2,988 Other expenses, net 890 911 832 723 708 719 - ---------------------------------------------------------------------------------------------------------------- Operating expenses $ 4,840 $ 5,075 $ 5,199 $ 4,535 $ 4,642 $ 4,782 - ---------------------------------------------------------------------------------------------------------------- Net Income $ 2,469 $ 1,982 $ 3,053 $ - $ - $ - ================================================================================================================ Company's reported equity in net income $ 1,235 $ 991 $ 1,527 $ - $ - $ - ================================================================================================================ Financial Position: As reported by investee- Plant in service $ 44,047 $ 44,047 $ 44,043 $ 31,993 $ 31,993 $ 31,993 Accumulated depreciation (9,031) (8,163) (7,293) (8,523) (7,447) (6,372) Other assets 3,308 3,129 3,114 3,008 3,087 3,277 - ---------------------------------------------------------------------------------------------------------------- Total assets $ 38,324 $ 39,013 $ 39,864 $ 26,478 $ 27,633 $ 28,898 Less- Long-term debt 26,300 28,500 30,600 24,654 25,837 27,021 Other liabilities 2,517 2,425 2,359 1,824 1,796 1,877 - ---------------------------------------------------------------------------------------------------------------- Net assets $ 9,507 $ 8,088 $ 6,905 $ - $ - $ - ================================================================================================================ Company's reported equity in net assets $ 4,754 $ 4,044 $ 3,453 $ - $ - $ - ================================================================================================================
At December 31, 1998, Penobscot Gas has approximately a $77,000 equity investment in Bangor Gas and recorded an equity loss in Bangor Gas of approximately $98,000 for the year ended December 31, 1998. At December 31, 1998, Bangor Gas' total assets, principally construction work in progress, amounted to $2.9 million. SMALL POWER PRODUCTION FACILITIES-As of the end of 1998, the Company had contracts with six independent, 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 has been attempting to alleviate the adverse impact of high-cost contracts with small power production facilities. One method for doing so has been to pay a fixed sum in return for terminating the contract. The first such transaction was accomplished in 1993, and in 1995 the Company succeeded in accomplishing two more. 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. 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 are 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. 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 latest 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. The 1995 transactions involved a "buyback" of the contracts for the purchase of power from two biomass-fueled generating plants in West Enfield and Jones- boro, Maine, which are identical plants under common ownership. The buyback cost was approximately $170 million, including transaction costs. Under the Company's Alternative Marketing Plan, the buyback costs were deferred and recorded as a regulatory asset, to be amortized and collected over a ten-year period, beginning July 1, 1995. The cost of the buy-back was financed entirely by new debt instruments, thereby significantly increasing the Com- pany's indebtedness. See Note 4 for discussion of these financings. In addition to the buyback costs incurred to date, the Company was committed under certain conditions to reimburse the towns of Enfield and Jonesboro for lost property tax revenues in an amount which was not expected to exceed $1.4 million over a two-year period. In 1997 and 1996 the Company made payments of approximately $1.5 million to the two towns under this commitment. As previously reported, the Company had been working to restructure a power purchase contract with the PERC, its last remaining high-priced non-utility generator contract that offered a potential for substantial savings. 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 under this contract was approximately $14.7 million in 1998 and is projected to be $15 million annually, net of revenues from the resale of power to another utility (these amounts are not reduced by the Company's pro rata share of PERC's net revenues discussed below). 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. 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 1998 the Company realized $2 million 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) Bangor Hydro 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) Bangor Hydro 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 Bangor Hydro common stock at a price of $7 per share. No warrants may be exercised within the first nine months after their issuance, and they become 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 would have 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. Depending upon a number of assumptions, including the ultimate cost of the warrants and markets for solid waste disposal, it is projected that the restructuring will result in cost savings to Bangor Hydro over the next twenty years with a net present value of $25-40 million. The anticipated savings resulting from this transaction were used to reduce the level of electric rates approved by the MPUC in the Company's recent general rate case by approximately $2.4 million on an annual basis. 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. The Company has deferred, as a regulatory asset, the $6.25 million in payments to PERC, approximately $1.5 million in costs associated with the contract restructuring, and $2 million for the estimated fair value of the warrants. As discussed above, the Company is currently recovering PERC restructuring costs in rates. The $2 million in warrants have also increased additional paid-in capital on the Consolidated Balance Sheets. 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. Except as described below, the holders of the notes issued by Bangor-Pacific are without recourse to the joint venture partners or their parent companies. In the event Bangor-Pacific fails to pay when due amounts payable pursuant to the loan agreement, each partner has agreed to make capital contributions to Bangor-Pacific in an amount equal to 50% of such amounts due and payable, but not exceeding an amount equal to distributions from Bangor-Pacific received by such partner in the preceding twelve-month period. The Company is obliged to provide funds necessary to support the foregoing limited financial commitment to the project undertaken by PHC as the partner. Under the purchased power contract, if the project operates as anticipated, payments by the Company to Bangor-Pacific are estimated to be about $7.5 million annually (without consideration of any distributions by the joint venture to the partners). It is possible that the Company would be required to make payments under the contract regardless of whether any power is delivered, in an amount of approximately $4 million per year. However, the Company has the right to terminate the contract if the failure to deliver power continues for a period of twelve consecutive months. Information relating to the operations and financial position of Bangor-Pacific appears at the top of page 33. In connection with the Company's generation asset sale (see Note 10), an agreement has been reached to sell PHC's ownership interest in Bangor-Pacific. OTHER POWER SUPPLY COMMITMENTS-The Company has a contract, which started in June 1997, for the delivery of up to 60 MW of power from another utility, ending February 29, 2000. This contract is directly tied to the price of oil and the Company has hedged this purchase through its energy risk management program (see Note 13 for a discussion of the Company's fuel hedge program). The Company's purchased power expense (including hedge settlements) under this contract was approximately $13.4 million in 1998 and is projected to be approximately $13.3 million in 1999. The Company has also entered into a new 40 MW purchase power contract tied directly to the price of oil. The term of this contract is January 1, 1999 through February 29, 2000. The Company has also hedged this purchase through its energy risk management program and expects the purchased power expense to be approximately $8.3 million in 1999. BASIN MILLS AND VEAZIE PROJECTS-As a result of increased uncertainty about the recoverability of amounts invested through 1993 in licensing activities for proposed additional hydroelectric facilities, the Company established a reserve against those investments in the amount of $8.7 million as of December 31, 1993. Since 1993 the Company has charged to non-operating expense all amounts related to these licensing activities. The projects for which the reserve was established are a proposed 38 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 is included in the assets to be sold as part of its generation asset sale. 7. RECOVERY OF SEABROOK INVESTMENT AND SALE OF SEABROOK INTEREST The Company was a participant in the Seabrook nuclear project in Seabrook, New Hampshire. On December 31, 1984, the Company had almost $87 million invested in Seabrook, but because the uncertainties arising out of the Seabrook Project were having an adverse impact on the Company's financial condition, an agreement for the sale of Seabrook was reached in mid-1985 and was finally consummated in November 1986. During 1985, a comprehensive agreement was negotiated among the Company, the MPUC staff, and the Maine Public Advocate addressing the recovery through rates of the Company's investment in Seabrook (the Seabrook Stipulation). This negotiated agreement was approved by the MPUC in late 1985. Although the implementation of the Seabrook Stipulation significantly improved the Company's financial condition, substantial write-offs were required as a result of the determination that a portion of the Company's investment in Seabrook would not be recovered. In addition to the disallowance of certain Seabrook costs, the Seabrook Stipulation also provided for the recovery through customer rates of 70% of the Company's year-end 1984 investment in Seabrook Unit 1 over 30 years, and 60% of the Company's investment in Unit 2 over seven years, with base rate treatment on the unamortized balances. As of December 31, 1992, the Company's investment in Seabrook Unit 2 was fully amortized. 8. UNAUDITED QUARTERLY FINANCIAL DATA Unaudited quarterly financial data pertaining to the results of operations are shown below: Quarter Ended ------------------------------------------ Mar. 31 June 30 Sept. 30 Dec. 31 ------------------------------------------ (DOLLARS IN THOUSANDS EXCEPT PER SHARE AMOUNTS) 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 ============================================================================ 1997 - ---------------------------------- Electric Operating Revenue $ 48,176 $ 42,236 $ 47,557 $ 49,356 Operating Income 6,657 4,896 5,902 6,334 Net Income (Loss) 716 (1,037) (188) 122 Basic Earnings (Loss) Per Share of Common Stock $ .05 $ (.19) $ (.07) $ (.03) ============================================================================ 1996 - ---------------------------------- Electric Operating Revenue $ 48,161 $ 43,152 $ 47,355 $ 48,706 Operating Income 10,454 9,036 8,417 8,334 Net Income 4,095 2,758 2,295 2,135 Basic Earnings Per Share of Common Stock $ .51 $ .32 $ .26 $ .24 ============================================================================ 9. FAIR VALUE OF FINANCIAL INSTRUMENTS The following methods and assumptions were used to estimate the fair value at December 31, 1998 of each class of financial instrument for which it is practical to estimate the value: Cash and cash equivalents: the carrying amount of $2,945,946 approximates fair value. Funds held by trustee-money market funds and U.S. Treasury Bills: the carrying amount of $8,675,668 approximates fair value. The fair values of other financial instruments at December 31, 1998 based upon similar issuances of comparable companies are as follows: In Thousands - ------------------------------------------------------------------------ Carrying Amount Fair Value ------------------------------ Funds held by trustee-guaranteed investment contract $ 21,192 $ 19,825 Mandatory redeemable cumulative preferred stock 9,198 8,922 First Mortgage Bonds 103,743 110,607 Pollution Control Revenue Bonds 4,200 4,200 FAME Revenue Notes 113,700 120,280 Medium Term Notes-LIBO rate plus 2% 45,000 45,000 Medium Term Notes-LIBO rate plus 1.125% 21,900 21,900 - ------------------------------------------------------------------------- 10. INDUSTRY RESTRUCTURING AND RATE REGULATION INDUSTRY RESTRUCTURING-In the Company's 1996 and 1997 Form 10-K's, the Company described electric utility restructuring efforts in Maine, including the MPUC's recommendation to the legislature. After months of hearings and deliberations, the Maine legislature passed L.D. 1804, "An Act to Restructure the State's Electric Industry", which the Governor signed into law on May 29, 1997. The principal provisions of the new law are as follows: 1) Beginning on March 1, 2000, all consumers of electricity have the right to purchase generation services directly from competitive electricity suppliers who will not be subject to rate regulation. 2) By March 1, 2000, the Company must divest of all generation related assets and business functions except for: a) contracts with qualifying facilities and conservation providers; b) nuclear assets, namely, the Company's investment in Maine Yankee, however, the MPUC may require divestiture on or after January 1, 2009; c) assets that the MPUC determines necessary for the operation of the transmission and distribution services. The MPUC may grant an extension of the divestiture deadline if the extension will improve the selling price. For assets not divested, the utilities are required to sell the rights to the energy and capacity from these assets. The Company shall submit to the MPUC its divestiture plan no later than January 1, 1999. 3) Billing and metering services will be subject to competition beginning March 1, 2002, but the legislation permits the MPUC to establish an earlier date, no sooner than March 1, 2000. 4) The Company, through an unregulated affiliate, may market and sell electricity both within and outside its current service territory, limited to 33% of the load within the Company's service territory and unlimited outside the Company's service territory. 5) The Company will continue to provide transmission and distribution services which will be subject to continued regulation by the MPUC. 6) If after March 1, 2000, 10% or more of the stock of a regulated distribution utility is purchased by an entity, the purchasing entity and any related entity may not sell or offer for sale generation service to any retail customer of electric energy in the state of Maine. 7) Maine electric utilities will be permitted a reasonable opportunity to recover legitimate, verifiable and unmitigable costs that are otherwise unrecoverable as a result of retail competition in the electric utility industry. The MPUC shall determine these stranded costs by considering: a) the utility's regulatory assets related to generation; b) the difference between net plant investment in generation assets compared to the market value for those assets; and c) the difference between future contract payments and the market value of the purchased power contracts. The Company shall pursue all reasonable means to reduce its potential stranded costs and to receive the highest possible value for generation assets and contracts, including the exploration of all reasonable and lawful opportunities to reduce the cost to ratepayers of contracts with qualifying facilities. By July 1, 1999, the MPUC will have estimated the stranded costs for the Company and the manner for the collection of these costs by the transmission and distribution company. Customers reducing or eliminating their consumption of electricity by switching to self-generation, conversion to alternative fuels or utilizing demand-side management measures cannot be assessed exit or entry fees. The MPUC shall include in the rates charged by the transmission and distribution utility decommissioning expenses for Maine Yankee. In 2003 and every three years thereafter until the stranded costs are recovered, the MPUC shall review and reevaluate the stranded cost recovery. 8) All competitive providers of retail electricity must be licensed and registered with the MPUC and meet certain financial standards, comply with customer notification requirements, adhere to customer solicitation requirements and are subject to unfair trade practice laws. Competitive electricity providers must have at least 30% renewable resources (which include hydroelectric generation) in their energy portfolios. 9) A standard-offer service will be available for all customers. An unregulated affiliate of the Company providing retail electric power is prohibited from providing more than 20% of the load within the Company's service territory under the standard offer service. 10) An unregulated affiliate of the Company marketing and selling retail electric power must adhere to specific codes of conduct, including, among others: a) employees of the unregulated affiliate providing retail electric power must be physically separated from the regulated distribution affiliate and cannot be shared; b) the regulated distribution affiliate must provide equal access to customer information; c) the regulated distribution company cannot participate in joint advertising or marketing programs with the unregulated affiliate providing retail electric power; d) the distribution company and its unregulated affiliated provider of retail electric power must keep separate books of accounts and records; and e) the distribution company cannot condition or tie the provision of any regulated service to the provision of any service provided by the unregulated affiliated provider of electricity. 11) Employees, other than officers, displaced as a result of retail competition will be entitled to certain severance benefits and retraining programs. These costs will be recovered through charges collected by the regulated distribution company. 12) Other provisions of the new law include provisions for: a) consumer education; b) continuation of low-income programs and demand-side management activities; c) consumer protection provisions; d) new enforcement authority for the MPUC to protect consumers. The MPUC is currently conducting several rulemaking proceedings associated with the new restructuring law. AGREEMENT ON SALE OF COMPANY'S GENERATING ASSETS-On September 25, 1998, the Company and PP&L Global, Inc., a Pennsylvania corporation and a subsidiary of PP&L Resources, Inc., reached an agreement for PP&L Global to acquire most of the Company's electric generating assets with a combined base load capacity of 89.2 megawatts and certain transmission rights for a sale price of $89 million. The proposed sale is a result of the Company's effort to comply with Maine's previously discussed electric utility restructuring legislation. The Company began seeking proposals from prospective bidders to purchase its generation and generation-related assets in early 1998 and as part of the auction process, received final bids from various bidders in August 1998. Pursuant to the agreement, the Company has agreed to sell to PP&L Global (i) its Ellsworth, Howland, Milford, Medway, Orono, Stillwater and Veazie hydroelectric facilities, which are all situated along the Penobscot River Basin and Union River in Maine, (ii) the 50% ownership interest owned by PHC in Bangor-Pacific, (iii) the Company's 8.33% joint ownership interest in the William F. Wyman Unit No. 4 oil-fired steam plant, (iv) the Company's designs, applications and other rights with respect to the potential development of the Basin Mills hydroelectric project, to be located in Bradley and Orono, Maine, (v) the Company's designs, applications and other rights with respect to the potential development of a high-voltage transmission line from Orrington, Maine, to New Brunswick, Canada, and (vi) certain of the Company's rights to transmission capacity, including its rights as a participant in the regional utilities' agreements with Hydro- Quebec. The sale is subject to certain closing conditions as set forth in the agreement, including receipt of approvals by federal and state regulatory agencies. The MPUC has already given approvals for the sale, and other outstanding governmental proceedings should be resolved within the next few months. In addition, third-party consents to the sale of certain of the assets will be required, and the Company cannot predict whether or on what terms such consents can be obtained. The Company anticipates that most of the net after-tax proceeds from the sale will be used to retire outstanding debt. The Company expects that a portion of the sale value will be applied to reduce the Company's stranded costs for regulatory purposes, which should lower the amounts that would otherwise be collected in the future from customers. REGULATORY PROCEEDINGS-On February 9, 1998, the MPUC issued its final order on the Company's request to increase its rates permanently. Of the approximately $22 million increase in annual revenue ultimately requested by the Company, the MPUC authorized an increase of approximately $13.2 million (which included a $5.1 million temporary rate increase in July 1997) annually. While there are many factors that explain the difference between the MPUC allowance and the Company's requested increase, much of that difference is attributable to the proposed accounting treatment of various costs and the deferral of other costs for future consideration, including the deferral of certain costs associated with the Company's ownership interest in the Maine Yankee nuclear power plant. While those accounting treatments have affected the timing of receipt of revenues by the Company and have required the Company to finance the payment of the associated costs, they did not significantly affect the Company's earnings in 1998. The MPUC order was based upon a determination that the Company should be allowed to earn an annual return of 12.75% on common equity. It also included a new rate plan, the Alternative Rate Plan, under which the Com- pany's rates are subject to certain reconciliations based upon actual expenditures by the Company and an annual adjustment beginning on May 1, 1999 to account for inflation with an offset for assumed increases in productivity. Other than those adjustments, the Company will not change its rates unless its return on equity exceeds or falls short of the allowed return by more than 350 basis points. If the Company's return on equity falls outside of that bandwidth, 50% of the excess or shortfall will be adjusted for in the Company's rates. In February 1999, the Company submitted its 1999 filing to the MPUC under the Alternative Rate Plan. If approved, the Company will implement a rate increase of approximately 2% effective May 1, 1999. The Company is not seeking an increase due to inflation. Rather, the entire amount of the increase is due to adjustments for specific cost items. The largest of these is for the recovery of the 1998 ice storm costs (see Note 12) at a rate of $1.46 million annually over a four-year period. The remainder of the request consists of adjustments for items contemplated in the MPUC's decision in the Company's last rate case, discussed above, but for which the amounts were not known at the time. As previously discussed, the 1997 Maine restructuring legislation requires the MPUC, when retail access begins, to provide a "reasonable opportunity" to recover stranded costs through the rates of the transmission and distribution (T&D) utility, comparable to the utility's opportunity to recover stranded costs before the implementation of retail access under the legislation. The principal restructuring provisions of the legislation provide for customers to have direct retail access to generation services and for deregulation of competitive electricity providers, commencing March 1, 2000, with T&D companies continuing to be regulated by the MPUC. The MPUC is conducting the proceeding that will ultimately determine the Company's stranded costs and corresponding revenue requirements, and has scheduled completion of the current phase of the proceeding for the second quarter of 1999. On July 24, 1998, the Company filed direct testimony in the proceeding estimating its future revenue requirements as a T&D utility and providing an estimate of its stranded costs, and rebuttal testimony was filed on November 25, 1998. The Company estimated its total stranded costs to be approximately $284 million, which includes the net present value of above-market purchased power obligations and has estimated its stranded cost revenue requirement to be approximately $40.6 million, annually starting March 1, 2000. The Company cannot predict the results of the MPUC proceeding, which is scheduled to conclude in May 1999, subject to later updating prior to March 1, 2000. The Company is also actively involved in numerous other MPUC rule-makings in connection with the various aspects of the introduction of retail competition. REGULATORY ASSETS AND MEETING THE REQUIREMENTS OF FAS 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" (FAS 71). FAS 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, 1998, the Company has regulatory assets, net of regulatory liabilities, of approximately $246.3 million. The Company continues to meet the requirements of FAS 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. If the Company is not 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 FAS 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 transmission and distribution company. The Company anticipates, based on current generally accepted accounting principles, that FAS 71 will continue to apply to the regulated transmission and distribution segments of its business. If the Company failed to meet the requirements of FAS 71, due to legislative or regulatory initiatives, the Company would be required to revert to Statement of Financial Accounting Standards No. 101, "Regulated Enterprises- Accounting for the Discontinuation of Application of FASB No. 71" (FAS 101). If, under FAS 101, legislative or regulatory changes and/or competition result in electric rates which do not fully recover the Company's costs, a write-down of assets could be required. The Company does not anticipate any write-down of assets at this time. 11. SALE OF PROPERTY AT GRAHAM STATION 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 property is to be utilized by Casco Bay Energy, which plans to construct a $221 million gas-fired power plant that will produce 520 MW's of electricity. The plant will be powered by the proposed Maritimes & Northeast gas transmission line and regional transmission system. The Company realized a net gain from the sale of $4.5 million, which has been deferred (reflected as a component of Other Deferred Credits on the Consolidated Balance Sheet at December 31, 1998) in anticipation that it will likely be utilized as a future reduction to the Company's recoverable stranded costs. 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 has been 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. 12. STORM DAMAGE As discussed in the 1997 Form 10-K, 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 has been deferred and included in Other Deferred Charges on the Company's Consolidated Balance Sheets 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 is seeking to begin recovery of those deferred costs on May 1, 1999 as part of its annual rate adjustment pursuant to its Alternative Rate Plan. 13. DERIVATIVE FINANCIAL INSTRUMENTS INTEREST RATE CAPS-As discussed in Note 4, the Company, in 1995, entered into interest rate cap agreements (the cap or caps) with three financial institutions related to its $60 million of medium term notes to manage its exposure to interest rate fluctuations. Under the caps, the LIBO rate was capped at 7.25% over the five-year term of the medium term notes for the full notional amount of $60 million. At the beginning of each calendar quarter the notional interest rate is set by the financial institutions based on the current LIBO rate. The Company will be reimbursed for incremental interest expense incurred in excess of the 7.25% cap. During 1998, 1997 and 1996 the notional rate was not in excess of 7.25%. In 1998 the Company prepaid the remaining outstanding balance of the $60 million of medium term notes, but the interest rate cap remains in place because the benefits of the cap are also applicable to the new $45 million term loan. Credit risk arises from potential non-performance of counter parties to these agreements. The Company controlled the credit risk related to the cap by spreading the risk amongst three financial institutions and reviewing their financial stability prior to entering into the arrangements. There is no market risk associated with changes in interest rates since the Company paid for the cap when entering into the agreement. FUEL SWAPS-The Company purchases, rather than generates itself, a significant portion of the energy required to service its retail business. These purchased energy prices can vary with changes in the price or availability of the underlying fuel sources, and the risk of such price volatility is no longer covered by rate mechanisms which were previously in place. A significant portion of the Company's exposure to purchased energy price volatility is closely matched to changes in residual oil prices. To manage the oil-related risk of energy price fluctuations, the Company has entered into agreements known as "swaps", essentially in which the Company agreed to pay a fixed price for a specific quantity of a specific commodity (residual oil in this case), for a given time period. This transfers the risk (or the benefit) of commodity price fluctuations to the other party to the agreement for the given period of time. These are strictly financial transactions, and no delivery of the underlying commodity is taken. Settlements occur 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. The Company entered into "swap" transactions for 1998 and 1997 amounting to 1,180,000 and 865,000 barrels of residual oil, respectively. As a result of market movements in 1998 and 1997 the Company made cash payments of approximately $5.1 million in 1998 and received cash payments of $1.2 million in 1997 associated with the swap transactions. Additionally, as a result of the dramatic decrease in oil prices in 1998 (near twelve-year lows) the Company exceeded its margin limit with at least one of the counterparties to the swap agreements. Therefore the Company was required to post about $0.8 million of collateral in the form of cash, letter of credit, or other marketable security. The Company chose to provide cash as collateral and is reflected in accounts receivable on the Consolidated Balance Sheet at December 31, 1998. 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. As a result of these hedging activities, the Company is managing a substantial portion of the risk of energy price fluctuations, which allows the Company to more accurately predict its future purchased energy costs and cash flow requirements. To ensure the Company maintains a hedging, and not a speculative position, the Company has established official policies, procedures and controls for its fuel hedging program. The Company manages the credit risk related to the fuel swaps through credit limits, collateral instruments, monitoring procedures, and diversification of counterparties. Basis risk is the risk that changes in the Company's costs do not move perfectly in tandem with the index/commodity specified in the swap. While basis risk exists with the residual oil swaps, the relationship between the Company's oil related purchased power costs and the index is highly correlated, and the Company continues to develop its purchased power portfolio to ensure that a high degree of correlation exists. Therefore, the Company does not expect any significant exposure to market/basis risk from the oil swaps. As a result of the achievement of this high degree of correlation, the "swaps" are accounted for as hedges, and are not speculative financial instruments. At December 31, 1998, the Company was a party to "swaps" covering 1.6 million barrels of residual oil for the year 1999 and 265,000 barrels 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 no longer selling electricity in the retail market, the utilization of fuel swaps will no longer be required. The fair market value of these 1999 and 2000 "swaps" at December 31, 1998 is estimated to be a negative $4.1 million. Also, the Company expects to be required to post collateral in the first quarter of 1999. Collateral is not expected to be posted after the first quarter because hedge volumes will be significantly reduced and the Company does not anticipate entering into any additional hedge transactions. Since the "swaps" are accounted for as hedges, the fair market value has not been recorded in the Consolidated Financial Statements. The fair market value estimate was determined using available market data. Judgement is required in interpreting market data, and the use of different market assumptions or estimation methodologies may affect the estimated fair market value. 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%. During 1998, BERI incurred minor additional interest expense in connection with the interest rate swap arrangement. Market risk is the potential loss arising from adverse changes in interest rates. The fair value of the interest rate swap at December 31, 1998 is a negative $286,000 and represents the estimated payment that would be made to terminate the agreement. 14. CONTINGENCIES ENVIRONMENTAL MATTERS-On October 10, 1996, the American Institute of Certified Public Accountants issued Statement of Position 96-1, "Environmental Remediation Liabilities" (SOP). The principal objective of the SOP is to improve the manner in which existing authoritative accounting literature is applied by entities to specific situations of recognizing, measuring and disclosing environmental remediation liabilities. The SOP became effective January 1, 1997. This SOP has not had a material impact on the Company's financial position or results of operations. 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. As to the only other site which has been listed by the Department of Environmental Protection as an Uncontrolled Hazardous Substance Site, the Company was informed that it is considered a de minimis generator. 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 these waste disposal sites. 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, 1998, the liability recorded by the Company for its estimated environmental remediation costs amounted to $331,000. The Com- pany's actual future environmental remediation costs may be higher as additional factors become known. 15. NEW ACCOUNTING PRONOUNCEMENTS In June 1998, the Financial Accounting Standards Board issued Statement No. 133, "Accounting for Derivative Instruments and Hedging Activities" (FASB 133), and is effective for fiscal years beginning after June 15, 1999. FASB 133 establishes accounting and reporting standards for derivative instruments and for hedging activities. It requires that an entity recognize all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. Changes in the derivatives fair value should be recognized currently in earnings unless the derivative is designated as a hedge. When designated as a hedge, the change in fair value should be recognized currently in changes in equity. FASB 133 also requires a company to formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment. The affects of the adoption of FASB 133 on the Company's financial statements are currently not known. The Company believes that its fuel and interest rate swap agreements will qualify for hedge accounting treatment under FASB 133. In April 1998, the American Institute of Certified Public Accountants issued Statement of Position 98-5, "Reporting on the Costs of Start-up Activities" (SOP 98-5). The Company is required to adopt SOP 98-5 for fiscal year 1999. SOP 98-5 defines start-up activities as one-time activities an entity undertakes when it opens a new facility, introduces a new product line or service, conducts business in a new territory or with a new class of customer or beneficiary, initiates a new process in an existing facility or commences some new operation. SOP 98-5 covers accounting for organization costs and requires that any such costs should be expensed as incurred in the same manner as other start-up costs. The statement requires entities to expense previously capitalized costs in the year of adopting SOP 98-5. The Company does not believe the application of this statement will have a material impact on the financial statements. On January 1, 1998, the Company adopted Statement of Financial Accounting Standards No. 131, "Disclosures about Segments of an Enterprise and Related Information" (FASB 131). FASB 131 establishes standards for the way public business enterprises report information about operating segments in annual financial statements. It also establishes standards for related disclosures about products and services, geographic areas and major customers. The adoption of FASB 131 in 1998 did not have any impact on financial statement disclosures. PRICEWATERHOUSECOOPERS LLP REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS TO THE STOCKHOLDERS AND DIRECTORS OF BANGOR HYDRO-ELECTRIC COMPANY: In our opinion, the accompanying consolidated balance sheets and statements of capitalization and the related consolidated statements of income, common stock investment and cash flows present fairly, in all material respects, the financial position of Bangor Hydro-Electric Company (the Company) and its subsidiaries at December 31, 1998 and 1997, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1998, in conformity with generally accepted accounting principles. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with generally accepted auditing standards 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 the opinion expressed above. PricewaterhouseCoopers, LLP January 27, 1999 ITEM 9 CHANGES IN AND DISAGREEMENTS WITH AUDIT FIRMS ON - ------ ------------------------------------------------ FINANCIAL DISCLOSURE -------------------- There have been no changes in or disagreements with audit firms on financial disclosure. PART III - -------- ITEM 10 DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT - ------- -------------------------------------------------- See Part I above, and see the information under "Election of Directors" in the Company's definitive proxy statement for the annual meeting of stockholders to be held on May 19, 1999, which information is incorporated herein by reference. ITEM 11 EXECUTIVE COMPENSATION - ------- ---------------------- See the information under "Executive Compensation" in the Company's definitive proxy statement for the annual meeting of stockholders to be held on May 19, 1999, which information is incorporated herein by reference. ITEM 12 SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS - ------- ----------------------------------------------- AND MANAGEMENT -------------- (a) Security Ownership of Certain Beneficial Owners See the Company's definitive proxy statement for the annual meeting of stockholders to be held on May 19, 1999, which information is incorporated herein by reference. (b) Security Ownership of Management See the Company's definitive proxy statement for the annual meeting of stockholders to be held on May 19, 1999, which information is incorporated herein by reference. (c) Changes in Control Not applicable. ITEM 13 CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS - ------- ---------------------------------------------- See the information under "Compensation Committee Interlocks and Insider Participation" in the Company's definitive proxy statement for the annual meeting of stockholders to be held on May 19, 1999, which information is incorporated herein by reference. PART IV - ------- ITEM 14 EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS - ------- ---------------------------------------------------- on Form 8-K ----------- (a) Consolidated Financial Statements of the Company covered by the Report of the of Independent Auditors (See Item 8): Consolidated Statements of Income for the Years Ended December 31, 1998, 1997 and 1996 Consolidated Balance Sheets - December 31, 1998 and 1997 Consolidated Statements of Common Stock Investment for the Years ended December 31, 1998, 1997 and 1996 Consolidated Statements of Capitalization - December 31, 1998 and 1997 Consolidated Statements of Cash Flows for the Years Ended December 31, 1998, 1997 and 1996 Notes to Consolidated Financial Statements Report of Independent Accountants (b) Schedules Report of Independent Accountants Schedule VIII - Reserves for Doubtful Accounts and Insurance All other schedules are omitted as the required information is inapplicable or the information is presented in the Company's consolidated financial statements or related notes. (c) Exhibits See Exhibit Index, page (d) Reports on Form 8-K The Company has one current report on Form 8-K, dated September 25, 1998 relating to the Company's agreement to sell substantially all of its generation assets to PP&L Global, Inc. 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/ William C. Bullock, Jr. - --------------------------- 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 17, 1999. PRICEWATERHOUSECOOPERS REPORT OF INDEPENDENT ACCOUNTANTS To the Stockholders and Board of Directors of Bangor Hydro-Electric Company: Our report on the consolidated financial statements of Bangor Hydro-Electric Company is included in Item 8 of this Form 10-K. In connection with our audits of such financial statements, we have also audited the related financial statement schedule listed in the index in Item 14(b) of this Form 10-K. In our opinion, the financial statement schedule referred to above, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information required to be included therein. /s/ PriceWaterhouseCoopers, L.L.P. ---------------------------------------- PRICEWATERHOUSECOOPERS, L.L.P. January 27, 1999 SCHEDULE VIII RESERVES FOR DOUBTFUL ACCOUNTS AND INSURANCE -------------------------------------------- Additions -----------------------------
Balance at Charged to Charged to Balance at Beginning Costs and Other End Of Period Expenses Accounts Deductions of Period ------- ------- ------- ------- ------- 1998 Reserve for Doubtful Accounts $ 1,450,000 $ 1,345,536 $ - $ 1,720,536 (A)$ 1,075,000 ----------- ----------- ---------- ----------- ----------- Reserve for Retirees' Life Insurance $ - $ - $ - $ - $ - ----------- ----------- ---------- ----------- ----------- 1997 Reserve for Doubtful Accounts $ 1,450,000 $ 1,401,313 $ - $ 1,401,313 (A)$ 1,450,000 ----------- ----------- ---------- ----------- ----------- Reserve for Retirees' Life Insurance $ - $ - $ - $ - $ - ----------- ----------- ---------- ----------- ----------- 1996 Reserve for Doubtful Accounts $ 1,450,000 $ 1,826,884 $ - $ 1,826,884 (A)$ 1,450,000 ----------- ----------- ---------- ----------- ----------- Reserve for Retirees' Life Insurance $ 852,000 $ - $ - $ - $ 852,000 ----------- ----------- ---------- ----------- ----------- NOTE: (A) Accounts written off, less recoveries.
EXHIBIT INDEX EXHIBITS FILED HEREWITH EXHIBIT NO. DESCRIPTION OF EXHIBIT ----------- ---------------------- 3. ARTICLES OF INCORPORATION & BY-LAWS ----------------------------------- 3(a) Articles of Amendment Allowing Use of Similar Name 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 4. INSTRUMENTS DEFINING THE RIGHTS OF SECURITY HOLDERS --------------------------------------------------- 4.1 Mortgage and Deed of Form S-1, Reg. No. 2-54452, Trust dated as of Exhibit 4(b)(1) July 1, 1936, re First Mortgage Bonds 4.2 Supplemental Indenture Form S-1, Reg. No. 2-54452, dated as of December 1, Exhibit 4(b)(2) 1945, amending the Mortgage 4.3 Supplemental Indenture Form S-1, Reg. No. 2-54452 dated as of September 1, Exhibit 4(b)(4) 1969, re 8 1/4% Series Bonds, together with form of purchase agreement. (Supplemental indentures and purchase agreements with respect to prior issues are substantially identical in substantive content to the 8 1/4% Series documents). 4.4 Supplemental Indenture Form 10-K, 1975, Exhibit B dated as of November 1, 1975, re 10 1/2% Series Bonds, together with form of purchase agreement 4.5 Supplemental Indenture Form 8-K, 6/28/76, Exhibit A dated as of June 1, 1976, re 9 1/4% Series Bonds 4.6 Form of Purchase Form 10-K, 1976, Exhibit C Agreement re 9 1/4% Series Bonds 4.7 Supplemental Indenture Form S-7, Reg. No. 2-61589, dated as of January 1, Exhibit 5(a)(7) 1978, re 8.6% Series Bonds, together with form of purchase agreement 4.8 Supplemental Indenture Form 10-Q, 3rd Quarter 1979, dated as of August 1, Exhibit A 1979, re 10.25% Series Bonds, together with form of purchase agreement Common Stock Purchase Plan 4.9 Supplemental Indenture Form 10-Q, 1st Quarter, 1981, dated as of April 1, Exhibit A 1981 re 15.25% Series Bonds, together with form of purchase agreement 4.10 Supplemental Indenture Form 10-Q, 2nd Quarter 1981, dated as of July 30, Exhibit (4) 1981 re 16.50% Series Bonds, together with form of purchase agreement 4.11 Bond Purchase Agreement, Form 10-K, 1983, Exhibit 4(a) including form of supplemental indenture, with respect to First Mortgage Bonds, 12.50% Series due 1998 4.12 Loan Agreement, Indenture Form 10-K, 1983, Exhibit 4(b) of Trust and Letter of Credit Reimbursement Agreement with respect to Variable Rate Demand Pollution Control Revenue Bonds (Bangor Hydro- Electric Company Project) Series 1983 4.13 Bond Purchase Agreement, Form 10-K, 1984, Exhibit 4(a) including form of supplemental indenture, with respect to First Mortgage Bonds, 17.35% Series due 1994 4.14 Bond Purchase Agreement Form 10-Q, First Quarter, dated as of March 1, 1989 1989, Exhibit 4.1 including form of supplemental indenture, with respect to First Mortgage Bonds, 10.25% Series due 2019 4.15 Preferred Stock Purchase Form 10-K, 1990, Exhibit 4(a) Agreement, 8.76% Series dated as of December 19, 1989 4.16 Bond Purchase Agreement Form 10-K, 1990, Exhibit 4(b) dated as of June 15, 1990 including form of supplemental indenture, with respect to First Mortgage Bonds, 10.25% Series due 2020 4.17 Loan Agreement by and Form 10-Q, 3rd Quarter 1995, Finance Authority of Exhibit 4.1 Maine and Bangor Hydro- Electric Company 4.18 Credit Agreement Dated Form 10-Q, 3rd Quarter 1995, as of June 30, 1995 Exhibit 4.2 among Bangor Hydro- Electric Company, the Banks named therein, Chemical Bank as Administrative Agent and Fleet Bank of Maine and First National Bank of Boston, as Co-Agents. 4.19 Purchase Contract dated Form 10-Q, 3rd Quarter 1995, as of June 28, 1995 among Exhibit 4.3 the Finance Authority of Maine and Bangor Hydro- Electric Company and Prudential Securities Incorporated 4.20 General and Refunding Form 10-Q, 3rd Quarter 1995, Mortgage Indenture and Exhibit 4.4 Deed of Trust - Bangor Hydro-Electric Company to Chemical Bank, As Trustee, Dated as of June 1, 1995 4.21 Supplemental Indenture Form 10-Q, 3rd Quarter 1995, Dated as of June 15, 1995 Exhibit 4.5 to General and Refunding Mortgage Indenture and Deed of Trust dated as of June 1, 1995 (Bangor Hydro- Electric Company to Chemical Bank). 4.22 Supplemental Indenture as Form 10-Q, 3rd Quarter 1995, of June 29, 1995 to Mortgage and Deed of Trust dated as of July 1, 1936 (Bangor Hydro-Electric Company to Citibank, N.A. at Trustee). 4.23 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). 4.24 Second Amendment dated as of Form 10-K, 1997, Exhibit 4(a) June 6, 1997 to the Credit Agreement Dated as of June 30, 1995 among Bangor Hydro- Electric Company and the Banks named therein, Chase Manhattan Bank (formerly known as Chemical Bank) as Administrative Agent and Fleet Bank of Maine and First National Bank of Boston as Co-Agents. 4.25 Security Agreement dated as of Form 10-K, 1997, Exhibit 4(b) June 6, 1997 between Bangor Hydro-Electric Company and Chase Manhattan Bank as Administrative Agent under the Credit Agreement dated as of June 30, 1995, as amended from time to time. 4.26 Third Amendment dated as of Form 10-K, 1997, Exhibit 4(c) November 20, 1997 to the Credit Agreement Dated as of June 30, 1995 among Bangor Hydro- Electric Company and the Banks named therein, Chase Manhattan Bank (formerly known as Chemical Bank) as Administrative Agent and Fleet Bank of Maine and First National Bank of Boston as Co-Agents. 4.27 Amended and Restated Security Form 10-K, 1997, Exhibit 4(d) Agreement Dated as of November 20, 1997 between Bangor Hydro-Electric Company and Chase Manhattan Bank as Administrative Agent under the Credit Agreement dated as of June 30, 1995, as amended from time to time. 4.28 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 4.29 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 4.30 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 4.31 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 4.32 Warrant to Purchase Form 10-Q, Second Quarter 1998, Common Stock Granted to Exhibit 4(c) Energy National, Inc. on June 26, 1998 4.33 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 Form of Federal Power Form S-1, Reg. No. 2-54452, Commission license Exhibit 13(b)(4) for hydro-electric dam facility 10.14 Employee Stock Ownership Form S-7, Reg. No. 2-59747, Plan, including related Exhibit 5(a)(2) trust agreements, dated June 1, 1977 10.15 Sample of binder relating Form S-7, Reg. No. 2-59747, to contingent liability Exhibit 5(a)(4) for nuclear incidents 10.16 Agreements relating to Form S-7, Reg. No. 2-61589, Seabrook 1 and 2 Exhibit 5(a)(3) including offering letter dated September 7, 1977 and the Company's response thereto dated October 6, 1977, the Agreement to Transfer Ownership Share between the Company and The Connecticut Light and Power Co., dated November 1, 1977 and a letter amendment thereto dated January 31, 1978, and the Joint Ownership Agreement with Public Service Company of New Hampshire and other utilities as amended through January 31, 1975 10.17 Amendment No. 2 dated Form 10-K, 1976, Exhibit H(2) August 16, 1976 to Joint Ownership Agreement dated November 1, 1974 with Central Maine Power Company and others re Wyman Unit No. 4 10.18 Copies of Tenth and Form 10-K, 1979, Exhibit D Eleventh Amendments dated October 11, 1979 and December 15, 1979, respectively, to the Agreement for Joint Ownership Construction and Operation of New Hampshire Nuclear Units 10.19 Copies of Forms of Form 10-Q, 2nd Qtr. 1979, documents related to Exhibit A the Company's proposed purchase of an additional 1.80142% interest in the Seabrook Nuclear Units, consisting of PSNH's offer to sell ownership shares dated March 8, 1979, the Company's letter response thereto dated March 19, 1979, and the Sixth, Seventh, Eighth and Ninth Amendment to the Agreement for Joint Ownership, Construction and Operation of New Hampshire Nuclear Units, dated April 18, 1979, April 18, 1979, April 25, 1979, and June 8, 1979, respectively 10.20 Copy of Thirteenth Form 10-K, 1981, Exhibit Amendment dated as of 10(a) December 31, 1980 to the Agreement for Joint Ownership, Construction and Operation of New Hampshire Nuclear Units 10.21 Forms of contracts Form 10-Q, 2nd Qtr. 1982, concerning the Company's Exhibit 10 participation with other New England utilities in the proposed Quebec interconnection 10.22 Fourteenth Amendment Form 10-K, 1983, Exhibit 10.1 dated as of June 1, 1982 to the Agreement for Joint Ownership, Construction and Operation of New Hampshire Nuclear Units 10.23 Third Amendment dated Form 10-K, 1983, Exhibit 10.2 as of November 1, 1982 to Preliminary Quebec Interconnection Support Agreement 10.24 Second Amendment dated Form 10-K, 1983, Exhibit 10.3 as of November 1, 1982 to Agreement With Respect to Use of Quebec Interconnection 10.25 Amendment No. 2 dated Form 10-K, 1983, Exhibit 10.4 as of November 1, 1982, to Phase 1 Terminal Facility Support Agreement (Quebec Interconnection) 10.26 Amendment No. 2 dated Form 10-K, 1983, Exhibit 10.5 as of November 1, 1982 to Phase 1 Vermont Transmission Line Support Agreement (Quebec Interconnection) 10.27 Fourth Amendment Form 10-Q, 1st Quarter 1983, dated as of March 1, Exhibit 10.1 1983, to Preliminary Quebec Interconnection Support Agreement 10.28 Fourteenth Amendment to Form 10-Q, 2nd Quarter 1983, Agreement for Joint Exhibit 10.2 Ownership, Construction and Operation of New Hampshire Nuclear Units 10.29 Fifth Amendment to Form 10-Q, 2nd Quarter 1983, Preliminary Quebec Exhibit 10.2 Interconnection Support Agreement 10.30 Amendment dated as of Form 10-Q, 2nd Quarter 1983, September 1, 1981 Exhibit 10.3 to New England Power Pool Agreement 10.31 Amendment dated as of Form 10-Q, 2nd Quarter 1983, June 1, 1982 to New Exhibit 10.4 England Power Pool Agreement 10.32 Amendment dated as of Form 10-Q, 2nd Quarter 1983, June 15, 1983 to New Exhibit 10.5 England Power Pool Agreement 10.33 Amendment dated as of Form 10-Q, 3rd Quarter 1983, October 1, 1983 to Exhibit 10.1 New England Power Pool Agreement 10.34 Amendment No. 1 to the Form 10-K, 1983, Exhibit 10(b) Maine Yankee Power Contract 10.35 Amendment No. 2 to the Form 10-K, 1983, Exhibit 10(c) Maine Yankee Power Contract 10.36 Additional Power Con- Form 10-K, 1983, Exhibit 10(d) tract between Maine Yankee and its sponsors, including the Company 10.37 Interim Protection Agree- Form 10-Q, 1st Quarter 1984, ment dated as of April Exhibit 10.1 27, 1984 relating to the Seabrook project 10.38 Fifteenth Amendment Form 10-Q, 1st Quarter 1984, to the Seabrook Joint Exhibit 10.2 Ownership Agreement 10.39 Sixteenth Amendment Form 10-Q, 2nd Quarter 1984, to the Seabrook Joint Exhibit 10.1 Ownership Agreement 10.40 Agreement for Seabrook Form 10-Q, 2nd Quarter 1984, Project Disbursing Agent Exhibit 10.2 10.41 Seventeenth Amendment to Form 10-K, 1984, Exhibit 10(a) Seabrook Joint Ownership Agreement and corresponding First Amendment to Seabrook Project Disbursing Agent Agreement (neither of which were executed by the Company) 10.42 Preliminary Support Form 10-K, 1984, Exhibit 10(b) Agreement - Phase 2 of Hydro-Quebec Inter- connection 10.43 Letter of Intent between Form 10-Q, 2nd Quarter 1985, the Company and Eastern Exhibit 10.1 Utilities Associates re: possible sale of Seabrook interest 10.44 First, Second and Third Form 10-K, 1985, Exhibit 10(a) Amendments to agreement for Seabrook Project Disbursing Agent (none of which were executed by the Company) 10.45 Amendment dated September 1, Form 10-K, 1985, Exhibit 10(b) 1985 to Agreement with respect to Use of Quebec Interconnection 10.46 Energy Contract dated Form 10-K, 1985, Exhibit 10(c) March 1983 between NEPOOL and Hydro-Quebec re: Hydro-Quebec Phase I interconnection project 10.47 Energy Banking Agreement Form 10-K, 1985, Exhibit 10(d) dated March 1983 between NEPOOL and Hydro-Quebec re Hydro-Quebec Phase I interconnection project 10.48 Interconnection Agreement Form 10-K, 1985, Exhibit 10(e) dated March 1983 between NEPOOL and Hydro-Quebec re: Hydro-Quebec Phase I interconnection project 10.49 Amendment dated September 1 Form 10-K, 1985, Exhibit 10(f) 1985 to NEPOOL Agreement re: Hydro-Quebec Phase II interconnection project 10.50 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 10.51 Boston Edison AC Facilities Form 10-K, 1985, Exhibit 10(h) Support Agreement dated June 1, 1985 re: Hydro-Quebec Phase II interconnection project 10.52 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 10.53 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 10.54 Phase II New Hampshire Form 10-K, 1985, Exhibit 10(k) Facilities Support Agreement dated June 1, 1985 re: Hydro-Quebec Phase II interconnection project 10.55 First Amendment dated Form 10-K, 1985, Exhibit 10(l) March 1, 1985 and Second Amendment dated January 1, 1986 to Preliminary Quebec Interconnection Support Agreement - Phase II 10.56 Amendment No. 3 dated Form 10-K, 1985, Exhibit 10(m) October 1, 1984 to Maine Yankee Power Contract 10.57 Amendment No. 1 dated Form 10-K, 1985, Exhibit 10(n) August 1, 1985 to Maine Yankee Capital Funds Agreement 10.58 Amendments dated August 1, Form 10-K, 1985, Exhibit 10(o) 1985, August 15, 1985, and January 1, 1986 to NEPOOL Agreement 10.59 Fourth Amendment to Form 10-Q, 1st Quarter 1986, Seabrook Project Exhibit 10.1 Disbursing Agent Agreement 10.60 Third Amendment to Vermont Form 10-Q, 1st Quarter 1986, Transmission Line Support Exhibit 10.2 Agreement 10.61 First Amendment to Hydro- Form 10-Q, 1st Quarter 1986, Quebec Phase I Intercon- Exhibit 10.3 nection Agreement 10.62 First Amendment to Hydro- Form 10-Q, 2nd Quarter 1986, Quebec Phase II Exhibit 10.1 Massachusetts Trans- mission Facilities Support Agreement 10.63 First Amendment to Hydro- Form 10-Q, 2nd Quarter 1986, Quebec Phase II New Exhibit 10.2 Hampshire Transmission Facilities Support Agreement 10.64 First Amendment to Hydro- Form 10-Q, 2nd Quarter 1986, Quebec Phase II New England Exhibit 10.3 Power AC Facilities Support Agreement 10.65 First Amendment to Form 10-Q, 2nd Quarter 1986, Hydro-Quebec Phase II Exhibit 10.4 Boston Edison Company AC Facilities Support Agreement 10.66 Eighteenth Amendment to Form 10-Q, 2nd Quarter 1986, Seabrook Joint Ownership Exhibit 10.5 Agreement 10.67 Amendment Number 3 to Form 10-Q, 3rd Quarter 1986, Hydro-Quebec Phase l Exhibit 10.1 Terminal Facility Support Agreement 10.68 Amendment Number 3 to Form 10-Q, 3rd Quarter 1986, Hydro-Quebec Phase I Exhibit 10.2 Vermont Transmission Line Support Agreement 10.69 Power Sale Agreement for Form 10-Q, 3rd Quarter 1986, sale of approximately Exhibit 10.3 31 MW of system power by Bangor Hydro-Electric Company to UNITIL Power Corp. 10.70 Purchase Agreement with Form 10-Q, 3rd Quarter 1986, respect to Wyman No. 4 Exhibit 10.4 between Bangor Hydro- Electric Company and Fitchburg Gas and Electric Light Company 10.71 Nineteenth Amendment to Form 10-K, 1986, Exhibit 10(a) Seabrook Joint Ownership Agreement 10.72 Twentieth Amendment to Form 10-K, 1986, Exhibit 10(b) Seabrook Joint Ownership Agreement 10.73 Agreement of Purchase and Form 10-K, 1986, Exhibit 10(c) Sale dated February 19, 1986, regarding the sale of the Company's Seabrook interest to EUA Power 10.74 Bill of Sale and Assumption Form 10-K, 1986, Exhibit 10(d) of Obligations dated November 25, 1986 regarding the sale of the Company's Seabrook interest to EUA Power 10.75 Deed dated November 21, Form 10-K, 1986, Exhibit 10(e) 1986 regarding the sale of the Company's Seabrook interest to EUA Power 10.76 Agreement to Share Certain Form 10-K, 1986, Exhibit 10(f) Costs re Tewksbury-Seabrook Transmission Line dated May 8, 1986 10.77 Joint Venture Agreement Form 10-K, 1986, Exhibit 10(g) effective as of June 9, 1986, between the Company and Pacific Lighting Energy Systems (as amended by a First Amendment thereto dated June 16, 1986) re Bangor-Pacific Hydro Associates (formerly West Enfield Associates) 10.78 Capital Support Agreement Form 10-K, 1986, Exhibit 10(h) dated as of January 29, 1987, among the Company and lenders to Bangor- Pacific Hydro Associates 10.79 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) 10.80 Deed and Bill of Sale re Form 10-K, 1986, Exhibit 10(j) transfer of West Enfield site from the Company to Bangor-Pacific Hydro Associates 10.81 Assignment by the Company Form 10-K, 1986, Exhibit 10(k) of Joint Venture Interest to Penobscot Hydro Co., Inc. 10.82 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 10.83 Third Amendment to Pre- Form 10-K, 1987, Exhibit 10(a) liminary Quebec Intercon- nection Support Agreement - Phase II 10.84 Fourth Amendment to Pre- Form 10-K, 1987, Exhibit 10(b) liminary Quebec Intercon- nection Support Agreement - Phase II 10.85 Fifth Amendment to Pre- Form 10-K, 1987, Exhibit 10(c) liminary Quebec Intercon- nection Support Agreement - Phase II 10.86 Sixth Amendment to Pre- Form 10-K, 1987, Exhibit 10(d) liminary Quebec Intercon- nection Support Agreement - Phase II 10.87 Seventh Amendment to Pre- Form 10-K, 1987, Exhibit 10(e) liminary Quebec Intercon- nection Support Agreement - Phase II 10.88 Amendment to New England Form 10-K, 1987, Exhibit 10(f) Power Pool Agreement dated March 1, 1988 10.89 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 10.90 Dividend Reinvestment and Form 10-K, 1987, Exhibit 10(i) Common Stock Purchase Plan Effective as of December 1, 1987 10.91 Deed dated December 2, Form 10-K, 1988, Exhibit 10(a) 1988 regarding the sale of certain Seabrook trans- mission facilities to EUA Power 10.92 Ninth Amendment to Form 10-K, 1988, Exhibit 10(b) Preliminary Quebec Interconnection Support Agreement - Phase II 10.93 Tenth Amendment to Form 10-K, 1988, Exhibit 10(c) Preliminary Quebec Interconnection Support Agreement - Phase II 10.94 Second Amendment to Form 10-K, 1988, Exhibit 10(d) Massachusetts Trans- mission Facilities Support Agreement 10.95 Third Amendment to Form 10-K, 1988, Exhibit 10(e) Massachusetts Trans- mission Facilities Support Agreement 10.96 Fourth Amendment to Form 10-K, 1988, Exhibit 10(f) Massachusetts Trans- mission Facilities Support Agreement 10.97 Fifth Amendment to Form 10-K, 1988, Exhibit 10(g) Massachusetts Trans- mission Facilities Support Agreement 10.98 Sixth Amendment to Form 10-K, 1988, Exhibit 10(h) Massachusetts Trans- mission Facilities Support Agreement 10.99 Second Amendment to Form 10-K, 1988, Exhibit 10(i) New Hampshire Trans- mission Facilities Support Agreement 10.100 Third Amendment to Form 10-K, 1988, Exhibit 10(j) New Hampshire Trans- mission Facilities Support Agreement 10.101 Fourth Amendment to Form 10-K, 1988, Exhibit 10(k) New Hampshire Trans- mission Facilities Support Agreement 10.102 Fifth Amendment to Form 10-K, 1988, Exhibit 10(l) New Hampshire Trans- mission Facilities Support Agreement 10.103 Sixth Amendment to Form 10-K, 1988, Exhibit 10(m) New Hampshire Trans- mission Facilities Support Agreement 10.104 Second Amendment to Form 10-K, 1988, Exhibit 10(n) Phase II AC New England Power Facilities Sup- port Agreement 10.105 Third Amendment to Form 10-K, 1988, Exhibit 10(o) Phase II AC New England Power Facilities Sup- port Agreement 10.106 Fourth Amendment to Form 10-K, 1988, Exhibit 10(p) Phase II AC New England Power Facilities Sup- port Agreement 10.107 Fifth Amendment to Form 10-K, 1988, Exhibit 10(q) Phase II AC New England Power Facilities Sup- port Agreement 10.108 Second Amendment to Form 10-K, 1988, Exhibit 10(r) Phase II Boston Edison AC Facilities Support Agreement 10.109 Third Amendment to Form 10-K, 1988, Exhibit 10(s) Phase II Boston Edison AC Facilities Support Agreement 10.110 Fourth Amendment to Form 10-K, 1988, Exhibit 10(t) Phase II Boston Edison AC Facilities Support Agreement 10.111 Fifth Amendment to Form 10-K, 1988, Exhibit 10(u) Phase II Boston Edison AC Facilities Support Agreement 10.112 Letter of Assurances, Form 10-K, 1988, Exhibit 10(v) Consents and Agreements With Respect to Credit Facility Financing for Phase II Hydro-Quebec Financing 10.113 Agreement With Hanlin Form 10-K, 1988, Exhibit 10(w) Group, Inc., also known as "LCP", for the sale of electricity 10.114 401 (k) Plan for Non- Form 10-K, 1988, Exhibit 10(x) Union Employees 10.115 Credit Agreement dated Form 10-Q, First Quarter, 1989 as of May 2, 1989 among Exhibit 4.2 the Company, the Banks named therein, and Manufacturers Hanover Trust Company, as Agent 10.116 Agreement for the Sale Form S-2, Reg. No. 33-39181, and Purchase of Electricity Exhibit 10.79 dated as of August 13, 1984 between Ultrapower Incorpor- ated-Jonesboro and the Company 10.117 Agreement for the Sale Form S-2, Reg. No. 33-39181, and Purchase of Electricity Exhibit 10.80 dated as of August 13, 1984 between Ultrapower Incorpor- ated-West Enfield and the Company 10.118 Amendment Agreement Form S-2, Reg. No. 33-39181, dated November 3, 1988 Exhibit 10.81 between the Company and Babcock-Ultrapower West Enfield and Babcock- Ultrapower-Jonesboro 10.119 Agreement for the Form S-2, Reg. No. 33-39181, Purchase and Sale of Exhibit 10.82 Electricity dated as of June 21, 1984 between Penobscot Energy Recovery Company and the Company 10.120 Amendment No. 1 as of Form S-2, Reg. No. 33-39181, March 24, 1986 to the Exhibit 10.83 Agreement for the Purchase and Sale of Electricity dated as of June 21, 1984 between Penobscot Energy Recovery Company and the Company 10.121 Power Purchase Agree- Form S-2, Reg. No. 33-39181, ment dated October 24, 1984 Exhibit 10.84 between Alternative Energy Decisions, Inc. and the Company 10.122 Partnership Agreement Form S-2, Reg. No. 33-39181, dated as of July 1, 1990 Exhibit 10.85 between NORVARCO and Bangor Var Co., Inc. 10.123 Form of Agreement with Form 10-K, 1992, Exhibit 10(a) certain Executive Officers providing supplemental death and retirement benefits 10.124 Form of Agreement with Form 10-K, 1992, Exhibit 10(b) certain Executive Officers providing benefits upon a change of control 10.125 Purchase Agreement between Form 10-Q, 3rd Quarter 1995, Babcock-Ultrapower Exhibit 10.1 Jonseboro and Bangor Hydro- Electric Company 10.126 Purchase Agreement between Form 10-Q, 3rd Quarter 1995, Babcock-Ultrapower West Exhibit 10.2 Enfield and Bangor Hydro- Electric Company 10.127 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. 10.128 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. 10.129 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. 10.130 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. 10.131 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 10.132 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 10.133 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 10.134 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). EX-27 2 FINANCIAL DATA SCHEDULE ACCOMPANYING FORM 10-K
UT This schedule contains summary financial information extracted from Bangor Hydro-Electric Company-1998 Form 10K and is qualified in its entirety by rreference to such 10K. 0000009548 BANGOR HYDRO-ELECTRIC COMPANY 1,000 12-MOS DEC-31-1998 DEC-31-1998 PER-BOOK 251,342 55,557 36,645 262,144 0 605,688 36,817 59,054 22,993 118,864 7,604 4,734 263,028 0 12,000 0 25,515 1,594 0 0 172,349 605,688 195,144 6,093 153,915 160,008 35,136 1,292 36,428 24,963 11,465 1,244 10,221 0 22,906 30,932 $1.39 $1.33
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