10-K 1 k102002.txt BANGOR HYDRO-ELECTRIC CO. 10-K 2002 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, 2002 Commission File No. 1-10922 ----------------- ------- 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(g) of the Act: Title of each class ------------------- 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 February 1, 2003 of the voting stock held by non-affiliates of the registrant was $5.284 million. This Page Intentionally Left Blank BANGOR HYDRO-ELECTRIC COMPANY TABLE OF CONTENTS ----------------- PART I Page ---- Item 1. Business 4 Item 2. Properties 5 Item 3. Legal Proceedings 6 Item 4. Submission of Matters to a Vote of Security Holders 6 PART II Item 5. Market for Registrant's Common Equity and Related Stockholder Matters 6 Item 6. Selected Financial Data 8 Item 7. Management's Discussion and Analysis of Results of Operations and Financial Condition 10 Item 7A. Quantitative and Qualitative Disclosures About Market Risk 26 Item 8. Financial Statements and Supplementary Data 27 Consolidated Statements of Income 27 Consolidated Balance Sheets 28 Consolidated Statements of Capitalization 30 Consolidated Statements of Cash Flows 31 Consolidated Statements of Common Stock Investment 32 Notes to Consolidated to Financial Statements 33 Report of Independent Accountants 60 Item 9. Changes in and Disagreements with Independent Accountants on Accounting and Financial Disclosure 61 PART III Item 10. Directors and Executive Officers of the Registrant 62 Item 11. Executive Compensation 64 Item 12. Security Ownership of Certain Beneficial Owners and Management 69 Item 13. Certain Relationships and Related Transactions 70 Item 14. Controls and Procedures 71 PART IV Item 15. Exhibits, Financial Statement Schedule, and Reports on Form 8-K 71 Signatures 73 Principal Executive Officer's and Chief Financial Officer's Certifications 74 Schedule II - Valuation and Qualifying Accounts and Reserves 77 Exhibits Delivered with this Report 78 Exhibits Incorporated Herein by Reference 79 PART I ------ Item 1 Business ------ -------- (a) General development of business ------------------------------- Bangor Hydro-Electric Company (the Company) is a public utility incorporated in Maine in 1924. Effective October 10, 2001, pursuant to an Agreement and Plan of Merger, the Company became a wholly owned subsidiary of Emera Inc. of Halifax, Nova Scotia (Emera). For a discussion of general developments that have occurred in the Company's business since January 1, 2002, see Item 7, "Management's Discussion and Analysis of Results of Operations and Financial Condition - Recent Events Affecting the Company". (a) Regulatory and Rate Matters --------------------------- See Item 7, "Management's Discussion and Analysis of Results of Operations and Financial Condition - Recent Events Affecting the Company" and Item 8, "Notes to Consolidated Financial Statements - Note 10 - Industry Restructuring and Rate Regulation". (b) Financial information about segments ------------------------------------ The Company has no material segments outside of the electric business. (c) Narrative description of business --------------------------------- (i) Principal business ------------------ The Company is a public utility primarily engaged in the transmission and distribution of electric energy, with a service area of approximately 5,275 square miles having a population of approximately 190,000 people. The Company serves approximately 107,000 customers in portions of the counties of Penobscot, Hancock, Washington, Waldo, Piscataquis and Aroostook. On March 1, 2000, the Company's obligation to generate or otherwise supply electric energy terminated as part of the restructuring of the electric utility industry in Maine. Although the Company has no long- term supply responsibility, the Maine Public Utilities Commission (MPUC) can mandate that the Company be the default standard offer provider. In February 2001, the MPUC directed the Company to provide energy services to customers as the standard offer provider for the period March 1, 2001 through February 28, 2002. However, the MPUC has selected third party suppliers to provide energy services to customers as the standard offer provider for the period March 1, 2002 through February 28, 2003. (ii) New product or segment - Not applicable ---------------------- (iii) Sources and availability of raw materials ----------------------------------------- Not applicable. The Company is primarily engaged in the delivery of electric energy. (iv) Franchises - Not applicable ---------- (v) Seasonal business ----------------- Sales of electricity are highest during the winter months primarily due to heating requirements and fewer daylight hours. (vi) Working capital items --------------------- The Company has been granted, through the ratemaking process, an allowance for working capital to operate its ongoing electric utility system. (vii) Single customer - Not applicable --------------- (viii) Backlog of orders - Not applicable ----------------- (ix) Business subject to renegotiation - Not applicable --------------------------------- (x) Competitive conditions ---------------------- The Company is a regulated public utility with an exclusive franchise to provide electricity delivery service within its service territory. (xi) Research and development - Not applicable ------------------------ (xii) Environmental matters --------------------- See Item 7, "Management's Discussion and Analysis of Results of Operations and Financial Condition - Other Matters - Environmental Matters" and Item 8, "Notes to Consolidated Financial Statements - Note 13 - Contingencies" for a discussion of Environmental Matters. (xiii) Number of employees ------------------- As of December 31, 2002, the Company had 313 full time employees. (d) Financial information about geographical areas - Not applicable ---------------------------------------------- Item 2 Properties ------ ---------- The Company owns approximately 550 miles of transmission lines and approximately 4,200 miles of distribution lines to serve its customers in portions of the counties of Penobscot, Hancock, Washington, Waldo, Piscataquis and Aroostook, Maine. The Company owns a variety of customer and business information systems used to manage its business operations. Other properties consist of office, garage and warehouse facilities at various locations in its service area. Pursuant to the issuance of various first mortgage bond issues, all of the Company's property, real, personal or mixed, including real estate, easements, lines, poles, wires, generating stations, buildings and equipment, is subject to the lien of a Mortgage and Deed of Trust Securing First Mortgage Bonds dated as of July 1, 1936 as supplemented and amended, with Citibank, N.A. (formerly City Bank Farmers Trust Company) as Trustee. Pursuant to the issuance of various additional financings, all of BHE's property, real, personal or mixed, including real estate, easements, lines, poles, wires, generating stations, and buildings is further subject to the lien of a General and Refunding Mortgage Indenture and Deed of Trust dated as of June 1, 1995 as supplemented and amended, with The Chase Manhattan Bank (formerly Chemical Bank) as Trustee. This mortgage presently serves as a "second mortgage" on the Company's property, but is intended to become the Company's first mortgage once all outstanding first mortgage bonds are retired. Item 3 Legal Proceedings ------ ----------------- See Item 7, "Management's Discussion and Analysis of Results of Operations and Financial Condition - Recent Events Affecting the Company." See also Item 7, "Management's Discussion and Analysis of Results of Operations and Financial Condition - Other Matters - Environmental Matters " and Item 8, "Notes to Consolidated Financial Statements - Note 13 - Contingencies" 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 the Registrant's Common Equity and Related Stockholder ------ ----------------------------------------------------------------- Matters ------- BHE Holdings Inc., a wholly-owned subsidiary of Emera, owns all of the Company's common stock. For information regarding dividends declared see Item 8 - Consolidated Statements of Income; Consolidated Balance Sheets, Consolidated Statements of Capitalization, Consolidated Statements of Cash Flows; and Consolidated Statement of Common Stock Investment. This Page Intentionally Left Blank BANGOR HYDRO-ELECTRIC COMPANY Item 6 Selected Financial Data Six-Year Statistical Summary (Unaudited)
2002 2001 2000 1999 1998 1997 Megawatt Hours (MWH) Generated And Purchased Hydro Generation *** 84,436 65,392 90,719 205,265 275,379 262,377 Oil (Company) 868 2,435 3,142 69,026 96,476 69,580 Biomass/Refuse (Purchased) 154,832 150,401 152,060 137,384 156,051 159,990 NEPOOL/Other Purchases 2,333,428 1,782,797 1,914,615 1,629,643 1,522,125 1,583,093 --------- --------- --------- --------- --------- --------- Total Generated & Purchased 2,573,564 2,001,025 2,160,536 2,041,318 2,050,031 2,075,040 Less Line Losses and Company Use 128,282 130,067 140,470 143,198 139,028 147,298 --------- --------- --------- --------- --------- --------- Remainder-MWH sold 2,445,282 1,870,958 2,020,066 1,898,120 1,911,003 1,927,742 ========= ========= ========= ========= ========= ========= Classification of Sales-MWH Residential 556,462 546,144 558,596 533,566 522,836 533,161 Commercial 571,372 583,829 570,963 545,087 524,292 515,904 Industrial 449,170 462,792 604,959 667,059 662,382 687,365 Lighting 8,719 8,742 8,859 8,911 8,901 8,780 Wholesale 2,925 2,676 2,799 2,716 2,704 3,841 ---------- ---------- ---------- ---------- ---------- ---------- Total MWH Billed to Customers 1,588,648 1,604,183 1,746,176 1,757,339 1,721,115 1,749,051 Unbilled Sales-Net Increase 13,071 4,343 2,629 11,772 1,040 33,011 ---------- ---------- ---------- ---------- ---------- ---------- Total Delivered Sales (MWH) 1,601,719 1,608,526 1,748,805 1,769,111 1,722,155 1,782,062 (Less) Interruptible Sales 55,235 22,305 178,943 230,378 248,091 265,438 ---------- ---------- ---------- ---------- ---------- ---------- Total Firm Delivered Sales (MWH) 1,546,484 1,586,221 1,569,862 1,538,733 1,474,064 1,516,624 Off-System Sales 843,563 262,432 271,261 129,009 188,848 145,680 ---------- ---------- ---------- ---------- ---------- ---------- Total Energy Sales (MWH) 2,445,282 1,870,958 2,020,066 1,898,120 1,911,003 1,927,742 ========== ========== ========== ========== ========== ========== Electric Operating Revenues and Expenses (000's) Electric Operating Revenues Residential $ 52,219 $ 50,264 $ 57,746 $ 73,304 $ 71,396 $ 67,532 Commercial 39,645 37,795 44,329 63,093 60,191 55,391 Industrial 15,879 15,516 23,749 43,560 42,645 41,930 Lighting 1,888 1,837 1,929 2,268 2,207 2,065 Wholesale 18 19 63 220 235 310 ------------ ------------ ------------ ------------ ------------ ------------ Total Revenue from Customers $ 109,649 $ 105,431 $ 127,816 $ 182,445 $ 176,674 $ 167,228 Standard Offer Service Revenue 12,196 84,589 66,134 - - - ------------ ------------ ------------ ------------ ------------ ------------ Total Operating Revenue $ 121,845 $ 190,020 $ 193,950 $ 182,445 $ 176,674 $ 167,228 Unbilled Sales-Net Increase (Decrease) 1,245 815 (5,014) 2,042 481 2,375 ------------ ------------ ------------ ------------ ------------ ------------ Total Revenue $ 123,090 $ 190,835 $ 188,936 $ 184,487 $ 177,155 $ 169,603 (Less) Interruptible Revenue 963 1,687 4,973 10,049 11,064 11,215 ------------ ------------ ------------ ------------ ------------ ------------ Total Firm Revenue $ 122,127 $ 189,148 $ 183,963 $ 174,438 $ 166,091 $ 158,388 Off-System Revenue 39,712 18,952 19,352 12,947 14,630 13,615 ------------ ------------ ------------ ------------ ------------ ------------ Total Electric Operating Revenues $ 162,802 $ 209,787 $ 208,288 $ 197,434 $ 191,785 $ 183,218 ============ ============ ============ ============ ============ ============ Operating Expenses Fuel for Generation and Purchased Power $ 61,670 $ 34,649 $ 44,509 $ 80,748 $ 82,027 $ 92,792 Standard Offer Service Purchased Power 11,508 82,839 65,553 - - - Operating and Maintenance Expense 34,573 36,800 35,311 36,492 34,448 32,471 Depreciation and Amortization 24,537 27,751 28,312 30,565 31,891 35,104 Taxes 11,413 11,752 12,228 14,032 11,642 3,168 ------------ ------------ ------------ ------------ ------------ ------------ Total Operating Expenses $ 143,701 $ 193,791 $ 185,913 $ 161,837 $ 160,008 $ 163,535 ============ ============ ============ ============ ============ ============ Summary of Operations (000's) Operating Revenue $ 167,738 $ 217,408 $ 212,338 $ 197,994 $ 195,144 $ 187,324 Operating Expenses 143,701 193,791 185,913 161,837 160,008 163,535 Other Income (Loss) (including equity AFDC) 1,303 (654) 613 2,806 1,292 1,292 Interest Expense (net of borrowed AFDC) 12,879 14,273 15,936 20,683 24,963 25,467 ------------ ------------ ------------ ------------ ------------ ------------ Net Income (Loss) $ 12,461 $ 8,690 $ 11,102 $ 18,280 $ 11,465 $ (386) Less Preferred Dividends 266 266 266 945 1,244 1,376 ------------ ------------ ------------ ------------ ------------ ------------ Earnings (Loss) on Common Stock $ 12,195 $ 8,424 $ 10,836 $ 17,335 $ 10,221 $ (1,762) ============ ============ ============ ============ ============ ============
BANGOR HYDRO-ELECTRIC COMPANY Item 6 Selected Financial Data Six-Year Statistical Summary (Unaudited)
2002 2001 2000 1999 1998 1997 Selected Financial Data Total Assets (000's) $ 640,731 $ 678,245 $ 532,220 $ 543,950 $ 605,688 $ 600,583 ============ =========== ============ ============ ============ ============ Electric Plant (000's) Total Electric Plant $ 344,382 $ 341,143 $ 327,247 $ 318,435 $ 372,782 $ 358,878 Depreciation Reserve 97,473 93,985 86,684 84,825 101,633 96,595 ------------ ------------ ------------ ------------ ------------ ------------ Net Electric Plant $ 246,909 $ 247,158 $ 240,563 $ 233,610 $ 271,149 $ 262,283 ============ ============ ============ ============ ============ ============ Capitalization (000's) Short-Term Debt $ 16,000 $ 8,000 $ - $ - $ 12,000 $ 34,000 Long-Term Debt 118,059 131,968 161,960 183,300 263,028 221,643 Redeemable Preferred Stock - - - - 7,604 9,137 Preferred Stock 4,734 4,734 4,734 4,734 4,734 4,734 Common Equity 206,266 205,557 137,420 132,722 118,864 106,558 ------------ ---------- ------------ ------------ ------------ ------------ Total $ 345,059 $ 350,259 $ 304,114 $ 320,756 $ 406,230 $ 376,072 ============ ============ ============ ============ ============ ============ Capital Structure Ratios (%) Short-Term Debt 4.6 % 2.3 % - % - % 3.0 % 9.1 % Long-Term Debt 34.2 % 37.7 % 53.2 % 57.1 % 64.7 % 58.9 % Preferred Stock 1.4 % 1.3 % 1.6 % 1.5 % 3.0 % 3.7 % Common Stock 59.8 % 58.7 % 45.2 % 41.4 % 29.3 % 28.3 % ------------ ------------ ------------ ------------ ------------ ------------ Total 100.0 % 100.0 % 100.0 % 100.0 % 100.0 % 100.0 % ============= ============ ============ =========== ============ ============ Miscellaneous Statistics Shares Outstanding (Average) 7,363,424 7,363,424 7,363,424 7,363,424 7,363,424 7,363,424 Shares Outstanding (Year End) 7,363,424 7,363,424 7,363,424 7,363,424 7,363,424 7,363,424 Number of Common Stockholders (Year End) 1 1 6,222 5,678 6,328 6,868 Basic Earnings (Loss) Per Common Share $ 1.66 $ 1.14 $ 1.47 $ 2.35 $ 1.39 $ (0.24) Diluted Earnings (Loss) Per Common Share $ 1.66 $ 1.08 $ 1.30 $ 2.08 $ 1.33 $ (0.24) Dividends Declared Per Common Share $ 1.29 $ 0.60 $ 0.80 $ 0.45 $ - $ - Book Value Per Common Share $ 17.65 $ 17.26 $ 18.66 $ 18.02 $ 16.14 $ 14.47 Return on Common Equity 9.46 % 6.30 % 7.98 % 13.81 % 9.11 % (1.64)% Ratio of AFDC to Common Stock Earnings 8 % 14 % 3 % (4)% 11 % (48)% Ratio of Earnings to Fixed Charges 2.35 % 1.89 % 2.11 % 2.25 % 1.59 % 0.86 % Payout Ratio 78 % 53 % 54 % 26 % - % - % Percentage of Construction Expenditures Funded Internally 100 % 100 % 100 % 100 % 100 % 100 % ============ ============ ============ ============ ============ ============ Residential Customer Data Average Number of Customers 94,510 93,398 92,656 91,726 90,888 90,433 Kilowatt-Hours per Customer 5,888 5,847 6,029 5,817 5,753 5,896 Revenue per Customer $ 552.52 $ 538.17 $ 623.23 $ 799.16 $ 785.54 $ 746.76 Revenue per Kilowatt-Hour in Cents 9.38 9.20 10.34 13.74 13.65 12.67 ============= ============= ============= ============= ============= ============= Miscellaneous System Data Net System Capability at Time of Peak (MW) Firm* n/a 182.23 98.98 273.72 381.54 344.44 System Peak Demand (MW) 290.26 290.37 304.71 293.08 281.63 277.06 Reserve Margin at Time of Peak** n/a % (37.2)% (67.5)% (6.6)% 35.5 % 24.3 % System Load Factor 68.0 % 68.4 % 70.8 % 74.5 % 75.4 % 79.5 % ============ ============ ============ ============ ============ ============ * The net system capability was reduced subsequent to the generation asset sale, which occurred in May 1999. As of 2002, BHE no longer provides generation capability to serve load. ** While the reserve margin at time of peak in 2001, 2000 and 1999 was negative, the system requirements were met through spot market purchases. As of 2002,BHE no longer provides generation capability to serve load. *** Subsequent to the generation asset sale in May 1999, Hydro generation was purchased.
ITEM 7 ------ MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Recent Events Affecting the Company ----------------------------------- REGULATORY PROCEEDINGS AND CORPORATE REORGANIZATION - As reported in the 2001 Form 10-K, on February 14, 2002, the Company presented to the Maine Public Utilities Commission (MPUC) a proposed resolution of the ongoing Alternative Rate Plan (ARP) proceeding that called for a multi- year freeze in the distribution portion of the Company's rates. The ARP proceeding, as well as proposed proceedings to implement a general increase in the Company's distribution rates and to initiate a management investigation of the Company, were suspended to provide the Company and interested parties additional time to negotiate a potential settlement of these interrelated proceedings. On April 25, 2002, the Company and other parties to the proceeding executed a stipulation to present to the MPUC a single comprehensive ARP applying to the Company's MPUC jurisdictional distribution revenue requirement and rates. On June 6, 2002, the MPUC approved the ARP and also dismissed the pending management investigation of the Company. The terms of the ARP include a rate plan to be in effect through December 31, 2007, with the Company's core distribution rates being adjusted downward on July 1 of each year from 2003 to 2007, at annual rates ranging from 2% to 2 3/4%. The Company is also allowed rate adjustments associated with certain specified categories of costs. The ARP also includes a mechanism whereby distribution returns on common equity outside of a certain range will be shared evenly between the Company and ratepayers. The Company is also required to meet certain customer service quality standards during the term of the ARP, and rate reduction penalties will result from not meeting the various performance measures as set forth in the stipulation. Finally, the ARP provides the Company with an accounting order allowing for the deferral of employee transition costs during 2002 and 2003 in connection with reductions in operating costs, which are discussed below. These deferred costs are being amortized over a ten year period, starting in June 2002. Successful implementation of the ARP necessitated a significant decrease in the Company's operating costs, and as a result, the Company reorganized its operations in 2002. The internal restructuring, which encompasses all aspects of the Company, has reduced operating costs by approximately 20%-25%. The Company is also beginning to transfer a portion of its fixed costs to variable costs, and improve processes to enhance long-term performance. As part of the restructuring, employment levels were reduced by approximately 25% in the second and third quarters of 2002 through early retirement and severance arrangements. Also in connection with the reorganization, the Company has adopted an Asset Management Model in order to improve efficiency and performance as well as lowering its operating costs. This model puts the principal of market based solutions into practice. The total employee transition costs incurred in 2002 were approximately $8.1 million and are recorded as a component of Other Regulatory Assets on the consolidated balance sheets at December 31, 2002. In February 2002, the MPUC issued an Order in connection with changes in the Company's stranded cost rates. As a result of the Order, and to recover the stranded costs created as a result of the restructuring of the electric utility industry in the State of Maine, the Company's stranded cost rates were increased effective March 1, 2002. The stranded cost rate increase resulted in the Company's total electric rates increasing by approximately 6.5%. The stranded cost rates are set for a period not to exceed three years, although the Company has the right to seek adjustments to these rates if certain economic situations occur. Also effective March 1, 2002, the Company is no longer responsible for being the standard-offer service provider. The Company, though, still has a standard-offer related power supply commitment with a third party through February 2004 amounting to approximately $57 million. The power delivered under this contract is being resold to one of the new standard-offer service providers, with estimated revenues to be realized of approximately $40 million. The difference between the cost of the power and the resale revenues are being recovered in the Company's stranded cost rates starting March 1, 2002. As a result of the Company no longer being the standard-offer provider effective in March 2002, and the previously discussed power contract obligation, there is an impact on the comparability of revenues and expenses for the 2002 periods presented in this filing in relation to 2001. REDEMPTION OF PREFERRED STOCK - As reported in its Current Report on Form 8-K dated December 9, 2002, the Company requested MPUC approval for authority to redeem all or a portion of its outstanding preferred stock. This approval was received on December 23, 2002. Also as reported in its Current Report on Form 8-K dated December 9, 2002, the Company was in the process of acquiring all or a portion of the shares through a tender offer and a call of the shares. In the first quarter of 2003 the Company completed the redemption of a significant portion of its outstanding preferred stock, at a total cost of approximately $4.7 million. As a result of these redemption's, the Company will now seek de-registration of its preferred stock. Results of Operations --------------------- EARNINGS - Basic earnings per common share were $1.66, $1.14, and $1.47, for the years ended 2002, 2001 and 2000, respectively. The earned return on average common equity was 9.5% in 2002, 6.3% in 2001 and 8% in 2000. The increase in earnings in 2002 in relation to 2001 was a result of many factors. The single largest item was the approximately $3.9 million in costs incurred in 2001 associated with the Company's merger with Emera ($.33 reduction in earnings per common share in 2001). Also, principally as a result of the Company's workforce reductions in 2002, labor expense was approximately $1.9 million lower in 2002 as compared to 2001 ($.15 increase in earnings per common share in 2002 as compared to 2001). In 2001, as a result of a settlement of certain issues with the parties participating in the Company's stranded cost rate filing with the MPUC, the Company charged to expense approximately $1.7 million ($.13 reduction in earnings per common share in 2001). Offsetting these year 2002 earnings enhancements to some extent was an approximately $961,000 increase in pension and other postretirement benefit costs in 2002 as compared to 2001 ($.08 reduction in earnings per common share in 2002). The reduction in earnings in 2001 as compared to 2000 was due to several factors, the largest of which being costs associated with the Company's merger with Emera in each year. In 2001, the Company incurred approximately $3.9 million ($.33 reduction in earnings per common share) of such costs as compared to $3 million in 2000 ($.24 reduction in earnings per common share). Also, as previously discussed, in 2001, the Company charged to expense approximately $1.7 million ($.13 reduction in earnings per common share) in connection with the stranded cost rate filing settlement. Finally negatively impacting earnings in 2001 was the establishment of a $615,000 reserve ($.05 reduction in earnings per common share) associated with adjustments to revenue related to filings with the New England Power Pool (NEPOOL). REVENUES - With the implementation of competition in the electric utility industry in the state of Maine starting March 1, 2000, and excluding the provision of standard-offer service through February 2002, the Company no longer sells electricity to customers. The Company's T&D and stranded cost charges to customers, though, continue to be based on customers' electricity usage measured in kilowatt-hours (kWh). Consequently, discussion related to electric operating revenues will continue to have a kWh sales, or hereafter referred to as "energy sales" component. Electric operating revenues are as follows for 2002 as compared to 2001: 2002 2001 Change Residential $ 53,460,057 $ 51,011,678 $2,448,379 Commercial 39,990,493 37,908,435 2,082,058 Industrial 10,335,054 9,895,889 439,165 Other 1,945,380 1,875,277 70,103 ---------------------------------------- Subtotal $105,730,984 $100,691,279 $5,039,705 Large Special Contracts 5,163,127 5,554,793 -391,666 ---------------------------------------- Total Related to Energy Sales $110,894,111 $106,246,072 $4,648,039 Other Miscellaneous Revenues 4,935,070 7,620,164 -2,685,094 ---------------------------------------- Total Electric Operating Revenue $115,829,181 $113,866,236 $1,962,945 ---------------------------------------- Energy sales volume in gigawatt hours is as follows for each of 2002 and 2001: 2002 2001 Change Residential 566.6 554.1 12.5 Commercial 583.5 584.9 -1.4 Industrial 196.5 206.1 -9.6 Other 11.9 11.5 .4 ---------------------------------------- Subtotal 1,358.5 1,356.6 1.9 Large Special Contracts 243.2 251.9 -8.7 ---------------------------------------- Total Energy Sales 1,601.7 1,608.5 -6.8 ---------------------------------------- Electric operating revenue increased by approximately $2 million in 2002 as compared to 2001. The increase was principally the result of the previously discussed 6.54% rate increase associated with stranded cost recovery. Also impacting the increased revenues somewhat in 2002 was a .14% increase in energy sales, which excludes certain large special contract customers. Other miscellaneous revenues were lower in 2002 as a result of a $1.8 million reduction in certain stranded cost related revenue deferrals. The decrease is due to the implementation of new stranded cost rates on March 1, 2002, as well as the impact of the previously discussed loss in 2001 associated with the settlement of the stranded cost rate filing. Also, other revenues associated with charging electric generators for wheeling power over the Company's transmission lines and out of its service territory were approximately $2.1 million lower in 2002 compared to 2001. The decrease is due primarily to the fact that the new standard offer service provider is purchasing power from the Company to resell to standard offer customers in the Company's service territory that, prior to March 1, 2002, was wheeled outside of the service territory. Off-system sales, which are sales related to power pool and inter- connection agreements and resales of purchased power, were approximately $20.8 million greater in 2002 in relation to 2001. The increase is due principally to the previously discussed resale of power associated with the former standard-offer power supply contract. The $72.4 million decrease in standard-offer service revenues in 2002 is due mostly to the Company no longer being the standard-offer provider effective March 1, 2002. With the implementation of retail competition effective March 1, 2000, comparisons of electric operating revenues for 2001 as compared to 2000 are difficult. Total electric operating revenues, including standard- offer service, increased by approximately $5.1 million, or 2.4%, in 2001 in comparison to 2000. Principally as a result of increases in standard-offer service rates as ordered by the MPUC in 2000 and 2001, electric operating revenues attributable to energy sales were approximately $13.6 million higher in the 2001. From the March 1, 2000 through March 1, 2001, the cumulative increase in standard-offer service rates was approximately 60%. This impact of the increased standard-offer rates was offset to some extent by an 8% reduction in total energy sales in 2001, due principally to the shutdown of the Company's largest retail customer, HoltraChem Manufacturing Company (HoltraChem) in September 2000, the weak economy in the Company's service territory and by the impacts of warmer than average weather in 2001. Effective July 1, 2001, and providing for an increase in revenues, the Company entered into a special rate contract with a large industrial customer to provide fully bundled electric service (both T&D and energy) to this customer. Formerly, the Company was only providing T&D service to this customer. The Company entered into a power purchase contract to procure the power necessary to serve this customer under this contract. Principally as a result of the new contract, the Company recognized approximately $2.8 million in greater electric operating revenues associated with this customer in 2001 as compared to 2000. Other revenues, which decreased by approximately $8.3 million in the 2001 period, were most affected by a $11.8 million reduction in revenues associated with the standard-offer service deferral mechanism. In 2001, the Company's energy sales related to standard-offer revenues were greater than the associated costs of providing the standard-offer service, and consequently the Company's recorded reductions in other revenues of approximately $8.8 million. In the 2000 period, starting March 1, the Company recorded additional other revenues of approximately $3 million as a result of standard-offer costs exceeding energy sales related standard-offer revenues. The decreased other revenues in 2001 were offset to some extent by Holtrachem revenue sharing, which was a $1.1 million reduction in revenues in 2000, while, as a result of the Holtrachem plant shutdown, there was no revenue sharing in 2001. As a result of the February 2000 rate order from the MPUC, the Company's overall rates, including the impact of the initial standard- offer prices, were reduced by approximately 2.9% starting March 1, 2000. The Company also implemented various rate changes for its standard-offer service as approved by the MPUC. The result of these standard-offer rate changes for the period from March 1 through October 1, 2000 was an increase in the standard-offer prices of 36% for residential and small commercial customers and 25% for large industrial customers as compared to the prices when initially set by the MPUC on March 1, 2000. EXPENSES - Total fuel for generation and purchased power expense, excluding the standard offer, increased approximately $27 million in 2002 as compared to 2001. The largest item affecting the increased expense was approximately $29.8 million of costs in 2002 associated with the previously discussed former standard-offer power contract obligation. Also, the Company incurred approximately $1.8 million in greater expense in 2002 associated with other power purchases under long-term contracts with small power production facilities, resulting from increased generation in 2002. Offsetting these increases somewhat was an approximately $1.3 million decrease in Maine Yankee costs in 2002. Also there was a $1.2 million decrease in purchased power costs in 2002 in connection with serving a portion of a power sale contract. This reduction was due to decreases in the market prices of power in 2002 as compared to 2001. Finally, effective July 1, 2001, and running through February 28, 2002, the Company entered into a special rate contract with a large industrial customer to provide fully bundled electric service (both T&D and energy) to this customer. Formerly, the Company was only providing T&D service to this customer. The Company entered into a power purchase contract to procure the power necessary to serve this customer under this contact. In the 2001 period the Company incurred approximately $1.5 million in greater purchased power costs associated with serving the customer as compared to the 2002 period. The $71.3 million decrease in standard-offer service purchased power expense in 2002 is due mostly to the Company no longer being the standard-offer provider effective March 1, 2002. Total fuel for generation and purchased power expense, including the standard offer, increased approximately $7.4 million in 2001 as compared to 2000. Standard offer purchased power expense for the comparable periods of March through December of each year was $3.5 million higher in 2001. The increase is due to higher power prices, offset by reductions in standard offer sales. Also, in connection with the previously discussed new special rate contract with a large industrial customer, in 2001 the Company incurred $2.3 million of purchased power expense associated with serving this customer. Further increasing purchased power expense in 2001 was the loss in connection with the stranded cost rate settlement. Also increasing purchased power expense was the recording of a $615,000 reserve associated with adjustments to revenue related to filings with the NEPOOL. Finally, in the first two months of 2001, purchased power costs were also higher, since the Company purchased significantly more power on the spot power market as compared to 2000 as a result of the expiration of the power contracts that had been in place in the 2000 period. Further, the market prices for power were higher due to higher fuel prices and possibly lack of sufficient competition in the generation market. Offsetting these increases to some extent in 2001 were lower transmission related costs, including those associated with NEPOOL. In 2001, the Company also realized reduced transmission costs as a result of the construction of additional qualifying transmission facilities whose costs are recoverable from the other NEPOOL transmission owners. Other operation and maintenance (O&M) expense decreased by approximately $2.2 million in 2002 as compared to 2001. Principally as a result of the workforce reductions in 2002, O&M payroll expense was approximately $1.9 million lower in 2002 relative to 2001. Also, as a result of cost reduction efforts in 2002, other O&M non- labor expenses were generally lower as compared to 2001. Due principally to a refocus of the Company's line clearance program (tree trimming) in 2002, the associated expense was approximately $864,000 lower in 2002 as compared to 2001. These decreases in other O&M expense were offset somewhat by the previously discussed $961,000 increase in pension and other postretirement benefit costs in 2002 as compared to 2001. The increased expense is principally attributable to decreases in the discount rate used to actuarially compute the expense as well as reduced expected returns on plan assets as a result of poor stock market performance. Other O&M expense increased by approximately $1.5 million in 2001 relative to 2000. The single largest item impacting the increased expense was related to pension expense, which was approximately $1.4 million greater in 2001 as compared to 2000. This was due principally to changes in actuarial assumptions used in calculating pension expense and the end of the amortization of the transition pension benefit in 2001. Also in 2001, bad debt expense increased by approximately $610,000 due to the write-off of amounts associated with the Chapter 11 bankruptcy filing of a large industrial customer, a greater level of write-offs of standard offer receivables and in 2000 bad debt expense was reduced by a $200,000 decrease in the reserve for bad debts. These increases were offset to some extent by a reduction in legal and regulatory related costs in 2001, as there was a greater level of regulatory activities in 2000 in relation to 2001. Depreciation and amortization expense increased by approximately $525,000 in 2002 relative to 2001 and by approximately $866,000 in 2001 as compared to 2000 due principally to additions to the Company's electric plant in service in both 2002 and 2001. The Company is in the process of conducting a depreciation study to determine the appropriate useful lives for its plant assets as well as the propriety of the level of the Company's depreciation reserve, with an anticipated completion in 2003. Management cannot predict the results of the study or how the results will be implemented within the context of the Company's ARP. The Company's expenses over the period 2000-2002 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 have been deferred, and appear on the Consolidated Balance Sheets as assets on the strength of the regulatory authority to amortize them and to collect these amounts from customers (thus the term "regulatory assets"). Although there are a number of such authorized amortizations, the major ones include the amortization of purchased power contract buyouts/restructurings, Seabrook investment, deferred asset sale gain, and deferred employee transition costs. For a discussion of these regulatory assets and liabilities, see Notes 7 and 10 to the consolidated financial statements. Effective March 1, 2000, in connection with the implementation of new electric rates associated with the electric utility industry restructuring, the Company began amortizing certain stranded cost related regulatory assets and liabilities that had been previously deferred on the Company's balance sheets. Also, effective March 1, 2002, with the implementation of new stranded cost electric rates, certain of the previous amortizations were adjusted, and also the Company began amortizing new stranded cost related regulatory assets and liabilities that had been previously deferred on the Company's balance sheets since March 1, 2000. The following summarizes the components of the regulatory amortizations for 2002, 2001 and 2000: 2002 2001 2000 Contract buyouts and restructuring $20,274,191 $22,557,124 $22,311,448 Seabrook investment 1,699,050 1,699,050 1,699,050 Deferred asset sale gain (4,681,324) (8,076,133) (6,393,038) Other stranded cost related regulatory assets and liabilities (4,921,047) 386,908 382,295 Distribution related regulatory assets and liabilities 1,159,530 1,159,530 1,153,687 Employee transition costs 458,021 - - ------------------------------------- Total Regulatory Amortizations $13,988,421 $17,726,479 $19,153,442 ------------------------------------- The decrease in property and other taxes in 2002 in comparison to 2001 was principally due to a reduction in payroll taxes, resulting from the previously discussed corporate downsizing in 2002. This was offset somewhat by increased property taxes in 2002 caused by increases to electric plant in service and higher property tax rates. In December 2002, the Company filed with the Internal Revenue Service (IRS) a request for a change in the accounting for costs capitalized for income tax reporting purposes. This request, if accepted, could result in an approximately $6.7 million reduction in current income tax obligations. Management cannot predict the outcome of this filing with the IRS. The increase in property and other taxes in 2001 relative to 2000 was due primarily to higher property taxes, resulting from electric plant additions and increased property tax rates. The decrease in total federal and state income taxes in 2002 relative to 2001 was principally a function of the impact of $183,000 in additional income tax expense in 2001 in connection with disallowed investment tax credits, as well as adjustments in 2002 as a result of filing the year 2001 income tax returns. These decreases were offset by higher earnings in 2002. See Footnote 3 to the Consolidated Financial Statements for a reconciliation of the Company's effective income tax rate. The decrease in total federal and state income taxes for 2001 as compared to 2000 was principally a function of lower earnings in 2001 as compared to 2000. OTHER INCOME AND (DEDUCTIONS) AND INTEREST EXPENSE - Allowance for funds used during construction (AFDC), which includes carrying costs on certain regulatory assets and liabilities, decreased by approximately $219,000 in 2002 relative to 2001. The decrease was primarily a result of the implementation of new stranded cost rates on March 1, 2002, whereby the rate recovery of various regulatory assets began and the accrual of carrying costs ended. AFDC increased by $835,000 in 2001 relative to 2000 due mainly to approximately $526,000 in carrying costs being recorded on the deferred asset sale gain in 2000. The Company also recorded increased carrying costs on exercised Penobscot Energy Recover Company (PERC) common stock warrants in 2001 relative to 2000. Offsetting these increases to some extent was less AFDC associated with lower levels of construction in 2001. Other income, net of income taxes increased by approximately $2.1 million in 2002 compared to 2001. The increase is due mostly to the previously discussed $3.9 million in merger related costs incurred in 2001. Other income, net of income taxes decreased by approximately $1.7 million in 2001 in comparison to 2000 principally as a result of a $1.2 million gain on the sale of the Company's formerly wholly-owned subsidiary Penobscot Gas in 2000. Also merger related costs were $3.9 million in 2001 as compared to $3 million in 2000. Finally, investment income was lower in 2001 due principally to reductions in the Company's available cash balances from the 1999 generation asset sale. Long-term debt interest expense decreased $1.7 million in 2002 relative to 2001 due principally to repayments on the Company's long-term debt in each year. In June 2002 and 2001, the Company made $16.1 million and $15.1 million in principal payments, respectively, on the Company's Finance Authority of Maine (FAME) Revenue Notes. Also, monthly principal payments on the $24.8 million medium term notes, which were fully repaid in July 2002, amounted to approximately $5.5 million and $6.2 million, respectively, in 2002 and 2001. Also reducing 2002 long- term debt interest expense was the retirement of the $20 million in 7.38% first mortgage bonds at the end of July 2002. These decreases were offset to some extent by additional interest expense in 2002 resulting from the issuance of a $13.7 million note in October 2001 with the Municipal Review Committee (MRC) in connection with the exercise of common stock warrants. Long-term debt interest expense decreased $1.4 million in 2001 in relation to 2000 due primarily to the 2001 repayments on the Company's long-term debt discussed above, as well as debt repayments in 2001. In June 2000, the Company made a $14 million principal payment on the FAME Revenue Notes. Also, monthly principal payments on the $24.8 million medium term notes amounted approximately $5.5 million in 2000. These were offset to some extent by interest expense in 2001 associated with the $13.7 million MRC note issued in October 2001. Other interest expense increased approximately $170,000 in 2002 relative to 2001 principally to higher interest expense as a result of increased borrowings under the Company's revolving credit facility. Weighted average borrowings outstanding were approximately $21.8 million in 2002 as compared to $3 million in 2001. The increased borrowings were necessitated to some extent by the funding of debt service payments ($16.1 million in principal plus interest) on the FAME Revenue Notes at the end of June 2002 and the retirement of $20 million in 7.38% first mortgage bonds in July 2002. Also, other interest expense was impacted somewhat by a $125,000 reduction in amortization of debt issuance costs in 2002 due to the expiration of certain amortizations and lower short-term interest rates in 2002. Other interest expense increased by approximately $116,000 in 2001 in relation to 2000 due principally to borrowings and fees under the Company's revolving credit facility. In 2000 there were no borrowings under the revolving credit facility. This was offset to some extent by a reduction in the amortization of debt issuance costs in 2001 as a result of the end of the amortization period of certain deferred debt issuance costs in June 2001 and June 2000. Liquidity, Capital Requirements, and Capital Resources ------------------------------------------------------ The Consolidated Statements of Cash Flows reflect events for the years ended December 2002, 2001 and 2000 as they affect the Company's liquidity. Net cash provided by operations was approximately $33.9 million in 2002, $25.3 million in 2001 and $37.6 million in 2000. The approximately $8.6 million increase in operating cash flows in 2002 relative to 2001 was due to several factors. The single largest item affecting the comparability of operating cash flows in the two years was approximately $14.2 million in payments in 2001 in connection with the exercise of the Company's common stock warrants (See Note 7 to the Consolidated Financial Statements). Also increasing operating cash flows in 2002 as compared to 2001 was the impact of the approximately $3.9 million in incremental merger related costs that were incurred in 2001. Operating cash flows are also impacted in each period by the standard-offer service. In 2002, the Company's standard-offer service costs exceeded revenues by approximately $2.1 million, while in 2001, revenues exceeded associated costs by approximately $8.8 million. Changes in accounts receivable and accounts payable in the statement of cash flows are also greatly impacted by the standard-offer related revenues and purchased power obligations. Negatively impacting operating cash flows in 2002 was $3.5 million in payments associated with benefits provided to terminated employees in connection with the previously discussed cost reduction efforts. The approximately $12.3 million reduction in operating cash flows in 2001 in relation to 2000 was the result of several factors. The largest single item impacting this change was cash payments to the PERC common stock warrant holders in connection with the exercise of warrants in each period. In 2001 approximately $14.2 million in payments were made to the holders of the warrants, while in 2000 these payments amounted to only $2.1 million. Cash flows from operations were further impacted in 2001 by lower earnings as compared to the year 2000. Operating cash flows are also impacted in both 2001 and 2000 by the standard-offer service. In 2001, the Company's standard-offer service revenues exceeded associated costs by approximately $8.8 million, while in 2000, the costs exceeded revenues by approximately $3 million. Changes in accounts receivable and accounts payable in the statement of cash flows are also greatly impacted by the standard-offer related revenues and purchased power obligations. Also cash flows were negatively impacted by a $.008/kWh rate reduction provided to certain large customers starting in April 2001. While the earnings impact of the rate discounts is negated by additional asset sale gain amortization to offset the rate discounts, cash flows are negatively impacted by providing the $2.5 million in rate discounts over the 10 1/2 month period the reduced rates were in effect. Enhancing cash flows to some extent in 2001 was the receipt in October 2001 of $2.6 million associated with the settlement of a dispute regarding the sale of a jointly owned property in which the Company had an interest. See Note 10 to the Consolidated Financial Statements for a discussion of this transaction. The following summarizes the Company's capital expenditures for each of 2002, 2001 and 2000: ($000's) 2002 2001 2000 Electric distribution system $ 7,916 $ 9,513 $ 8,188 Electric transmission system 1,415 1,590 4,184 Other, including general property and software 763 5,245 4,309 -------------------------------- Total capital expenditures $10,094 $16,348 $16,681 -------------------------------- Other capital expenditures in 2001 and 2000 included significant amounts in connection with customer information system changes necessitated by the restructuring of the electric industry on March 1, 2000. The Company expects its capital expenditures to total between $35 and $40 million over the next three years, although it may be necessary to adjust the budget for capital expenditures on a year-to- year basis. As previously discussed, in July 2000 the Company received $1.25 million in connection with the sale of Penobscot Gas. In 2002, the Company made $9.5 million in common dividend payments to its parent company, Emera, while in 2001, four quarterly common dividend payments of $.20 per share were paid to previous common shareholders. The increase in dividends paid on common stock in 2001 as compared to 2000 was due to an increase in the common dividend from $.15 to $.20 per share in March 2000. The increase in payments on long-term debt in 2002 was due principally to higher monthly principal payments on the $24.8 million medium term notes in 2002 as compared to 2001, and at the end of June 2002 the Company made a $16.1 million principal payment on the FAME revenue notes, as compared to a $15.1 million principal payment at the end of June 2001. Also, in July 2002 the Company retired $20 million of 7.38% first mortgage bonds. Finally, the Company made approximately $1.5 million of principal payments in 2002 on the $13.7 million MRC note as compared to approximately $433,000 in payments in 2001. In 2000, the Company made $19.5 million in repayments on long-term debt, including a $14 million principal payment at the end of June 2000 on the FAME Revenue Notes and $5.5 million in payments on the $24.8 million medium term notes. In connection with the final principal and interest payment on the $24.8 million medium term notes in 2002, the Company utilized $1.5 million of funds that had been maintained in a capital reserve fund since this debt had been issued in 1998. As discussed in Note 5 to the consolidated financial statements, in December 2002, the Company received $20 million in proceeds in connection with the issuance of 6.09% senior unsecured notes. The proceeds were utilized to paydown outstanding amounts under the Company's revolving credit facility. The Company had maintained full borrowing capacity under its revolving credit facility from the second quarter of 1999 through June 2001, but it became necessary to renew borrowings under the revolving line in June 2001 to fund the required FAME debt payment of $15.1 million. The Company's utilization of the line of credit was also impacted by the merger costs in 2001 and the cash payments to common stock warrant holders. The Company's borrowings under this arrangement amounted to $8 million at December 31, 2001. On June 29, 2001, the Company extended the revolving credit agreement until October 1 and then until March 31, 2002, and the agreement was further extended until June 30, 2003 with some modifications. The facility was increased to $60 million to accommodate the certain debt retirements in 2002, another pricing level was added to recognize the Company's improved credit and certain modifications were made to some of the financial covenants. Also, the Company entered into a promissory note that allows the Company to borrow up to an additional $10 million. This unsecured facility is used by the Company to manage working capital needs, and the interest rate setting mechanism and other major terms of the note are similar to terms in the revolving credit agreement. The Company's outstanding borrowings under these short-term borrowing facilities amounted to $16 million at December 31, 2002. Capital and operating needs in 2002, 2001 and 2000 were met through internally generated funds, the Company's revolving credit line and generation asset sale proceeds. Under the current projections of cash needs, the new credit facilities discussed above should provide adequate borrowing capacity or other longer-term financing vehicles. The Company has approximately $81.2 million of first mortgage bonds and other long-term debt maturities in the period 2003-2007. CONTRACTUAL CASH OBLIGATIONS AND OTHER COMMERCIAL COMMITMENTS - The following tables quantify the Company's future contractual obligations and commercial commitments as of December 31, 2002 ($ in 000's): Payments Due by Period ---------------------- Less than After 5 Contractual Obligations: Total 1Year 1-3 years 4-5 years years ----------------------- ----- ----- --------- --------- ----- Long-term Debt $152,196 $34,137 $43,661 $ 5,276 $ 69,122 Operating Leases 2,242 860 993 389 - Long-term Purchased Power Commitments 278,992 22,516 35,541 31,365 189,570 -------- ------- ------- -------- ------- Total Contractual Cash Obligations $433,430 $57,513 $80,195 $37,030 $258,692 ======== ======= ======= ======= ======== See Notes 5 and 7 to the consolidated financial statements for a discussion of the Company's long-term debt obligations and long-term purchased power contract commitments. Amount of Committed Expiration per Period ----------------------------------------- Total Other Commercial Amounts Less than After 5 Commitments: Committed 1Year 1-3 years 4-5 years years ----------- --------- ----- --------- --------- ----- Lines of Credit $54,000 $54,000 $ - $ - $ - ------- ------- -------- -------- ------- Total Commercial Commitments $54,000 $54,000 $ - $ - $ - ======= ======= ======== ======== ======= See Note 5 to the consolidated financial statements for a discussion of the Company's short-term credit facilities. Other Matters MAINE YANKEE - TERMINATION OF DECOMMISSIONING OPERATIONS CONTRACT - In May 2000 Maine Yankee terminated its decommissioning operations contract with Stone & Webster Engineering Corp. (Stone & Webster) pursuant to the terms of the contract. Stone & Webster disputed Maine Yankee's grounds for the termination. In June 2000 Stone & Webster filed a voluntary petition under Chapter 11 of the United States Bankruptcy Code with the United States Bankruptcy Court for the District of Delaware. Upon the contract termination Maine Yankee temporarily assumed the general contractor role and entered into interim agreements with Stone & Webster and obtained assignments of several subcontracts in order to allow decommissioning work to continue and to avoid the adverse consequences of an abrupt or inefficient demobilization from the Plant site. After assessing its long-term alternatives for safely and efficiently completing the decommissioning, including evaluating proposals from prospective successor general contractors, on January 26, 2001 Maine Yankee announced that it would continue to manage the project itself. In June 2000 Federal Insurance Company (Federal), which had provided performance and payment bonds in the amount of approximately $38.5 million each in connection with the decommissioning operations contract, filed a declaratory- judgment complaint against Maine Yankee in the Bankruptcy Court in Delaware, which was subsequently transferred to the United States District Court in Maine. The complaint alleged that Maine Yankee had improperly terminated the decommissioning operations contract with Stone & Webster and had failed to give proper notice of the termination to Federal under the contract, and that Federal had no further obligations under the bonds. After extensive discovery and resolution of certain preliminary issues by the court, in December 2001 Maine Yankee and Federal entered into a settlement agreement pursuant to which Federal paid Maine Yankee $44 million on January 18, 2002. The settlement was reflected on Maine Yankee's 2001 financial statements. That amount represented full payment under the performance bond, plus an additional amount under the payment bond reflecting certain payments previously made by Maine Yankee to subcontractors and suppliers who had not been fully paid by Stone & Webster. Maine Yankee deposited the payment in its decommissioning trust fund to offset past and future expenses resulting from the failures of Stone & Webster. In addition, Maine Yankee has continued to pursue its claims for damages that was originally filed against Stone & Webster and its parent corporations in August 2000 in the Bankruptcy Court in Delaware. After recognizing the payment from Federal, Maine Yankee asserted a right to recover an additional $21 million in that court from the bankrupt estates. In February 2002 Stone & Webster filed a claim for approximately $7 million against Maine Yankee in the Bankruptcy Court in Delaware for alleged breaches of contract and to subordinate any Maine Yankee claims. On May 30, 2002, the court concluded extensive hearings and argument by allowing a claim in favor of Maine Yankee under section 502(c) of the Bankruptcy Code, in the estimated amount of $20.8 million against each of the three principal bankrupt estates (jointly and severally). The Court's ruling also effectively precluded approximately $4 million of Stone & Webster's February 2002 claim against Maine Yankee, while offering no opinion or findings on the remainder, the resolution of which will, if necessary, be the subject of further proceedings. The actual cash amount to be recovered by Maine Yankee on this allowed claim remains contingent on a number of factors beyond Maine Yankee's control, including without limitation the extent to which the bankrupt estates ultimately have assets available to pay the claim, the final disposition of Stone & Webster's February 2002 claim, and possible reconsideration of the ruling in the future based on actual expenses of completing the decommissioning. Maine Yankee therefore cannot predict the final outcome of the Bankruptcy Court proceeding. MAINE YANKEE - NUCLEAR FUEL STORAGE - Federal legislation enacted in 1987 directed the Department of Energy (DOE) to proceed with the studies necessary to develop and operate a permanent high-level waste (spent fuel) repository at Yucca Mountain, Nevada. The project has encountered delays, and the DOE has indicated that the permanent disposal site is not expected to open before 2010, although originally scheduled to open in 1998. In accordance with the process set forth in the legislation, in February 2002 the Secretary of Energy recommended the Yucca Mountain site to the President for the development of a nuclear waste repository, and the President then recommended development of the site to the Congress. As provided in the statutory procedure, the State of Nevada formally objected to the site in April 2002, and in July 2002 the Congress overrode the objection. Construction of the repository requires the approval of the Nuclear Regulatory Commission (NRC), upon application of the DOE and after a public adjudicatory hearing, as well as a second NRC approval after completion of construction to operate the facility. The Company cannot predict the timing or results of those proceedings. In November 1997 the U.S. Court of Appeals for the District of Columbia Circuit confirmed the obligation of the DOE under the Nuclear Waste Policy Act of 1982 to take responsibility for spent nuclear fuel from commercial reactors in January 1998. After an unsuccessful effort by Maine Yankee in the same court to compel the DOE to take Maine Yankee's spent fuel, in June 1998 Maine Yankee filed a claim for money damages in the U.S. Court of Federal Claims for the costs associated with the DOE's default. In November 1998 the Court granted summary judgment in favor of Maine Yankee, ruling that the DOE had violated its contractual obligations, but leaving the amount of damages incurred by Maine Yankee for later determination by the Court. Since then the parties have been engaged in extensive discovery and resolution of pre-trial issues in the damages phase of the proceeding. Maine Yankee is pursuing its claim for determination of damages vigorously, but cannot predict the outcome or timing of the determination. At the same time, as an interim measure until the DOE meets its contractual obligation to dispose of Maine Yankee's spent fuel at Yucca Mountain or elsewhere, the Company constructed an independent spent fuel storage installation (ISFSI), utilizing dry-cask storage, on the Plant site and is in the process of transferring the spent fuel from the spent-fuel pool to the individual casks and the casks to the ISFSI. The company's total cost of maintaining the ISFSI will be substantially affected by heightened security costs and by the length of time it is required to operate the ISFSI before the DOE honors its contractual obligation to take the fuel from the site. The Company's current decommissioning cost estimated is based on an assumption that its operation of the ISFSI will end in 2023, but the actual period of operation and cost may vary. On January 15, 2003, the Company notified NAC International (NAC), the contractor responsible for providing for the fabrication of the spent- fuel casks and transferring the fuel to the casks and the casks to the ISFSI, that the Company was terminating its contract with NAC pursuant to the terms of the contract. NAC had been experiencing financial difficulties and had requested relief from the terms of the contract. Maine Yankee believes that NAC had also failed to perform its contractual obligations in accordance with the terms of the contract and provide adequate assurance of its ability to do so in the future. NAC has indicated that it disputes Maine Yankee's basis for terminating the contract and has served Maine Yankee with a demand to arbitrate the dispute, while at the same time the parties have been in negotiations to resolve the situation. In the meantime, Maine Yankee has entered into contracts with the major subcontractors and resumed the transfer of fuel to the ISFSI under its own management. Maine Yankee believes that its termination of the NAC contract was legally justified, but cannot predict the outcome of the negotiations or arbitration proceeding. In connection with the state of Maine's electric industry restructuring law, the Company was allowed the recovery of Maine Yankee decommissioning costs as a component of its stranded costs. In the Company's stranded cost rate orders from the MPUC that became effective on March 1, 2000 and 2002, the Company was allowed to defer the amount of any future FERC ordered changes in Maine Yankee's decommissioning collections. Consequently, management does not believe that Maine Yankee's decommissioning contractor difficulties or nuclear fuel storage issues will have a material adverse impact on the Company's results of operations, financial condition or cash flows. ENVIRONMENTAL MATTERS - The Company is regulated by the United States Environmental Protection Agency (EPA) as to compliance with the Federal Water Pollution Control Act, the Clean Air Act, and several federal statutes governing the treatment and disposal of hazardous wastes. The Company is also regulated by the Maine Department of Environmental Protection (DEP) under various Maine environmental statutes. The Company is actively engaged in complying with these federal and state acts and statutes, and it has not, to date, encountered material difficulties in connection with such compliance. In 1992, the Company received notice from the DEP that it was investigating the cleanup of several sites in Maine that were used in the past for the disposal of waste oil and other hazardous substances, and that the Company, as a generator of waste oil that was disposed at those sites, may be liable for certain cleanup costs. The Company learned in October 1995 that the EPA placed one of those sites on the National Priorities List under the Comprehensive Environmental Response, Compensation and Liability Act and would pursue potentially responsible parties. With respect to this site, the Company is one of a number of waste generators under investigation. The Company has recorded a liability, based upon currently available information, for what it believes are the estimated environmental remediation costs that the Company expects to incur for this waste disposal site. Additional future environmental cleanup costs are not reasonably estimable due to a number of factors, including the unknown magnitude of possible contamination, the appropriate remediation methods, the possible effects of future legislation or regulation and the possible effects of technological changes. At December 31, 2002, the liability recorded by the Company for its estimated environmental remediation costs amounted to approximately $411,000. The Company's actual future environmental remediation costs may be different as additional factors become known. In 2002 the Company expended approximately $171,000 in operations to comply with environmental standards for air, water and hazardous materials. NEW ACCOUNTING PRONOUNCEMENT - In June 2002, the Financial Accounting Standards Board issued Statement No. 143, "Accounting for Asset Retirement Obligations". This Statement addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. It applies to legal obligations associated with the retirement of long- lived assets that result from acquisition, construction, development and (or) the normal operation of a long-lived asset, except for certain obligations of lessees. This Statement is effective for financial statements issued for fiscal years beginning after June 15, 2002. Management does not believe that the implementation of this Statement will materially impact the Company's financial position, earnings or cash flows, principally as a result of the regulatory accounting utilized by the Company. In November 2002, the Financial Accounting Standards Board issued Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" (FIN 45). Along with new disclosure requirements, FIN 45 requires guarantors to recognize at the inception of certain guarantees a liability for the fair value of the obligation undertaken in issuing the guarantee. This differs from the current practice to record a liability only when a loss is probable and reasonably estimable. The recognition and measurement provisions of FIN 45 are applicable on a prospective basis to guarantees issued or modified after December 31, 2002. The adoption of FIN 45 is not expected to have a material effect on the Company's results of operations or financial position. In December 2002, the Financial Accounting Standards Board issued Interpretation No. 46, "Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51" (FIN 46). FIN 46 requires certain variable interest entities to be consolidated by the primary beneficiary of the entity if the equity investors in the entity do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from the other parties. FIN 46 is effective for all new variable interest entities created or acquired after January 31, 2003. For variable interest entities created or acquired before February 1, 2003, the provisions of FIN 46 must be applied for the first interim or annual period beginning after June 15, 2003. Management is currently evaluating the impact of the adoption of FIN 46 and does not anticipate that it will have a material effect on the Company's result of operations or financial position. CRITICAL ACCOUNTING POLICIES - We prepare our financial statements in conformity with accounting principles generally accepted in the United States. Judgments and uncertainties about the application of these accounting policies along with estimates and other assumptions may affect reported results. Regulation - As a regulated electric utility, the Company prepares its financial statements in accordance with Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation", (SFAS No. 71) for its regulated business. In order for a Company to report under SFAS No. 71, the Company's rates must be designed to recover its costs of providing service and must be able to collect those rates from customers. If rate recovery becomes unlikely or uncertain, whether due to competition or regulatory action, this accounting standard would no longer apply to the Company's regulated operations. In the event the Company determines that it no longer meets the criteria for applying SFAS No. 71, the accounting impact would be an extraordinary non-cash charge to operations of an amount that could be material. Management periodically reviews these criteria to ensure the continuing application of SFAS No. 71 is appropriate. Based on a current evaluation of the various factors and conditions that are expected to impact future cost recovery, Management believes future recovery of its regulatory assets are probable. Pension and Other Postretirement Benefits - Assumptions used in determining projected benefit obligations and the fair values of plan assets for the Company's pension plans and other postretirement benefit plans are evaluated periodically by management in consultation with outside actuaries. Changes in assumptions are based on relevant company data, such as rate of increase in compensation levels and the long-term rate of return on plan assets. Critical assumptions, such as the discount rate used to measure the benefit obligations, the expected long-term rate of return on plan assets and health care cost projections, are evaluated and updated annually. The Company has assumed that the expected long-term rate of return on plan assets will be 8%, a 1% reduction from the assumption utilized in 2001. At the end of each year, the Company determines the discount rate that reflects the current rate at which pension liabilities could be effectively settled. This rate should be in line with rates for high quality fixed income investments available for the period to maturity of the pension benefits, and changes as long-term interest rates change. At year-end 2002, we determined this rate to be 6.75%. Postretirement benefit plan discount rates are the same as those used by our defined benefit pension plan in accordance with the provisions of Statement of Financial Accounting Standards No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions". In the fourth quarter of 2002, the Company recorded a non-cash adjustment to equity through other comprehensive loss of approximately $2 million to reflect additional minimum pension liability. Based on the current assumptions, as well as the impact of recent market declines in the value of pension assets, the Company estimates that the pension expense for 2003 will increase approximately $1.5 million over the 2002 expense. Also, the Company will be required to start making contributions to its pension plan in 2003, amounting to approximately $2.1 million. The trend in health care costs is difficult to estimate and it has an important effect on postretirement liabilities. The 2002 health care cost trend rate, which is the weighted average annual projected rate of increase in the per capita cost of covered benefits, was 9%. This rate is assumed to decrease to 5% by 2008 and then remain at that level. Other - 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. We reserve an estimate for potential uncollectible customer accounts based on historical uncollectible experience and specific customer identification where practical. 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. Income taxes are recorded in accordance with SFAS No. 109, "Accounting for Income Taxes." FORWARD LOOKING STATEMENTS - Management's discussion and analysis of results of operations and financial condition contains items that are "forward-looking" as defined in the Private Securities Litigation Reform Act of 1995. These statements are subject to certain risks and uncertainties that could cause actual results to differ materially from those anticipated in the forward-looking statements. Readers should not place undue reliance on forward-looking statements, which reflect management's view only as of the date hereof. The Company undertakes no obligation to publicly revise these forward-looking statements to reflect subsequent events or circumstances. Factors that might cause such differences include, but are not limited to, the Company's merger with Emera, future economic conditions, relationships with lenders, earnings retention and dividend payout policies, developments in the legislative, regulatory and competitive environments in which the Company operates and other circumstances that could affect revenues and costs. ITEM 7A QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK The Company's major financial market risk exposure is changing interest rates. Changes in interest rates will affect interest paid on variable rate debt and the fair value of fixed rate debt. The Company manages interest rate risk through a combination of both fixed and variable rate debt instruments. The Company also was a party to an interest rate swap associated with the variable rate medium term notes (See Note 13 to the 2001 Form 10-K). This debt was fully repaid in July 2002. Item 8 ------ Financial Statements & Supplementary Data ----------------------------------------- BANGOR HYDRO-ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF INCOME For the Years Ended December 31,
Predecessor ----------- Period From Period From January 1, Acquisition 2001 Date to Through December 31, Acquisition 2002 2001 Date 2000 ---- ---- ---- ---- Electric Operating Revenues: Electric operating revenue (Note 1) $ 115,829,181 $ 29,919,908 $ 83,946,328 $ 126,852,407 Off-system sales (Note 7) 39,712,482 4,234,118 14,718,171 19,351,606 Standard offer service (Note 10) 12,195,953 17,476,348 67,112,864 66,133,532 ------------- ------------ ------------- ------------- $ 167,737,616 $ 51,630,374 $ 165,777,363 $ 212,337,545 ------------- ------------ ------------- ------------- Operating Expenses: Fuel for generation and purchased power (Notes 1 and 4) $ 61,670,112 $ 8,670,095 $ 25,978,835 $ 44,509,554 Standard offer service purchased power (Note 10) 11,507,606 16,945,383 65,893,732 65,552,980 Other operation and maintenance (Notes 1 and 6) 34,572,636 9,502,542 27,297,029 35,310,660 Depreciation and amortization (Note 1) 10,549,148 2,198,158 7,826,371 9,158,885 Regulatory amortizations (Notes 7, 8 and 10) 13,988,421 4,345,577 13,380,902 19,153,442 Taxes - Local property and other 4,859,734 1,181,771 3,817,948 4,795,698 Income (Note 3) 6,553,102 2,038,384 4,713,760 7,432,261 ------------- ------------ ------------- ------------- $ 143,700,759 $ 44,881,910 $ 148,908,577 $ 185,913,480 ------------- ------------ ------------- ------------- Operating Income $ 24,036,857 $ 6,748,464 $ 16,868,786 $ 26,424,065 Other Income And (Deductions): Allowance for equity funds used during construction (Note 1) 497,920 139,532 464,541 158,698 Other, net of applicable income taxes (Notes 2 and 3) 805,363 157,452 (1,416,135) 454,715 ------------- ------------ ------------- ------------- Income Before Interest Expense $ 25,340,140 $ 7,045,448 $ 15,917,192 $ 27,037,478 ------------- ------------ ------------- ------------- Interest Expense: Long-term debt (Note 5) $ 12,145,601 $ 3,393,733 $ 10,429,419 $ 15,211,905 Other (Note 5) 1,179,320 286,443 722,586 893,455 Allowance for borrowed funds used during construction (Note 1) (446,083) (135,676) (423,431) (169,929) ------------- ------------ ------------- ------------- $ 12,878,838 $ 3,544,500 $ 10,728,574 $ 15,935,431 ------------- ------------ ------------- ------------- Net Income $ 12,461,302 $ 3,500,948 $ 5,188,618 $ 11,102,047 Dividends On Preferred Stock (Note 4) 265,570 66,429 199,141 265,570 ------------- ------------ ------------- ------------- Earnings Applicable To Common Stock $ 12,195,732 $ 3,434,519 $ 4,989,477 $ 10,836,477 ============= ============ ============= ============= Weighted Average Number Of Shares Outstanding (Note 4) 7,363,424 7,363,424 7,363,424 7,363,424 ------------- ------------ ------------- ------------- Earnings Per Common Share (Note 4): Basic $ 1.66 $ .47 $ .67 $ 1.47 Diluted 1.66 .47 .61 1.30 ------------- ------------ ------------- ------------- Dividends Declared Per Common Share $ 1.29 $ - $ .60 $ .80 ------------- ------------ ------------- ------------- The accompanying notes are an integral part of these consolidated financial statements.
Item 8 ------ Financial Statements & Supplementary Data ----------------------------------------- BANGOR HYDRO-ELECTRIC COMPANY CONSOLIDATED BALANCE SHEETS December 31,
Assets 2002 2001 ---- ---- Investment In Utility Plant: Electric plant in service, at original cost (Note 11) $ 333,410,221 $ 328,559,986 Less - Accumulated depreciation and amortization (Note 1) 97,473,295 93,984,836 ------------- ------------- $ 235,936,926 $ 234,575,150 Construction work in progress (Note 1) 5,933,988 7,307,837 ------------- ------------- $ 241,870,914 $ 241,882,987 Investments in corporate joint ventures: (Notes 1 and 7) Maine Yankee Atomic Power Company $ 4,033,846 $ 4,421,884 Maine Electric Power Company, Inc. 1,004,473 853,562 ------------- ------------- $ 246,909,233 $ 247,158,433 ------------- ------------- Other Investments, at cost (Note 9) $ 3,590,720 $ 3,497,681 ------------- ------------- Funds held by trustee, at cost (Notes 5 and 9) $ 21,191,940 $ 22,694,648 ------------- ------------- Current Assets: Cash and cash equivalents (Notes 1 and 9) $ 988,752 $ 884,617 Accounts receivable, net of reserve ($1,085,052 in 2002 and $761,000 in 2001) 21,027,291 19,268,889 Unbilled revenue receivable (Note 1) 8,318,821 15,379,708 Inventories, at average cost: Material and supplies 2,466,988 2,531,853 Fuel oil 44,860 53,320 Prepaid expenses 285,212 671,267 ------------- ------------- Total current assets $ 33,131,924 $ 38,789,654 ------------- ------------- Regulatory Assets and Deferred Charges: Goodwill-EMERA Acquisition (Note 2) $ 82,537,291 $ 82,537,291 Investment in Seabrook nuclear project, net of accumulated amortization of $36,969,396 in 2002 and $35,270,346 in 2001 (Notes 8 and 10) 21,872,679 23,571,729 Costs to terminate/restructure purchased power contracts, net of accumulated amortization of $166,003,281 in 2002 and $145,729,090 in 2001 (Notes 7 and 10) 72,675,931 92,057,206 Maine Yankee decommissioning costs (Notes 7 and 10) 31,101,273 37,306,576 Above-market purchased power contract obligation (Notes 10 and 13) 63,341,000 73,954,000 Other regulatory assets (Notes 3, 5, 6, 7 and 10) 57,843,677 52,657,562 Other deferred charges (Note 6) 6,535,328 4,019,969 ------------- ------------- Total regulatory assets and deferred charges $ 335,907,179 $ 366,104,333 ------------- ------------- Total Assets $ 640,730,996 $ 678,244,749 ============= ============= The accompanying notes are an integral part of these consolidated financial statements.
Item 8 ------ Financial Statements & Supplementary Data ----------------------------------------- BANGOR HYDRO-ELECTRIC COMPANY CONSOLIDATED BALANCE SHEETS December 31,
Stockholders' Investment and Liabilities 2002 2001 ---- ---- Capitalization: (see accompanying statement) Common stock investment (Notes 4 and 6) $ 206,266,149 $ 205,556,673 Preferred stock (Note 4) 4,734,000 4,734,000 Long-term debt, net of current portion (Notes 5 and 9) 118,058,636 131,967,827 ------------- ------------- Total capitalization $ 329,058,785 $ 342,258,500 ------------- ------------- Current Liabilities: Notes payable - banks (Note 5) $ 16,000,000 $ 8,000,000 ------------- ------------- Other current liabilities - Current portion of long-term debt (Notes 5 and 9) $ 34,137,342 $ 43,245,891 Accounts payable 20,281,376 22,491,785 Dividends payable 66,429 66,429 Accrued interest 2,092,608 2,663,225 Customers' deposits 572,291 572,867 Current income taxes (refundable) payable (355,008) 1,916,892 ------------- ------------- Total other current liabilities $ 56,795,038 $ 70,957,089 ------------- ------------- Total current liabilities $ 72,795,038 $ 78,957,089 ------------- ------------- Regulatory and Other Long-term Liabilities (Note 3) Deferred income taxes - Seabrook $ 11,337,954 $ 12,223,523 Other accumulated deferred income taxes 48,947,440 47,405,476 Maine Yankee decommissioning liability (Note 7) 31,101,273 37,306,576 Deferred gain on asset sale (Note 10) 9,888,574 14,574,316 Above-market purchased power contract obligation (Note 13) 63,341,000 73,954,000 Other regulatory liabilities (Notes 7 and 10) 11,264,848 18,961,715 Unamortized investment tax credits 1,185,596 1,311,928 Accrued pension and postretirement benefit costs (Note 6) 50,494,119 39,655,265 Other long-term liabilities (Notes 7 and 11) 11,316,369 11,636,361 ------------- ------------- Total regulatory and other long-term liabilities $ 238,877,173 $ 257,029,160 ------------- ------------- Total Stockholders' Investment and Liabilities $ 640,730,996 $ 678,244,749 ============= ============= The accompanying notes are an integral part of these consolidated financial statements.
Item 8 ------ Financial Statements & Supplementary Data ----------------------------------------- BANGOR HYDRO-ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF CAPITALIZATION December 31,
2002 2001 ---- ---- Common Stock Investment (Notes 1, 2 and 4) Common stock, no par value, stated value $5 per share- $ 36,817,120 $ 36,817,120 Authorized -- 10,000,000 shares Outstanding -- 7,363,424 shares Amounts paid in excess of par value 165,352,312 165,352,312 Accumulated other comprehensive loss (Note 6) (2,033,534) (47,278) Retained earnings 6,130,251 3,434,519 ------------- ------------- Total common stock investment $ 206,266,149 $ 205,556,673 Preferred Stock, Non-participating, cumulative, par value $100 per share, ------------- ------------- authorized 600,000 shares (Note 4): Not redemable or redeemable solely at the option of the issuer- 7%, Noncallable, 25,000 shares authorized and outstanding $ 2,500,000 $ 2,500,000 4.25%, Callable at $100, 4,840 shares authorized and outstanding 484,000 484,000 4%, Series A, Callable at $110, 17,500 shares authorized and outstanding 1,750,000 1,750,000 ------------- ------------- $ 4,734,000 $ 4,734,000 Long-Term Debt (Notes 5 and 9) ------------- ------------- First Mortgage Bonds- 10.25% Series due 2020 $ 30,000,000 $ 30,000,000 8.98% Series due 2022 20,000,000 20,000,000 7.30% Series due 2003 15,000,000 15,000,000 7.38% Series due 2002 - 20,000,000 ------------- ------------- $ 65,000,000 $ 85,000,000 Other Long-Term Debt- ------------- ------------- Finance Authority of Maine - Taxable Electric Rate Stabilization Revenue Notes, 7.03% Series 1995A, due 2005 $ 55,400,000 $ 71,500,000 Medium Term Notes, Variable interest rate-LIBO rate plus 1.125%, due 2002 - 5,460,000 Municipal Review Committee Note, 5%, due 2008 11,780,660 13,234,394 Senior unsecured note, 6.09%, due 2012 20,000,000 - Other miscellaneous notes payable, 3.90%, due 2006 15,318 19,324 ------------- ------------- $ 87,195,978 $ 90,213,718 Less: Current portion of long-term debt 34,137,342 43,245,891 ------------- ------------- $ 53,058,636 $ 46,967,827 ------------- ------------- Total Long-Term Debt $ 118,058,636 $ 131,967,827 ------------- ------------- Total Capitalization $ 329,058,785 $ 342,258,500 ============= ============= The accompanying notes are an integral part of these consolidated financial statements.
Item 8 ------ Financial Statements & Supplementary Data ----------------------------------------- BANGOR HYDRO-ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS For the years ended December 31,
Predecessor ----------- Period From Period From Acquisition January 1, Date to 2001 Through December 31, Acquisition 2002 2001 Date 2000 -------------- ------------ ------------- ------------- Cash Flows From Operating Activities: Net income $ 12,461,302 $ 3,500,948 $ 5,188,618 $ 11,102,047 Adjustments to reconcile net income to net cash from operating activities: Depreciation and amortization 10,549,148 2,198,158 7,826,371 9,158,885 Amortization of Seabrook nuclear project (Note 8) 1,699,050 424,763 1,274,287 1,699,050 Amortization of contract buyouts and restructuring (Note 7) 20,274,191 5,639,281 16,917,843 22,311,448 Amortization of deferred asset sale gain (Note 10) (4,681,324) (2,105,076) (5,971,057) (6,393,038) Other amortizations (3,330,048) 375,024 1,193,607 1,896,179 Allowance for equity funds used during construction (Note 1) (497,920) (139,532) (464,541) (158,698) Deferred income tax provision and amortization of investment tax credits (Note 3) 1,625,652 (212,917) (5,976,077) (2,765,264) Gain on sale of subsidiary - - - (1,205,727) Deferred Maine Yankee replacement power cost write-off (Note 7) - - - 1,992,848 Changes in assets and liabilities: Costs to restructure purchased power contract (Note 7) (750,000) (250,000) (750,000) (1,000,000) Deferred standard-offer service costs (Note 10) (2,138,380) 4,265,218 4,580,779 (2,988,823) Deferred special rate contract revenues (Note 10) (115,711) (910,954) (1,404,194) (1,368,948) Employee transition costs (Note 10) (3,535,097) - - - Exercise of PERC warrants-cash paid in lieu of issuing shares (Note 7) - (4,951,550) (9,225,892) (2,129,387) Deferred Wyman#4 litigation settlement proceeds (Note 10) - 2,592,294 - - Deferred incremental Maine Yankee costs (Note 7) - - - 807,616 Deferred costs associated with generation asset sale (Note 10) - - - 107,765 Accounts receivable, net and unbilled revenue 5,302,485 (1,291,684) 1,298,321 (5,113,248) Accounts payable (3,759,662) (1,032,699) (1,359,942) 10,609,785 Accrued interest (570,617) (703,043) 837,030 (23,521) Current and deferred income taxes (2,271,900) (293,705) 2,253,111 (10,093) Accrued pension and postretirement benefit costs (Note 6) 4,294,357 840,025 2,183,113 823,049 Other current assets and liabilities, net 458,802 (257,941) 580,127 202,486 Other, net (1,086,422) (256,505) (1,150,926) 65,770 -------------- ------------ ------------- ------------- Net Increase in Cash From Operating Activities: $ 33,927,906 $ 7,430,105 $ 17,830,578 $ 37,620,181 Cash Flows From Investing Activities: -------------- ------------ ------------- ------------- Construction expenditures $ (10,094,378)$ (6,264,489) $ (10,083,839) $ (16,680,501) Allowance for borrowed funds used during construction (Note 1) (446,083) (135,676) (423,431) (169,929) Proceeds from sale of subsidiary - - - 1,250,000 -------------- ------------ ------------- ------------- Net Decrease in Cash From Investing Activities $ (10,540,461)$ (6,400,165) $ (10,507,270) $ (15,600,430) Cash Flows From Financing Activities: -------------- ------------ ------------- ------------- Dividends on preferred stock $ (265,570)$ (66,380) $ (199,190) $ (265,570) Dividends on common stock (9,500,000) (1,472,685) (4,418,054) (5,522,567) Payments on long-term debt (Note 5) (43,017,740) (2,054,457) (19,720,645) (19,460,000) Capital reserve funds used in repayment on long-term debt 1,500,000 - - - Proceeds from issuance of long-term debt (Note 5) 20,000,000 - - - Short-term debt, net (Note 5) 8,000,000 2,000,000 6,000,000 - -------------- ------------ ------------- ------------- Net Decrease in Cash From Financing Activities $ (23,283,310)$ (1,593,522) $ (18,337,889) $ (25,248,137) -------------- ------------ ------------- ------------- Net Increase (Decrease) in Cash and Cash Equivalents $ 104,135 $ (563,582) $ (11,014,581) $ (3,228,386) Cash and Cash Equivalents at Beginning of Year 884,617 1,448,199 12,462,780 15,691,166 -------------- ------------ ------------- ------------- Cash and Cash Equivalents at End of Year $ 988,752 $ 884,617 $ 1,448,199 $ 12,462,780 ============== ============ ============= ============= The accompanying notes are an integral part of these consolidated financial statements.
Item 8 ------ Financial Statements & Supplementary Data ----------------------------------------- BANGOR HYDRO-ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF COMMON STOCK INVESTMENT
Accumulated Amounts Paid Other Total Common Common in Excess of Retained Comprehensive Stock Stock Par Value Earnings Loss Investment ------------- ------------- ------------- ---------------- ------------- Balance December 31, 1999 $36,817,120 $ 58,890,342 $37,014,433 $ - $132,721,895 Net income - - 11,102,047 - 11,102,047 Cash dividends declared on- Preferred stock - - (265,570) - (265,570) Common stock - - (5,890,738) - (5,890,738) Exercise of warrants-cash paid in lieu of issuing shares (Note 4) - (247,975) - - (247,975) ----------- ------------ ----------- -------------- ------------- Balance December 31, 2000 $36,817,120 $ 58,642,367 $41,960,172 $ - $137,419,659 Net income - - 8,689,566 - 8,689,566 Other comprehensive loss net of taxes: Unrealized loss on interest rate swap - - - (47,278) (47,278) ------------ Total comprehensive income 8,642,288 ------------ Merger transactions (net) (Note 2) - 120,890,928 (42,531,595) - 78,359,333 Cash dividends declared on- Preferred stock - - (265,570) - (265,570) Common stock - - (4,418,054) - (4,418,054) Exercise of warrants-cash paid in lieu of issuing shares (Note 4) - (14,180,983) - - (14,180,983) ----------- ------------ ----------- ------------ ------------ Balance December 31, 2001 $36,817,120 $165,352,312 $ 3,434,519 $ (47,278) $205,556,673 Net income - - 12,461,302 12,461,302 Other comprehensive loss net of taxes: Unrealized gain on interest rate swap - - - 47,278 47,278 Minimum pension liability (Note 6) - - - (2,033,534) (2,033,534) ------------ Total comprehensive income 10,475,046 Cash dividends declared on- ------------ Preferred stock - - (265,570) - (265,570) Common stock - - (9,500,000) - (9,500,000) ----------- ------------ ----------- ------------ ------------ Balance December 31, 2002 $36,817,120 $165,352,312 $ 6,130,251 $ (2,033,534) $206,266,149 =========== ============ =========== ============= ============ The accompanying notes are an integral part of these consolidated financial statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Note 1. Nature of Operations and Summary of Significant Accounting Policies ---------------------------------------------------------------------------- NATURE OF OPERATIONS - Bangor Hydro-Electric Company (the Company) is a public utility engaged in the transmission and distribution of electric energy and other energy related services, with a service area of approximately 5,275 square miles having a population of approximately 190,000 people. The Company serves approximately 107,000 customers in portions of the Maine counties of Penobscot, Hancock, Washington, Waldo, Piscataquis, and Aroostook. The Company's regulated operations are subject to the regulatory authority of the Maine Public Utilities Commission (MPUC) as to retail rates, accounting, service standards, territory served, the issuance of securities and other matters. The Company is also subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC) as to certain matters, including rates for transmission services. The Company is a member of the New England Power Pool (NEPOOL), and is interconnected with other New England utilities to the south and with New Brunswick Power Corporation to the north. BASIS OF CONSOLIDATION - The Consolidated Financial Statements of the Company include its wholly- owned subsidiaries, Bangor Var Co., Inc. (BVC), Bangor Energy Resale, Inc. (BERI), CareTaker, Inc. (CareTaker), Bangor Fiber Co., Inc. (Bangor Fiber), and Bangor Line Co., Inc. (Bangor Line). 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 5 for a discussion of this financing arrangement). CareTaker was incorporated in 1997 and provides security alarm services on a retail basis to residential and commercial customers. Bangor Fiber was formed in 2000 to supply fiber optic communications cable to communications companies and cable service providers and other related activities. Bangor Line was formed in 2001 to provide engineering, permitting and design, geographic information system and construction services to third parties. See Note 7 for additional information with respect to BVC. All significant intercompany balances and transactions have been eliminated. The accounts of the Company are maintained in accordance with the Uniform System of Accounts prescribed by the regulatory bodies having jurisdiction. EQUITY METHOD OF ACCOUNTING - The Company accounts for its investments in the common stock of Maine Yankee Atomic Power Company (Maine Yankee) and Maine Electric Power Company, Inc. (MEPCO) under the equity method of accounting, and records its proportionate share of the net earnings of these companies as a reduction of fuel for generation and purchased power expense. See Note 7 for additional information with respect to these investments. ELECTRIC OPERATING REVENUE - Electric Operating Revenue, including that associated with standard offer service (See Note 10) consists primarily of amounts charged for electricity delivered to customers during the period. The Company records unbilled revenue, based on estimates of electric service rendered and not billed at the end of an accounting period, in order to match revenue with related costs. As of March 1, 2000, the Company bills customers for the energy supplied by competitive energy providers (See Note 10). Competitive energy providers are paid only after the funds are collected from customers. The Company records accounts receivable for the amounts billed to competitive energy customers and a corresponding accounts payable for the amounts due to the energy supplier. No revenue is recognized as the Company is acting as an agent. Also, effective March 1, 2002, as a result of new bids received from competitive energy providers, the Company is no longer serving as the standard offer service provider. The Company is, though, serving as the billing and collection agent under the standard offer program. 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 was approximately 2.9% in each of 2002, 2001 and 2000. 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 $7.8 million in 2002, $10.1 million in 2001 and $10 million in 2000. GOODWILL -In connection with the acquisition of the Company's common stock by Emera, Inc. (Emera) in October 2001 (see Note 2), the excess of the cost over the fair value of the net assets of the Company has been recorded as goodwill on the Company's consolidated balance sheet. In accordance with the implementation of Statement of Financial Accounting Standards No. 141, "Business Combinations", goodwill is no longer amortized. The Company assesses the recoverability of goodwill by using discounted cash flow analysis. ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFDC) - In accordance with regulatory requirements of the MPUC, the Company capitalizes as AFDC financing costs related to portions of its construction work in progress, at a rate equal to its weighted cost of capital, into utility plant with offsetting credits to other income and interest. This cost is not an item of current cash income, but is recovered over the service life of plant in the form of increased revenue collected as a result of higher depreciation expense and return. In addition, carrying costs on certain regulatory assets and liabilities, including the deferred asset sale gain (see Note 10), were also capitalized and included in AFDC in the Consolidated Statements of Income. The average AFDC (carrying costs) rates computed by the Company were 8.8% in 2002, 9.1% for 2001 and 9.3% in 2000. 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 $12.6 million, $14.1 million and $15.1 million in 2002, 2001 and 2000, respectively. Cash paid for income taxes was approximately $9.6 million, $10.4 million and $10 million in 2002, 2001 and 2000, respectively. Non-cash financing activity: In October 2001 the Company issued a $13,667,550 note payable in connection with the exercise of common stock warrants. See Notes 5 and 7 for a discussion of the note payable and the common stock warrants. RISK MANAGEMENT AND DERIVATIVE FINANCIAL INSTRUMENTS - The Company's major financial market risk exposure is changing interest rates. Changing interest rates will affect interest paid on variable rate debt and the fair value of fixed rate debt. The Company manages interest rate risk through a combination of both fixed and variable rate debt instruments and an interest rate swap which terminated in 2002 (see Note 5). 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. 133, "Accounting for Derivative Instruments and Hedging Activities". In November 2002 the Company purchased a weather hedge for the 2002- 2003 heating season. The hedge is designed to protect against the negative impacts of warmer than normal weather on the Company's electric operating revenues. The cost of the weather hedge is being amortized over the 2002- 2003 heating season. No income was recognized for this weather hedge in 2002 due to the colder than normal weather. See Note 12. RECLASSIFICATIONS-Certain prior year amounts have been reclassified to conform with the presentation used in the 2002 Consolidated Financial Statements. Note 2. Merger with Emera, Inc. -------------------------------- On October 10, 2001, Emera, Inc. (Emera) completed the acquisition of all of the outstanding common stock of the Company for US$26.806 per share in cash. Emera also owns Nova Scotia Power, a fully integrated electric utility that supplies substantially all of the generation, transmission and distribution of electricity in Nova Scotia; and has an interest in the Maritimes & Northeast Pipeline, which transports Sable natural gas through Maine to Boston. The acquisition transaction was accounted for using purchase accounting. The cost in excess of the fair value of the net assets acquired, amounting to approximately $82.5 million is recorded as goodwill on the consolidated balance sheets. As previously discussed, the goodwill is not being amortized, but instead is subject to an impairment test at least annually in accordance with the provisions of Statement of Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets". Goodwill associated with the Emera acquisition was not adjusted for any impairment losses in 2002 or 2001. As a result of the merger, and as required under purchase accounting by generally accepted accounting principles, retained earnings of the Company were reset to zero and moved to amounts paid in excess of par value. Also in connection with merger related activities, the Company incurred approximately $3.9 million and $3 million in incremental costs in 2001 and 2000, respectively. These were recorded as a component of Other Income (Expense) in the Consolidated Statements of Income for 2001 and 2000. Note 3. Income Taxes --------------------- In accordance with Statement of Financial Accounting Standards No. 109 "Accounting for Income Taxes" (FAS 109), the Company recorded cumulative net additional deferred income tax liabilities of approximately $10.5 million as of December 31, 2002 and $10.3 million as of December 31, 2001. 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 ($15.7 million and $16.0 million as of December 31, 2002 and 2001, 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 ($4.5 million and $4.9 million as of December 31, 2002 and 2001, respectively), and the establishment of deferred tax assets on unamortized investment tax credits ($701,000 and $776,000 as of December 31, 2002 and 2001, respectively). These latter amounts have been recorded in Other Regulatory Liabilities at December 31, 2002 and 2001. 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, 2002 and 2001: 2002 2001 ------------ ------------- Deferred Income Tax Liabilities: Costs to terminate/restructure purchased power contracts $ 18,877,652 $ 26,362,744 Excess book over tax basis of electric plant in service 42,237,261 37,117,206 Investment in jointly-owned companies 1,676,838 1,476,037 Other regulatory assets 4,177,045 2,547,116 Other 93,100 138,374 ------------ ------------ $ 67,061,896 $ 67,641,477 ------------ ------------ Deferred Income Tax Assets: Deferred asset sale gain $ 4,255,984 $ 5,901,889 Accrued pension and postretirement benefit costs 7,486,547 5,734,119 Other regulatory liabilities 2,312,651 5,369,662 Other 4,059,274 3,230,331 ------------ ------------ $ 18,114,456 $ 20,236,001 ------------ ------------ Total other accumulated deferred income taxes $ 48,947,440 $ 47,405,476 ============ ============ The individual components of federal and state income taxes reflected in the Consolidated Statements of Income for 2002, 2001 and 2000 are stated in the table below. Year Ended December 31, 2002 2001 2000 ------------------------------------------------------------------------ Current Income Tax Provision $ 5,481,256 $12,258,263 $10,366,395 Deferred Income Tax Provision 1,751,984 (6,048,863) (2,625,596) Investment Tax Credits, Net (126,332) 42,951 (139,668) ----------- ----------- ----------- Total Provision $ 7,106,908 $ 6,252,351 $ 7,601,131 Allocated to Other Income (553,806) 499,793 (168,870) ----------- ----------- ----------- Charged to Operating Expense $ 6,553,102 $ 6,752,144 $ 7,432,261 ============ ============ =========== The Company's effective tax rate differed from the statutory rate of 35% due to the following: 2002 2001 2000 --------------------------------------------- (Dollars in Thousands) Amount % Amount % Amount % --------------------------------------------- Federal income tax provision at statutory rate $6,849 35.0% $5,230 35.0% $6,546 35.0% Less (Plus) permanent differences in tax expense resulting from statutory exclusions from taxable income: Asset sale gain permanent differences (201) (1.0) (349) (2.3) (276) (1.5) Amortization of equity component of AFDC on recoverable Seabrook investment (160) (.8) (160) (1.0) (160) (.8) Other 468 2.3 246 1.6 334 1.7 --------------------------------------------- Federal income tax provision before effect of timing differences $6,742 34.5% $5,493 36.7% $6,648 35.6% 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) (.7) (151) (1.0) (151) (.8) State income tax liability deducted for federal income tax purposes 591 3.0 424 2.8 550 2.8 Reversal of excess deferred income taxes 319 1.6 230 .5 147 .8 Amortization of investment tax credits 126 .6 140 .9 140 .8 Other (18) - (375) (2.5) (67) (.2) --------------------------------------------- Federal income tax provision $5,875 30.0% $5,225 35.0% $6,029 32.2% ============================================= Note 4. Common and Preferred Stock and Earnings Per Share ---------------------------------------------------------- COMMON STOCK - In connection with the Company's merger with Emera on October 10, 2001, Emera owns all of the Company's outstanding common shares. The common stock has general voting rights of one vote per twelve shares owned. PREFERRED STOCK - Authorized but unissued shares of 552,660 (plus additional shares equal in number to such presently outstanding shares as may be retired) may be issued with such preferences, restrictions or qualifications as the board of directors may determine. Any new shares so issued will be required to be issued with per share voting rights no greater than that of the common stock. The callable preferred stock may be called in whole or in part upon any dividend date by appropriate resolution of the board of directors. The currently outstanding preferred stock has general voting rights of one vote per share. With regard to payment of dividends or assets available in the event of liquidation, preferred stock ranks prior to common stock. EXERCISE OF COMMON STOCK WARRANTS - In 2001, the remaining 1,437,215 of outstanding common stock warrants were exercised, which were issued in connection with the PERC purchased power contract restructuring, were exercised at market prices ranging from $25.625 to $26.806 per share. For a complete discussion of the PERC contract restructuring and the issuance of warrants, see Note 7. For 736,315 of the warrants, the Company exercised its option to pay cash to the holders of the warrants instead of actually issuing shares of common stock. These payments amounted to approximately $14.2 million. For 700,900 of unexercised warrants associated with the Municipal Review Committee (MRC), the Company and the MRC entered into an agreement whereby the Company, instead of issuing shares or paying cash, established a note payable to the MRC in the amount of $13,667,550, at an interest rate of 5% and a term of seven years. See Note 5 for a discussion of the MRC debt. Since the common shares were not issued, and the Company had recorded the estimated fair value of these warrants when issued in June 1998 as a $1.4 million addition to paid-in capital, an adjustment has been made in connection with the cash payments option and the MRC note payable to reduce paid-in capital by this amount as of December 31, 2001. Also as a result of the exercise of the warrants in 2001, the MPUC, in connection with its order approving the Company's merger with Emera, established a cap on the value of the warrants that could be recorded as a regulatory asset for exercises in 2001. Since all of the warrant exercises in 2001 were in excess of this cap, the Company was required to write-off this excess amount to paid-in capital. The charges, which reduced paid-in capital, amounted to approximately $12.6 million in 2001. See Note 7 for a complete discussion of the impact of the MPUC's orders concerning the PERC warrants. EARNINGS PER SHARE - The following table reconciles basic and diluted earnings per common share assuming all outstanding common stock warrants were converted to common shares (see Note 7 for discussion of warrants issued in connection with the PERC purchased power contract restructuring). For 2001 the Predecessor period is from January 1, 2001 through the acquisition date, and the Successor period is from the acquisition date to December 31, 2001. Successor Predecessor 2002 2001 2001 2000 ----------- ---------- ---------- ----------- Earnings applicable to common stock $12,195,732 $3,434,519 $4,989,477 $10,836,477 ----------- ---------- ---------- ----------- Average common shares outstanding 7,363,424 7,363,424 7,363,424 7,363,424 Plus: incremental shares from assumed conversion of outstanding warrants - - 791,745 990,099 ----------- ---------- ---------- ----------- Average common shares outstanding plus assumed warrants converted 7,363,424 7,363,424 8,155,169 8,353,523 ----------- ---------- ---------- ----------- Basic earnings per common share $1.66 $.47 $.67 $1.47 ----------- ---------- ---------- ----------- Diluted earnings per common share $1.66 $.47 $.61 $1.30 =========== ========== ========== =========== Note 5. Lending Agreements --------------------------- In connection with financing the costs of the purchased power contract buyback accomplished in June 1995 (see Note 6), the Company entered into a Loan Agreement with the Finance Authority of Maine (FAME), a body corporate and politic and public instrumentality of the state of Maine. Pursuant to authorizing legislation in Maine, FAME issued $126 million of notes through a private placement, the repayment of which is the responsibility of the Company under the terms of the Loan Agreement. Of that amount, approximately $105 million was made available to the Company to finance a portion of the buyback and approximately $21 million was set aside in a capital reserve fund. The notes bear interest at an annual rate of 7.03%, mature on July 1, 2005 and are subject to a schedule of annual principal payments, which began on July 1, 1998. The amount held in the capital reserve fund will be used to pay the final installment of principal and interest due in 2005. The assets in the capital reserve fund are held by a third party trustee and invested in a guaranteed investment contract, earning interest at an annual rate of 6.51%. The interest earnings are utilized to offset the semiannual interest payments on the FAME notes. In order to secure the FAME notes, the Company executed a General and Refunding Mortgage Indenture and Deed of Trust establishing a lien on the Company's property junior to the lien under the Company's First Mortgage Bonds Indenture. The Company may not issue any additional First Mortgage Bonds in the future. The Company issued bonds to FAME under the new mortgage in the amount of $126 million. 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. On October 10, 2001, the Company issued a unsecured promissory note to the MRC for the amount of $13,667,550 (MRC Promissory Note). The Company and the MRC agreed to terms and conditions of the MRC Promissory Note under which the Company shall make a series of cash payments to the MRC upon the exercise of warrants on the closing of the merger with Emera, Inc. (See Notes 4 and 7 for a discussion of the PERC common stock warrants). The MRC Promissory Note has a term of seven years, a fixed interest rate of 5%, and payments of interest and principal on a quarterly basis. The MRC has the right to defer some or all of any of the quarterly payments within the same Note Year (August 1 to July 31), upon at least a 14 days' prior written notice to the Company. On December 20, 2002, the Company received proceeds from the private placement issuance of a $20 million senior unsecured note. The note has a term of ten years, a fixed interest rate of 6.09% and payments of interest on a semiannual basis. The $20 million principal borrowing is to be paid at maturity. Current maturities of the first mortgage bonds and other long-term debt for the five years subsequent to December 31, 2002, amounting to $81,239,236, are $34,137,342 in 2003, $20,314,371 in 2004, $21,830,717 in 2005, $2,318,969 in 2006, and $2,637,837 in 2007. 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 three year revolving credit commitment of $30 million. The amended credit agreement is secured by $82.5 million of non-interest bearing First Mortgage Bonds. The term loan was fully repaid in May of 1999, and the First Mortgage Bonds have expired. On June 29, 2001, the Company extended the revolving credit agreement until October 1 and then until March 31, 2002, and the agreement was further extended until June 30, 2003 with some modifications. The facility was increased to $60 million to accommodate the certain debt retirements in 2002, another pricing level was added to recognize the Company's improved credit and certain modifications were made to some of the financial covenants. By the terms of the credit agreement, 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. On June 29, 2001, the Company, as permitted under the Amended and Restated Credit and Term Loan Agreement, entered into a Promissory Note with a financial institution that allows the Company to borrow up to an additional $10 million. This unsecured facility is used by the Company to manage working capital needs, and the interest rate setting mechanism and other major terms of the Note are similar to terms in the Amended and Restated Credit and Term Loan Agreement. The original facility expired on October 1, 2001, but has also subsequently been extended to June 30, 2003. In connection with debt agreements the Company must comply with certain financial covenants related to the Company's debt ratio, fixed charge coverage, net worth, and limitation on the payment of common dividends. The Company in compliance with all covenants associated with its lending agreements. Certain information related to the Company's short-term credit facilities is as follows: 2002 2001 2000 ----------- ----------- ----------- Total credit available at end of period $70,000,000 $40,000,000 $30,000,000 Unused credit at end of period $54,000,000 $32,000,000 $30,000,000 Borrowings outstanding at end of period $16,000,000 $ 8,000,000 - Effective interest rate (exclusive of fees) on borrowings outstanding at end of period 2.4% 4.4% -% Average daily outstanding borrowings for the period $21,782,192 $ 3,031,507 $ - Weighted daily average annual interest rate (exclusive of fees) 2.8% 4.4% -% Highest level of borrowings outstanding at any month-end during the period $45,000,000 $ 8,000,000 $ - =========== ============ ======== Note 6. Postretirement Benefits ------------------------------- The Company has a noncontributory pension plan covering substantially all of its employees. Benefits under the plan are generally based on the employee's years of service and compensation during the years preceding retirement. The Company's general policy is to contribute to the funds the amounts deductible for federal income tax purposes. The Company also has an unfunded noncontributory supplemental non-qualified pension plan that provides additional retirement benefits to certain former senior executives. There were no employer contributions to the noncontributory pension plan in 2002, 2001 or 2000. The plan's assets are composed of fixed income securities, equity securities and cash equivalents. In 2002, as a result of a corporate restructuring, the Company implemented an early retirement program which provided for enhanced pension benefits for the early retirees. The following tables detail the funded status of the plan, the amounts recognized in the Company's Consolidated Financial Statements, the components of pension (income) expense for 2002, 2001 and 2000 and the major assumptions used to determine these amounts (includes both the funded and unfunded plans). Total pension expense (income) included the following components: 2002 2001 2000 ----------- ---------- ---------- Service cost-benefits earned during the period $ 916,726 $1,387,841 $1,186,910 Interest cost on projected benefit obligation 3,920,015 3,622,633 3,479,260 Expected return on plan assets (3,925,587) 4,260,894) (4,460,416) Amortization of unrecognized asset and gains (losses) (568,643) (6,958) (664,911) ----------- ---------- ---------- Total pension expense (income) $ 342,511 $ 742,622 $ (459,157) =========== ========== ========== The following table sets forth the plans' funded status at December 31, 2002 and 2001: 2002 2001 ------------- ------------- Change in Projected Benefit Obligation Balance as of December 31, 2001 and 2000 $ 53,382,582 $ 47,951,796 Service cost 916,726 1,387,841 Interest cost 3,920,015 3,622,633 Benefits paid (3,396,922) (2,863,257) Amendments 2,054,108 - (Gains) and losses 2,278,722 3,283,569 Other - Special termination charge 1,612,956 - ------------- ------------- Balance as of December 31, 2002 and 2001 $ 60,768,187 $ 53,382,582 ------------- ------------- Change in Plan Assets Balance as of December 31, 2001 and 2000 $ 41,430,955 $ 48,425,866 Employer contributions 130,441 54,142 Benefits paid (3,396,922) (2,863,257) Actual return, less expenses (3,700,541) (4,185,796) ------------- ------------- Balance as of December 31, 2002 and 2001 $ 34,463,933 $ 41,430,955 ------------- ------------- Funded status $ (26,304,254) $ (11,951,627) Unrecognized prior service cost 2,474,374 - Unrecognized (gain) or loss 8,872,460 (1,180,767) ------------- ------------- Accrued pension at December 31, 2002 and 2001 $ (14,957,420) $ (13,132,394) ============= ============= Amounts recognized in the statement of financial position consist of: Accrued benefit liability $ (20,866,817) $ (13,132,394) Intangible asset 2,474,374 - Accumulated other comprehensive income 3,435,023 - ------------- ------------- Net amount recognized $ (14,957,420) $ (13,132,394) ============= ============= The discount rate and rate of increase in future compensation levels used to determine pension obligations, effective January 1, 2003, are 6.75% and 4%, respectively, and were used to calculate the plans' funded status at December 31, 2002. Significant assumptions used to determine the pension expense (income) for each year were as follows: 2002 2001 2000 ------- ----------- ----- Discount rate* 7.25% 7.75%/7.25% 8.0% Rate of increase in future compensation levels 4.0% 4.0% 4.0% Expected long-term rate of return on plan assets 8.0% 9.0% 9.0% * In 2001, a 7.75% discount rate was used prior to the acquisition, and 7.25% was subsequent to the acquisition. The provisions of Financial Accounting Standards Board Statement No. 87, "Employers' Accounting for Pensions", requires the Company to record an additional minimum liability of $5,909,397 at December 31, 2002. This liability represents the amount by which the accumulated benefit obligation exceeds the sum of the fair market value of plan assets and accrued amounts previously recorded. The additional liability may be offset by an intangible asset to the extent of previously unrecognized prior service cost. The intangible asset of $2,474,374 at December 31, 2002 is included in Other Deferred Charges on the Consolidated Balance Sheets. The remaining amount of $3,435,023 is recorded as a component of stockholders' equity, net of related tax benefits of $1,401,489, is included in Accumulated Other Comprehensive Loss on the Consolidated Statement of Common Stock Investment at December 31, 2002. As a result of regulatory accounting as approved in the Company's Alternative Rate Plan (See Note 10), the Company deferred $1,612,956, as a regulatory asset, related to this special termination charge. As a result of this accounting, the pension expense for 2002 was unaffected, while the pension liability was increased at December 31, 2002. In 2001, as a result of purchase accounting, all unrecognized actuarial gains and losses, prior service cost and the net transition asset were eliminated as of the merger with Emera. As a result of regulatory accounting, a regulatory asset of $10.4 million, equal to these unrecognized amounts, was established at the merger date. The Company is amortizing this balance over the same period at which the corresponding gains and losses were being amortized when they were a component of pension expense. Amortization expense amounted to $1,214,065 in 2002 and $211,670 in 2001 for the period subsequent to the merger. The accumulated benefit obligation for the unfunded supplemental pension plan with accumulated benefit obligations in excess of plan assets was $2,501,699 and $2,201,171 as of December 31, 2002 and 2001, respectively. In addition to pension benefits, the Company provides certain health care and life insurance benefits to its retired employees. Substantially all of the Company's employees may become eligible for retiree benefits if they reach normal retirement age while working for the Company. The Company maintains 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 $864,000 in 2002 and $1.3 million in 2001. 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 2002, 2001 and 2000 and the major assumptions used to determine these amounts are shown in the following tables: 2002 2001 2000 ----------- ----------- ----------- Service cost of benefits earned $ 583,496 $ 632,590 $ 573,740 Interest cost on accumulated postretirement benefit obligation 2,043,548 1,848,813 1,716,563 Actual return on plan assets (16,190) (37,836) (22,002) Amortization of unrecognized transition obligation - 375,900 501,200 Other deferrals, net (8,810) 271,727 280,255 ---------- ---------- ---------- Net periodic postretirement benefit cost $2,602,044 $3,091,194 $3,049,756 ========== ========== ========== The following table sets forth the benefit plan's funded status at December 31, 2002 and 2001. 2002 2001 ------------ ------------ Change in Accumulated Postretirement Benefit Obligation Balance as of December 31, 2001 and 2000 $ 27,488,444 $ 23,874,192 Service cost 583,496 632,590 Interest cost 2,043,548 1,848,813 Claims paid (1,053,187) (979,648) Gains and losses 1,532,744 2,112,497 Other - Special termination charge 1,366,357 - ------------ ------------ Balance as of December 31, 2002 and 2001 $ 31,961,402 $ 27,488,444 ------------ ------------ Change in Plan Assets Balance as of December 31, 2001 and 2000 $ 1,014,038 $ 879,734 Employer contributions 863,969 1,250,743 Retiree contributions 81,529 44,038 Claims/benefit payments and administrative fees (1,053,187) (1,198,313) Actual return 16,190 37,836 ------------- ------------ Balance as of December 31, 2002 and 2001 $ 922,539 $ 1,014,038 ------------- ------------ Funded status $(31,038,863) $(26,474,406) Unrecognized (gain) loss 1,411,561 (48,465) ------------ ------------ Accrued postretirement benefit cost at December 31, 2002 and 2001 $(29,627,302) $(26,522,871) ============ ============ The discount rate and near-term and long-term health care cost trend rates used to determine postretirement benefit obligations, effective January 1, 2003, and the Plan's funded status at December 31, 2002, were 6.75%, 9% and 5%, respectively. Significant assumptions used to determine the net periodic postretirement benefit cost for each year were as follows: 2002 2001 2000 ------ ------------- -------- Discount rate * 7.25% 7.75%/7.25% 8.0% Health care cost trend rate, employees less than age 65- Near-term 9.0% 7.5% 7.0% Long-term 5.0% 5.0% 5.0% Health care cost trend rate, employees greater than age 65- Near-term 9.0% 7.5% 7.0% Long-term 5.0% 5.0% 5.0% Rate of return on plan assets 5.0% 5.0% 5.0% * In 2001, a 7.75% discount rate was used prior to the acquisition, and 7.25% was subsequent to the acquisition. As a result of purchase accounting, all unrecognized actuarial gains and losses, prior service cost and the unrecognized net transition obligation were eliminated as of October 10, 2001, the merger date with Emera. As a result of regulatory accounting, a regulatory asset of $14.6 million, equal to these unrecognized amounts, was established at the merger date. The Company is amortizing this balance over the same period at which the corresponding gains and losses were being amortized when they were a component of the net periodic postretirement benefit cost. Amortization expense amounted to approximately $1.13 million in 2002 and $283,000 in 2001 for the period subsequent to the merger. 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 $ 508,177 $ (396,482) Effect on postretirement benefit obligation 5,906,425 (4,639,789) The estimates of the Company's accrued pension and postretirement benefit costs involve the utilization of significant assumptions. Changes in any one of these assumptions could impact the liabilities in the near term. The Company also provides a defined contribution 401(k) savings plan for substantially all of its employees. The Company's matching of employee voluntary contributions amounted to approximately $271,000 in 2002, $363,000 in 2001 and $370,000 in 2000. Note 7. Jointly Owned Facilities and Power Supply Commitments ------------------------------------------------------------- MAINE YANKEE - The Company owns 7% of the common stock of Maine Yankee, which owns and, prior to its permanent closure in 1997, operated an 880 megawatt (MW) nuclear generating plant (the Plant) in Wiscasset, Maine. Maine Yankee, which had commenced commercial operation on January 1, 1973, is the only nuclear facility in which the Company has an ownership interest. The Company's equity ownership in the plant had entitled the Company to about 7% of the output pursuant to a cost-based power contract. Pursuant to a contract with Maine Yankee, the Company is obligated to pay its pro rata share of Maine Yankee's operating expenses, including decommissioning costs. In addition, under a Capital Funds Agreement entered into by the Company and the other sponsor utilities, the Company may be required to make its pro rata share of future capital contributions to Maine Yankee if needed to finance capital expenditures. Plant Shutdown and Rate Case Settlement - On August 6, 1997, the board of directors of Maine Yankee voted to permanently cease power operations at the Plant and to begin decommissioning the Plant. The Plant had experienced a number of operational and regulatory problems and did not operate after December 6, 1996. The decision to close the Plant permanently was based on an economic analysis of the costs, risks and uncertainties associated with operating the Plant compared to those associated with closing and decommissioning it. The Plant's operating license from the Nuclear Regulatory Commission was scheduled to expire in 2008. The entire output of the Plant had been sold at wholesale by Maine Yankee to ten New England electric utilities, which collectively own all of the common equity of Maine Yankee; a portion of that output (approximately 6.2%) was in turn resold by certain of the owner utilities to 29 municipal and cooperative utilities in New England (the Secondary Purchasers). Maine Yankee recovered, and since the shutdown decision has continued to recover, its costs of providing service through a formula rate filed with the FERC and contained in Power Contracts with its utility purchasers, which, as amended, are also filed with the FERC. In November 1997, Maine Yankee submitted for filing certain amendments to the Power Contracts (the Amendatory Agreements) and revised rates to reflect the decision to shut down the Plant and to request approval of an increase in the decommissioning component of its formula rates. Maine Yankee's submittal also requested certain other rate changes, including recovery of unamortized investment (including fuel) and certain changes to its billing formula, consistent with the nonoperating status of the Plant. During 1998 and early 1999, the parties to the FERC proceeding, including, among others, the MPUC staff, the Maine Office of the Public Advocate and the Secondary Purchasers, engaged in extensive discovery and negotiations, which resulted in the filing of a settlement agreement with the FERC in January 1999. A separately negotiated settlement filed with the FERC in February 1999 resolved the issues raised by the Secondary Purchasers by limiting the amounts of their payments for decom-missioning the Plant and by settling other points of contention affecting individual Secondary Purchasers. Both settlements were found to be in the public interest and were approved by the FERC on June 1, 1999. The settlements constitute a full settlement of all issues raised in the FERC proceeding, including decommissioning cost issues and the issues pertaining to the prudence of the management, operation, and decision to permanently cease operation of the Plant. The primary settlement provides for Maine Yankee to recover amounts intended to cover the costs of decommissioning and those associated with the construction and maintenance of an of an off-site independent spent fuel storage installation (ISFSI). The settlement also provides for recovery of the unamortized investment (including fuel) in the Plant, together with a return on equity of 6.50% on limited equity balances. The Settling Parties also agreed not to contest the effectiveness of the Amendatory Agreements submitted to FERC as part of the original filing, subject to certain limitations including the right to challenge any accelerated recovery of unamortized investment under the terms of the Amendatory Agreements after a required informational filing with the FERC by Maine Yankee. In addition, Maine Yankee agreed to file with the FERC a rate proceeding that will have an effective date of no later than January 1, 2004, when major decommissioning activities are expected to be nearing completion. As a separate part of the settlement, the three Maine Sponsors of Maine Yankee, the MPUC Staff, and the Office of the Public Advocate entered into a further agreement (Maine Agreement) resolving retail rate issues and other issues specific to the Maine parties, including those that had been raised concerning the prudence of the operation and shutdown of the Plant. The Company believes that the settlement, including the Maine Agreement, constituted a reasonable resolution of the issues raised in the Maine Yankee FERC proceeding, and eliminated significant uncertainties concerning the Company's future financial performance. Under the Maine Agreement, the Company would continue to recover its Maine Yankee costs, although the allowed return on equity associated with the Company's equity balance in Maine Yankee was set at 6.50%. The final major provision of the Maine Agreement required the Maine owners, for the period from March 1, 2000, through December 1, 2004, to hold their Maine retail ratepayers harmless from the amounts by which the replacement power costs for Maine Yankee exceeded the replacement power costs assumed in the report to the Maine Yankee board of directors that served as a basis for the Plant shutdown decision. As part of a further settlement, the Company's liability was fixed at approximately $2.2 million to be reflected as a reduction in stranded costs effective March 1, 2002. The Company charged to fuel and purchased power expense and recorded as a regulatory liability $2 million in December 2000 representing the net present value of this future obligation. Maine Yankee's most recent estimate of the total costs of decommissioning and plant closure, for the period from 2002 to 2008, excluding funds already collected, is approximately $502 million (undiscounted). The Company's share of the estimated cost at December 31, 2002 is approximately $31.1 million and is recorded as a regulatory asset and decommissioning liability. The regulatory asset was recorded for the full amount of the decommissioning and plant closure costs due to the state's industry restructuring legislation (see Note 10) allowing the Company future recovery of nuclear decommissioning expenses related to Maine Yankee, as well as the Company being allowed a recovery mechanism in its February 2002 rate order for Maine Yankee non-decommissioning plant closure costs. Accumulated decommissioning funds at December 31, 2002 had an adjusted market value of $109.1 million of which the Company's share was approximately $7.6 million. Maine Yankee, starting in 2001, began a program of systematically redeeming its common stock from its owners. In 2001, the Company received approximately $703,000 in proceeds associated with the redemption of 5,264 common shares, while in 2002 the Company received an additional $525,000 in connection with the redemption of 3,955 common shares. At December 31, 2002, the Company holds 25,781 common shares of Maine Yankee. MEPCO - The Company owns 14.2% of the common stock of MEPCO. MEPCO owns and operates electric transmission facilities from Wiscasset, Maine, to the Maine-New Brunswick border. Information relating to the operations and financial position of Maine Yankee and MEPCO appears later in Note 6. In connection with the Company's generation asset sale in May 1999 (see Note 11), the Company sold certain of its rights to MEPCO transmission capacity. Summary Financial Information for Maine Yankee and MEPCO is as follows (dollars in thousands): ----------------------------------------------------------------------- Maine Yankee MEPCO ---------------------------------------------------------------------------- 2002 2001 2000 2002 2001 2000 ---- ---- ---- ---- ---- ---- Operations: As reported by investee- Operating revenues $ 58,924 $ 61,994 $ 43,813 $4,365 $4,514 $4,029 ======== ======== ======== ====== ====== ====== Earnings applicable to common stock $ 3,947 $ 4,371 $ 4,640 $1,068 $1,192 $1,381 ======== ======== ======== ====== ====== ====== Amounts reported by the Company- Purchased power costs $ 4,068 $ 5,198 $ 5,013 $ - $ - $ - Equity in net income (280) (310) (320) ( 168) (195) (157) -------- -------- -------- ------ ------- ------ Net purchased power expense $ 3,788 $ 4,888 $ 4,693 $ (168) $ (195) $ (157) ======== ======== ======== ======= ====== ====== Financial Position: As reported by investee- Total assets $679,975 $802,118 $915,097 $7,680 $6,870 $5,873 Less- Preferred stock - - 15,000 - - - Long-term debt 21,600 31,200 40,800 - - - Other liabilities and deferred credits 600,656 707,643 788,703 608 770 863 -------- -------- -------- ------ ------ ------ Net assets $ 57,719 $ 63,275 $ 70,594 $7,072 $6,100 $5,010 ========= ======== ======== ====== ====== ====== Company's reported equity- Equity in net assets $ 4,040 $ 4,429 $ 4,942 $1,004 $ 866 $ 711 Adjust Company's estimated to actual (6) (7) 8 - (12) (38) --------- -------- -------- ------ ------ ------ Equity in net assets as reported $ 4,034 $ 4,422 $ 4,950 $1,004 $ 854 $ 673 ========= ======== ======== ====== ====== ====== BANGOR VAR CO. - In 1990, the Company formed BVC, whose sole function is to be a 50% general partner in Chester, a partnership which owns a static var compensator (SVC), which is electrical equipment that supports the Phase 2 transmission line. A wholly-owned subsidiary of Central Maine Power Company owns the other 50% interest in Chester. Chester has financed the acquisition and construction of the SVC through the issuance of $33 million in principal amount of 10.48% senior notes due 2020, and up to $3.25 million in principal amount of additional notes due 2020 (collectively, the SVC Notes). The holders of the SVC Notes are without recourse against the partners or their parent companies and may only look to Chester and to the collateral for payment. The New England utilities which participate in Phase 2 have agreed under a FERC approved contract to bear the cost of Chester, on a cost of service basis, which includes a return on and of all capital costs. NEPOOL/HYDRO-QUEBEC PROJECT - The Company is a 1.6% participant in the NEPOOL/Hydro-Quebec Phase 1 project (Phase 1), a 690 MW DC intertie between the New England utilities and Hydro-Quebec constructed by a subsidiary of another New England utility at a cost of about $140 million. The participants receive their respective share of savings from energy transactions with Hydro-Quebec, and are obliged to pay for their respective shares of the costs of ownership and operation whether or not any savings are realized. The Company is also a 1.5% participant in the NEPOOL/Hydro-Quebec Phase 2 project (Phase 2), which involves an increase to the capacity of the Phase 1 intertie to 2,000 MW. As in the Phase 1 project, the Company receives a share of the anticipated energy cost savings derived from purchases from Hydro-Quebec and capacity benefits provided by the intertie and is required to pay its share of the costs of ownership and operation whether or not any savings are obtained. In connection with the generation asset sale in May 1999, the Company sold its rights as a participant in the regional utilities agreement with Hydro-Quebec (see Note 11). The Company, though, is still required to pay its share of the costs of ownership and operation of the Hydro-Quebec intertie. Also in connection with the asset sale, PP&L Global (PP&L) has agreed to pay the Company $400,000 per year to partially offset the Company's on-going Hydro-Quebec support payments. Since the Company still has an obligation for the costs of the Hydro-Quebec intertie, but it has sold the rights to the benefits as a participant, an approximately $5.6 million liability (included in Other Long-term Liabilities) and corresponding regulatory asset (included in Other Regulatory Assets) have been recorded as of December 31, 2002 on the Consolidated Balance Sheet representing the present value of the Company's estimated future payments (net of the $400,000 to be received from PP&L) for costs of ownership and operation of the Hydro-Quebec intertie. POWER SUPPLY COMMITMENTS - As of the end of 2002, the Company had long- term power supply 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. As discussed below, the power purchased under these contracts are resold to third parties under a separate contracts. 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. The Company's purchased power expense under this contract was approximately $6.3 million in 2002, $5.7 million in 2001 and $6.7 million in 2000, and is projected to be approximately $6.8 million in each of 2003 and 2004 and to steadily decrease over the remainder of the contract down to approximately $4 million in the last full year, 2023. In late July 1999, in connection with the generation asset sale, the Company sold PHC to PP&L and received $10 million in proceeds. The sale resulted in a gain of approximately $5.2 million, of which $4.7 million was deferred as part of the deferred asset sale gain (see Note 11). The remaining $.5 million of the gain related to the portion of the gain on sale of PHC which was allocable to shareholders. PERC - 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. A portion of the PERC output is resold to a third party under a power sales contract that ends in February 2003 (discussed below). The Company's purchased power expense under this contract was approximately $20.2 million in 2002, $19.3 million in 2001 and $19.1 million in 2000, and is projected to be approximately $17.2 million in 2003, $17.6 million in 2004, and to increase over the remainder of the contract up to $22 million in the last full year, 2017. Also as a result of a 1998 contract restructuring (discussed below), PERC will share the net revenues generated by the facility on a pro rata basis with the Company and the MRC, which represents over 130 Maine municipalities receiving waste disposal service from PERC. In 2002, 2001 and 2000 the Company realized $3.6 million, $3.5 million and $3.5 million, respectively, in savings associated with its share of PERC net revenues. The Company expects to realize similar levels of savings through the term of the PERC contract. Other Power Supply Commitments - The Company entered into a contract, which started on March 1, 2001, for the delivery of up to 160 MW of power from a third party, ending February 28, 2004. The energy delivered in connection with the contract was used to serve a portion of the standard offer service customer load through February 28, 2002. Subsequent to this date, the Company has resold this power to one of the new standard offer service providers in the Company's service territory. The Company's purchased power expense under this contract was approximately $37.5 million in 2002 and $21 million in 2001, and is estimated to be approximately $24.1 million in 2003 and $3.5 million in 2004. The non-standard offer related revenues associated with the resale of power amounted to $20.2 million in 2002 and is estimated to be approximately $17.1 million in 2003 and $2.7 million in 2004. This resale of power is recorded as a component of Off-system Sales in the Consolidated Statements of Income for 2002. See Note 10 for a discussion of the standard offer service. In late 1999 the Company selected the winning bidder for all of the capacity and energy from its six purchased power contracts being auctioned off pursuant to Chapter 307 of the MPUC's rules for regulation of electric utilities. The contract commenced March 1, 2000, the date when retail customer choice for power supply commenced in Maine, and continued through February 28, 2002. The Company recorded $1.4 million, $4.4 million and $4.5 million in revenues from the resale of power under this contract in 2002, 2001 and 2000, respectively. These revenues are recorded as a component of Off-system Sales in the Consolidated Statements of Income. In the fall of 2001, the MPUC selected the winning bidder to supply the small customer class of standard offer service starting in March 2002. Their bid was contingent upon being selected as buyer of all of the capacity and energy from the Company's previously discussed six purchased power contracts, two-year standard offer related energy supply contract and the output of the Company's diesel units. The period of sale commenced on March 1, 2002, and will continue for a period of three years. The revenues realized under this contract (excluding the portion related to the two-year standard offer related energy supply contract discussed above), as well as the final two months in 2002 of the previous Chapter 307 sales related contract, were approximately $5.8 million in 2002, and are estimated to be $8.5 million in 2003, $8.4 million 2004 and $1.4 million in 2005. This resale of power is recorded as a component of Off-system Sales in the Consolidated Statements of Income for 2002. The Company is also party to a power sales contract with another utility that ends in February 2003. The source of the power to supply this customer is from a portion of the PERC purchased power contract and from market purchases. The portion of the power sales contract associated with market purchases ended in August 2002. The Company realized $12.3 million, $14.5 million and $14.7 million of revenues under this contract in 2002, 2001 and 2000, and these amounts are reflected recorded as a component of Off-system Sales in the Consolidated Statements of Income. Rate Recovery - For a discussion of the rate recovery associated with these power supply commitments, see Note 10. PURCHASED POWER CONTRACT BUYOUTS AND RESTRUCTURING - During the 1990's, the Company attempted to alleviate the adverse impact of high-cost contracts with small power production facilities. One method for doing so was 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. 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 were secured by a mortgage on the property of the Beaver Wood facility. In each of the years from 1994 through 1997 the Company received its $1 million payment. The Company was entitled to receive the final two payments totaling $2 million in 1998 and 1999 from Beaver Wood. However, in July 1998, Beaver Wood indicated that it would not be making the payment due at that time and requested the Company agree to a lower payment. After assessing the potential costs and benefits of foreclosing on the mortgage, the Company determined that accepting a payment of $1.75 million would be a better alternative. This $1.75 million payment was received in February 1999. The Company has recorded the $250,000 shortfall as a regulatory asset as of December 31, 2001, and this amount will be recovered from customers in connection with the Company's stranded cost recovery. The Company established a regulatory asset associated with the cost of the buyout, and 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. This regulatory asset is being amortized at an annual rate of $3.9 million through February 2003. The 1995 transactions involved a "buyback" of the contracts for the purchase of power from two biomass-fueled generating plants in West Enfield and Jonesboro, Maine, which are identical plants under common ownership. The buyback cost, which was financed entirely by new debt instruments (See Note 5) was approximately $170 million, including transaction costs. The buyback costs were deferred and recorded as a regulatory asset and are being amortized and collected over a ten-year period, beginning July 1, 1995, at an annual expense of $17 million. Effective with the implementation of new stranded cost rates on March 1, 2002, the amortization period for this regulatory asset was extended until February 28, 2006, and the annual expense was reduced to $14.2 million. In June 1998 the Company successfully completed a 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. As previously discussed, in connection with this restructuring, PERC will share the net revenues generated by the facility on a pro rata basis with the Company and the MRC over the remaining term of the PERC contract. which represents over 130 Maine municipalities receiving waste disposal service from PERC. The Company also made a one-time payment of $6 million to PERC in June 1998 and made additional quarterly payments, starting in October 1998, of $250,000 for four years totaling $4 million. These amounts are recorded were regulatory assets when the payments were made. Finally, in connection with the PERC contract restructuring in 1998, the Company issued two million warrants to purchase common stock, one million each to PERC and the MRC. Each warrant entitled the warrant holder to acquire one share of the Company's common stock at a price of $7 per share. No warrants could be exercised within the first nine months after their issuance, and they were 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 had 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 established a cap on ratepayers' exposure to the cost of the warrants. Ratepayer costs were 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. This cap was further modified by the MPUC in 2001 in connection with the approval of the Company's merger with Emera. For any warrants which were exercised after the merger approval in January 2001, the cap on the ratepayers' exposure was set at $10.50 per share ($17.50 per share less the $7 exercise price). The Company will not recover any costs above the cap from ratepayers, and as previously discussed, these amounts were charged against paid-in capital in 2001. As previously discussed in Note 4, in 2001, the remaining 1,437,215 of outstanding common stock warrants were exercised. For 736,315 of these warrants, the Company exercised its option to pay cash to the holders of the warrants instead of actually issuing shares of common stock. These payments amounted to approximately $14.2 million. For 700,900 of unexercised warrants associated with the MRC, the Company and the MRC entered into an agreement whereby the Company, instead of issuing shares or paying cash, established the previously discussed note payable to the MRC. As a result of the exercise of the warrants in 2001 and the affects of the cap on the ratepayers' exposure as set by the MPUC, the Company increased its regulatory asset associated with the PERC contract restructuring by approximately $13.7 million in 2001. In 2000 and 1999, 212,786 and 349,999 common stock warrants were exercised (at a market prices below the book value per common share at the time of the exercise), respectively, and the Company exercised its option to pay cash to the holders of the warrants instead of actually issuing shares of common stock. These payments amounted to approximately $2.5 million in 2000 and $3.3 million in 1999. As a result of the exercise of the warrants in 2000 and 1999 and the cap on the ratepayers'exposure as set by the MPUC, the Company increased its regulatory asset associated with the PERC contract restructuring by approximately $1.9 million in 2000 and $2.9 million in 1999. As of December 31, 2002, the Company has deferred, as a regulatory asset, approximately $27.6 million in costs associated with the PERC contract restructuring. In its stranded cost rates, the Company is recovering, over the remaining term of the PERC contract, the full amount of deferred PERC restructuring costs, including the value of warrants exercised and the additional $250,000 quarterly payments discussed above, amounting to an annual amortization of $1.7 million per year. Note 8. 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. The regulatory asset is being recovered as a component of the Company's stranded costs, and the annual amortization expense amounts to approximately $1.7 million. Note 9. Fair Value of Financial Instruments ------------------------------------------- The following represents the estimated fair value at December 31, 2002 of each class of financial instrument for which it is practical to estimate the value: Cash and cash equivalents-including money market funds and repurchase agreements: the carrying amount of $988,752 approximates fair value. Funds held by trustees, associated with miscellaneous special deposits- U.S. Treasury Bills: the carrying amount of $1,007,252 approximates fair value. The fair values of other financial instruments at December 31, 2002 based upon similar issuances of comparable companies are as follows: (In Thousands) Carrying Amount Fair Value --------------- ---------- Funds held by trustee-guaranteed investment contract $21,191 $23,421 First Mortgage Bonds 65,000 83,917 FAME Revenue Notes 55,400 59,693 Senior Unsecured Note 20,000 20,172 Municipal Review Committee Note Payable 11,781 11,769 Short-term debt 16,000 16,000 Note 10. Industry Restructuring and Rate Regulation --------------------------------------------------- In 1997, the Maine legislature enacted a comprehensive law providing for the restructuring of the electric industry in Maine. The principal aspects of the law were as follows: - Effective March 1, 2000, retail consumers of electricity had the right to purchase energy supply directly from competitive electricity suppliers; - Electric utilities were required to divest of their generating assets and restrictions were imposed limiting their participation in generation and marketing activities; - Electric utilities were provided with the opportunity to recover their prudently incurred stranded costs; and - The MPUC was directed to conduct a competitive solicitation process to select a standard-offer provider to serve the needs of customers unable to find a competitive supplier or uninterested in doing so. The Maine restructuring law has essentially been fully implemented. As a result of the industry restructuring, the Company has been primarily engaged in the transmission and distribution of electric energy. Electric rates for the Company's customers are divided into four components, which are discussed below, (i) transmission, (ii) distribution, (iii) stranded costs, and (iv) energy service. The rates charged to customers for transmission, distribution and stranded costs are established in distinct regulatory proceedings. The Company's revenues are generated by a delivery charge encompassing transmission, distribution and stranded costs, and the Company is not presently involved in supplying energy to retail customers. The delivery charge, though, continues to be based on customers electricity usage measured in kilowatt hours ("kWh"). Sales of the Company's Generating Assets - 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. On May 27, 1999, the Company completed most of the transaction for the sale of its electric generating assets and certain transmission rights to PP&L. The purchase price for the assets transferred was $79 million. The sale involved all but one of the Company's hydroelectric plants on the Penobscot, Piscataquis, and Union rivers and Bangor Hydro's 8.33% ownership interest in the Wyman Unit #4 oil-fired plant in Yarmouth, Maine-a total base load capacity of 83 megawatts. The sale also involved a transfer by the Company of rights to transmit power over the MEPCO transmission facilities connecting NEPOOL to New Brunswick Canada; the Company's rights as a participant in the regional utilities' agreement with Hydro-Quebec pursuant to an agency agreement; and the Company's rights to develop a second high voltage transmission line that will connect NEPOOL to New Brunswick, Canada. The Company realized a net gain on the sale related to these sales of approximately $29.8 million, and $29.3 million of this amount was recorded as a deferred liability at February 29, 2000, on the Consolidated Balance Sheets. As discussed in Note 7, the other $.5 million of the gain on the sale of Penobscot Hydro that was allocable to shareholders, pursuant to orders of the MPUC, was recorded as other income in 1999. Effective with the March 1, 2000 rate change, the Company began amortizing the deferred asset sale gain over a 70-month period. The annual amortization amounts are being recorded in an uneven manner in order to levelize the Company's revenue requirement over this period. As a result of an increase in the Company's FERC regulated transmission rates on June 1, 2000, and the desire to not increase rates to its retail customers so close to the implementation of electric industry restructuring, which occurred on March 1, 2000, the Company agreed to reduce its MPUC jurisdictional distribution rates in an amount equal to the increase in its transmission rates. The reduction in the distribution rates was accomplished by accelerating the amortization of the deferred asset sale gain through May 2001 by an annualized total of $2.5 million. Effective April 15, 2001, and through February 28, 2002, in an effort to mitigate the effects of increased energy prices for the Company's large customers, the MPUC ordered the Company to reduce its distribution and stranded cost electric rates to certain large customers by $.008/kWh. To fund this rate reduction and corresponding decrease in revenues, the MPUC ordered the Company to accelerate the amortization of the deferred asset sale gain in an amount necessary to offset the estimated decrease in revenues caused by the rate reduction. The asset sale gain amortization was increased by approximately $2.5 million over the 10 1/2 month period the reduced rates was in effect. Also, the Company's FERC jurisdictional transmission rates changed on June 1, 2001. Consistent with 2000, the Company reduced its distribution rates via an adjustment to the asset sale gain amortization to offset the change in the transmission rates effective June 1, 2001. The annualized accelerated amortization associated with the transmission rate change amounts to approximately $1.6 million and ends in May 2002. In April 1999 Central Maine Power Company (CMP), sold all of its interest in the Wyman generating units and ancillary property, including its 59% interest in Unit 4. On August 31, 1999, 11 minority owners of Wyman #4, including Bangor Hydro, served a Demand for Arbitration on CMP with respect to the sale of Wyman #4. The Demand asserted that the minority owners were entitled to a share of the proceeds from CMP's sale of Wyman. On April 23, 2001, CMP and the minority owners reached a settlement agreement to dispose of all claims raised in the Demand for Arbitration. Under the terms of the agreement, CMP agreed to pay the minority owners $12 million in exchange for a full release from all claims arising from CMP's sale of Wyman. In July 2001 the MPUC issued an order approving the settlement agreement, and in October 2001 the Company received its share of the settlement from CMP amounting to approximately $2.6 million. This amount was deferred as a regulatory liability per the MPUC order, and the Company began returning this amount to customers starting March 1, 2002 over a two year period in connection with a change in its stranded cost rates. DISTRIBUTION SERVICE Distribution revenues represent approximately 50% of the Company's total electric operating revenues. On June 6, 2002, the MPUC approved an Alternative Rate Plan (ARP) and dismissed a pending management investigation of the Company. The terms of the ARP include a rate plan to be in effect through December 31, 2007, with the Company's core distribution rates being adjusted downward on July 1 of each year from 2003 to 2007, at annual rates ranging from 2% to 2 3/4%. The Company is also allowed rate adjustments associated with certain specified categories of costs. The ARP also includes a mechanism whereby distribution returns on common equity below 17% and above 5% in any given year will be retained by the Company. Earnings in excess of this range and earnings shortfalls below the range will be shared evenly between the Company and ratepayers. The Company is also required to meet certain customer service quality standards during the term of the ARP, and rate reduction penalties will result from not meeting the various performance measures as set forth in the stipulation. Finally, the ARP provides the Company with an accounting order allowing for the deferral and ten year amortization of employee transition costs during 2002 and 2003 in connection with reductions in the cost of operations. Successful implementation of the ARP necessitated a significant decrease in the Company's operating costs, and as a result, the Company reorganized its operations in 2002. The internal restructuring, which encompasses all aspects of the Company, has reduced operating costs by approximately 20%-25%. The Company is also beginning to transfer a portion of its fixed costs to variable costs, and improve processes to enhance long-term performance. As part of the restructuring, employment levels were reduced by approximately 25% in the second and third quarters of 2002 through early retirement and severance arrangements. The total employee transition costs incurred in 2002 were approximately $8.1 million and are recorded as a component of Other Regulatory Assets on the consolidated balance sheets at December 31, 2002. These deferred costs are being amortized over a ten-year period, starting in June 2002. STRANDED COST SERVICE Stranded cost revenues represent approximately 40% of the Company's total electric operating revenues. Pursuant to the Maine restructuring law, electric utilities are entitled to recover all prudently incurred stranded costs that cannot reasonably be mitigated. In February 2002, the MPUC issued an order allowing the Company to increase its rates to recover the stranded costs created as a result of the restructuring of the electric utility industry in the State of Maine. The stranded cost rate increase, effective March 1, 2002, resulted in the Company's total electric rates increasing by approximately 6.5%. The stranded cost rates are set for a period not to exceed three years, although the Company has the right to seek adjustments to these rates if certain economic situations occur. 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. In connection with the Company's stranded cost rate proceeding with the MPUC the principal regulatory assets and liabilities being recovered from/returned to customers as stranded costs are as follows: - Maine Yankee decommissioning and other closure costs (See Note 7) - Obligations associated with Hydro-Quebec (See Note 7) - The cost of energy and capacity associated with the power purchase contracts, net of revenues from resale (See Note 7) - Purchased power contract buyout and restructuring costs (See Note 7) - Seabrook investment (See Note 8) - Deferred special rate contract revenues (See below in Note 10) - Deferred asset sale gain (See Above in Note 10) - Deferred standard offer costs (See Below in Note 10) - Deferred Maine Yankee replacement power cost write-off (See Note 7) Deferred Special Rate Contract Revenues - Also in connection with the February 2000 rate order from the MPUC, and starting March 1, 2000, the Company was granted a deferral mechanism for the difference in actual revenues realized from customers under special rate contracts as compared to the estimated revenues from these customers utilized in setting the Company's new electric rates starting March 1, 2000. Under this deferral mechanism, the Company recorded a regulatory asset and additional revenues of approximately $1.4 million for the period from March 1, 2000 through December 31, 2000. In 2001, the Company's special rate contract revenue deferrals amounted to approximately $1.6 million, of which $2.3 million was recorded as additional revenue and $700,000 was recorded as an increase in goodwill. The increase in goodwill was a result of certain adjustments to the deferrals approved by the MPUC in the Company's recent stranded cost rate proceeding. In 2002, for January and February, the Company recorded a regulatory asset and additional revenues of approximately $.6 million. Effective March 1, 2002, with the implementation of new stranded cost rates, these deferrals ceased, and the Company began amortizing the deferred special rate contract revenue regulatory asset balance over a four year period. Effective March 1, 2002, the Company began recording new special rate contract revenue deferrals in connection with a new rate contract with a large industrial customer. The Company is realizing stranded cost related revenues from this customer that are in excess of amounts assumed in the latest stranded cost rate proceeding. As a result, and as ordered by the MPUC, the Company is recording a reduction in the deferred special rate contract revenue regulatory asset and a reduction in revenues. The revenue deferrals associated with this customer amounted to $.5 million for the period from March 2002 to December 2002. The net deferred special rate contract revenue regulatory asset amounts to $2.5 million at December 31, 2002 and is included as a component of Other Regulatory Assets in the Consolidated Balance Sheets. TRANSMISSION SERVICE Transmission revenues represent approximately 10% of the Company's total electric operating revenue. The regulation of electric transmission has also been undergoing substantial restructuring. In New England, these changes have included the restructuring of NEPOOL and the formation of the New England Independent System Operator, ISO-New England (ISO-NE) in March 1997. ISO-NE is an independent entity operating under contract with NEPOOL to manage the New England region's electric bulk power generation and transmission systems and administering the region's open access transmission tariff. The Company's transmission facilities are already under the operational control of ISO-New England and rates for retail transmission service are subject to FERC jurisdiction. In February 2001, the FERC last issued an order approving transmission rates for service provided on or after March 1, 2000. Under the FERC Order approving these transmission rates, a "formula" rate was approved, allowing the Company to adjust its rates annually to reflect changes in the Company's costs and its sales volume during the preceding calendar year. The Company's transmission rate formula will be subject to review by FERC during 2003. In addition, ongoing FERC initiatives to restructure the transmission industry may ultimately result in a different transmission cost recovery structure. ENERGY SERVICE The Company is not presently engaged in selling energy to customers. Pursuant to the Maine restructuring law, all customers have the right to select a competitive energy supplier to serve their energy requirements. For customers unable to do so, or uninterested in doing so, standard offer service is provided by default. The MPUC is responsible for selecting a standard offer provider through a competitive solicitation process. The solicitation process is anticipated to be conducted every three years for residential and small commercial customers and every year for large commercial and industrial customers. For the period March 2000 through February 2002, the MPUC rejected results of the competitive solicitation process for the Company's customers and directed the Company to arrange for standard offer service. The MPUC established the schedule of rates the Company could charge for this service starting March 1, 2000. The Company entered into arrangements with third parties to purchase the energy to serve the standard- offer customers. The Company was allowed by the MPUC to defer, for future ratemaking treatment, the difference between revenues realized from the standard-offer sales and the costs incurred to provide this service, including carrying costs on the deferred balance. Since March 1, 2000, when new rates went into effect, on a cumulative basis, the revenues realized from standard offer customers exceeded the costs of providing the standard offer service, and consequently, the Company recorded a regulatory liability. Effective March 1, 2002, with the implementation of new stranded cost rates as approved by the MPUC, the Company began amortizing the deferred standard offer liability balance over a two year period. The deferred balance amounted to approximately $1 million as of December 31, 2002 (which is included in Other regulatory liabilities on the Consolidated Balance Sheets). Also, as previously discussed, effective March 1, 2002, as a result of new bids received from competitive energy providers, the Company is no longer serving as the standard offer service provider. The Company is, though, serving as the billing and collection agent under the standard offer program. As a result of the previously discussed reconciliation mechanism, standard-offer related revenues and expenses do not have any impact on the Company's earnings, although they do result in increases in both categories in the Company's Consolidated Statements of Income. Consequently, the Consolidated Statement of Income for 2002, 2001 and 2000 has been modified to reflect the separate presentation of standard-offer service revenues and purchased power expenses. Regulatory Assets and Meeting the Requirements of SFAS 71 - The Company is subject to the provisions of Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS 71). SFAS 71 allows the establishment of regulatory assets for costs accumulated for certain items other than the usual and customary capital assets, and allows the deferral of the income statement impact of those costs if they are expected to be recovered in future rates. As of December 31, 2002, the Company has regulatory assets, net of regulatory liabilities, of approximately $225.7 million. The Company continues to meet the requirements of SFAS 71 since the Company's rates are intended to recover the cost of service plus a rate of return on the Company's investment, as well as providing specific recovery of costs deferred in prior periods. The legislation enacted in Maine associated with industry restructuring specifically addressed the issue of cost recovery of regulatory assets stranded as a result of industry restructuring. Specifically, the legislation requires the MPUC, when retail access begins, to provide a "reasonable opportunity" for the recovery of stranded costs through the rates of the transmission and distribution company, comparable to the utility's opportunity to recover stranded costs before the implementation of retail access under the legislation. The final rate orders from the MPUC effective March 1, 2000 and March 1, 2002 did not result in the Company writing off any stranded costs, but if the Company had not been allowed full recovery of its stranded costs, it would be required to write-off any disallowed costs. As provided for in Emerging Issues Task Force Issue No. 97-4, "Deregulation of the Pricing of Electricity," the Company will continue to record regulatory assets in a manner consistent with SFAS 71 as long as future recovery is probable, since the Maine legislation provides the opportunity to recover regulatory assets including stranded costs through the rates of the T&D company. The Company anticipates, based on current generally accepted accounting principles, that SFAS 71 will continue to apply to the regulated T&D segments of its business. If the Company failed to meet the requirements of SFAS 71, due to legislative or regulatory initiatives, the Company would be required to apply Statement of Financial Accounting Standards No. 101, "Regulated Enterprises-Accounting for the Discontinuation of Application of FASB No. 71" (SFAS 101). If legislative or regulatory changes and/or competition result in electric rates which do not fully recover the Company's costs, a write-down of regulatory assets would be required. The Company does not anticipate any write-down of assets at this time. Note 11. Construction of Facilities for Casco Bay Energy -------------------------------------------------------- The Company entered into an agreement with Casco Bay whereby the Company agreed to construct various transmission facilities required to allow a generating facility being constructed in Veazie, Maine to interconnect with the Company's electrical system and deliver its output to the New England Power Pool Transmission Facility (PTF) grid. Under this agreement, Casco Bay agreed to advance funds necessary to pay for such construction. Pursuant to a FERC order approving an amendment to the NEPOOL Agreement, approximately 50% of the construction funds advanced are being refunded to Casco Bay by customers of NEPOOL over an approximately 30-year period. The Company began refunding such construction costs to Casco Bay starting in June 2000. The refunds amounted to approximately $582,000 in 2002, $513,000 in 2001 and $300,000 in 2000. At the end of 2002, the Company had recorded approximately $4 million of electric plant in service for these PTF facilities and a corresponding long-term payable of $3.8 million. The long-term payable is included on the Consolidated Balance Sheets as a component of Other Long-term Liabilities. Note 12. Derivative Financial Instruments ------------------------------------------- Effective January 1, 2001, the Company adopted Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS No. 138. This new accounting standard requires that all derivative instruments be recorded on the balance sheet at fair value and establishes criteria for designation and effectiveness of hedging relationships. The effect of adopting this standard was not material to the Company's consolidated financial statements. The accounting for derivative financial instruments can change based on guidance received from the Derivatives Implementation Group (DIG). The DIG identifies practice issues that arise from applying the requirements of SFAS 133 and advises the Financial Accounting Standards Board on how to resolve those issues. PURCHASED POWER CONTRACTS - In the second quarter of 2001, the DIG reached a conclusion as to the interpretation of clearly and closely related contracts that qualify for the normal purchase and sales exception under SFAS 133. The conclusion of the DIG was that for contracts with prices indexed to the Consumer Price Index (CPI), these would not qualify for the normal purchase and sale exception under SFAS 133 and would need to be accounted for as derivatives under this statement effective July 1, 2001. The Company has two power contracts (one purchase and one sale) with prices indexed to a broad price measure similar to the CPI, that were excluded from the scope of SFAS 133 on January 1, 2001, as a result of the normal purchase and sale exception. Given the DIG's conclusion, the Company, effective July 1, 2001, began to account for these power contracts as derivatives in accordance with SFAS 133 and recorded them at fair value on the Company's consolidated balance sheet in the third quarter of 2001. The fair value of the above-market portion of these contracts as of December 31, 2002 and 2001 represents a liability of approximately $63.3 million and $74 million, respectively. The Company has recorded a regulatory asset to offset this liability, since the Company is currently recovering the net above-market cost of these contracts as part of its stranded cost recovery. As a result of this regulatory accounting, the recording of these contracts on the Company's consolidated balance sheet does not result in an impact on earnings. WEATHER HEDGE - In November 2002 the Company purchased a weather hedge for the 2002-2003 heating season. The hedge is designed to protect against the negative impacts of warmer than normal weather on the Company's electric operating revenues. The cost of the weather hedge was approximately $87,000 which is being amortized over the 2002- 2003 heating season. No income was recognized for this weather hedge in 2002 due to the colder than normal weather. The fair value of this financial instrument at December 31, 2002 is de minimis. Note 13. Contingencies ---------------------- ENVIRONMENTAL MATTERS - In 1992, the Company received notice from the Maine Department of Environmental Protection that it was investigating the cleanup of several sites in Maine that were used in the past for the disposal of waste oil and other hazardous substances, and that the Company, as a generator of waste oil that was disposed at those sites, may be liable for certain cleanup costs. The Company learned in October 1995 that the United States Environmental Protection Agency placed one of those sites on the National Priorities List under the Comprehensive Environmental Response, Compensation, and Liability Act and will pursue potentially responsible parties. With respect to this site, the Company is one of a number of waste generators under investigation. The Company has recorded a liability, based upon currently available information, for what it believes are the estimated environmental remediation costs that the Company expects to incur for this waste disposal site. Additional future environmental cleanup costs are not reasonably estimable due to a number of factors, including the unknown magnitude of possible contamination, the appropriate remediation methods, the possible effects of future legislation or regulation and the possible effects of technological changes. At December 31, 2002, the liability recorded by the Company for its estimated environmental remediation costs amounted to approximately $411,000. The Company's actual future environmental remediation costs may be different as additional factors become known. Note 14. New Accounting Pronouncement -------------------------------------- In June 2002, the Financial Accounting Standards Board issued Statement No. 143, "Accounting for Asset Retirement Obligations". This Statement addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. It applies to legal obligations associated with the retirement of long-lived assets that result from acquisition, construction, development and (or) the normal operation of a long-lived asset, except for certain obligations of lessees. This Statement is effective for financial statements issued for fiscal years beginning after June 15, 2002. Management does not believe that the implementation of this Statement will materially impact the Company's financial position, earnings or cash flows, principally as a result of the regulatory accounting utilized by the Company. Note 15. Unaudited Quarterly Financial Data ------------------------------------------- Unaudited quarterly financial data pertaining to the results of operations are shown below (Dollars in thousands except for per share amounts): Quarters Ended ------------------------------------------- Mar. 31, June 30, Sept. 30, Dec. 31, --------- -------- --------- -------- 2002 ---- Operating Revenues $ 48,645 $ 38,285 $ 40,881 $ 39,927 Operating Income 6,292 4,559 7,008 6,178 Net Income 3,028 1,765 4,301 3,367 Basic Earnings Per Share of Common Stock $ .40 $ .23 $ .58 $ .45 ======== ======== ======== ======== 2001 ---- Operating Revenues $ 56,204 $ 54,003 $ 55,570 $ 51,631 Operating Income 7,627 3,169 6,099 6,722 Net Income (Loss) 4,584 (201) 3,062 1,244 Basic Earnings (Loss) Per Share of Common Stock $ .61 $ (.04) $ .41 $ .16 ======== ======== ======== ======== 2000 ---- Operating Revenues $ 50,121 $ 48,563 $ 58,641 $ 55,012 Operating Income 8,307 4,652 6,535 6,930 Net Income 3,937 1,339 3,940 1,885 Basic Earnings Per Share of Common Stock $ .53 $ .17 $ .53 $ .25 ======== ======== ======== ======== ERNST & YOUNG Ernst & Young LLP Phone: (617) 266-2000 200 Clarendon Street Fax: (617) 266-5843 Boston, Massachusetts 02116-5072 www.ey.com Report of Independent Auditors To the Stockholders and Directors of Bangor Hydro-Electric Company We have audited the consolidated financial statements listed in the index appearing under Item 14(a) and the financial statement schedule appearing under Item 14(b) as of December 31, 2002 and 2001, and for the years then ended. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audit. We conducted our audit in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion. In our opinion, the 2002 and 2001 consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Bangor Hydro-Electric Company at December 31, 2002 and 2001, and the consolidated results of its operations and its cash flows for the year then ended in conformity with accounting principles generally accepted in the United States. Also, in our opinion, the related financial statement schedules, when considered in relation to the basic financial statements taken as a whole, present fairly in all material respects the information set forth therein. As discussed in Note 1 to the consolidated financial statements, in 2002 the Company adopted Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets" and Financial Accounting Standards No. 141, "Business Combinations". February 5, 2003 /s/ Ernst & Young LLP Ernst & Young LLP is a member of Ernst & Young International, Ltd. Item 9 Changes in and Disagreements with Independent Accountants on Financial Disclosure --------------------------------------------------------------------- At a regularly scheduled meeting of the Board of Directors held on November 21, 2001, the Board appointed Ernst & Young LLP, P.O. Box 2007, Station CRO, 13th Floor, 1959 Upper Water Street, Halifax, N.S. B3J 2Z1 to serve as the Company's Independent Public Accountants for the Company's 2001 and 2002 fiscal years, thereby discontinuing the Company's retention of PricewaterhouseCoopers, LLP, One Post Office Square, Boston, Massachusetts 02109, in this capacity. The decision to change accountants was approved by the Audit Committee of the Board. Ernst & Young serves as independent auditors to Emera Inc., a parent of the Company. PricewaterhouseCoopers report on the financial statements for 2000 did not contain any adverse opinion or a disclaimer of opinion, nor was it qualified or modified as to uncertainty, audit scope, or accounting principles. During the Company's 2000 fiscal year and during 2001 prior to the retention of Ernst & Young, the Company had no disagreements with PricewaterhouseCoopers on any matter of accounting principles or practices, financial statement disclosure, or auditing scope or procedure, which disagreement(s), if not resolved to the satisfaction of the former accountant, would have caused it to make reference to the subject matter of the disagreement(s) in connection with its report. During the two most recently completed fiscal years or during 2001, PricewaterhouseCoopers (A) did not advise the Company that the internal controls necessary for the Company to develop reliable financial statements do not exist; (B) did not advise the Company that information had come to their attention that had led them to no longer be able to rely on management's representations, or that had made them unwilling to be associated with the financial statements prepared by management; (C) did not advise the Company of the need to expand significantly the scope of its audit, or that information had come to their attention during the two most recently completed fiscal years or during 2001, that if further investigated may: (i) materially impact the fairness or reliability of either: a previously issued audit report or the underlying financial statements; or the financial statements issued or to be issued covering the fiscal period(s) subsequent to the date of the most recent financial statements covered by an audit report (including information that may prevent it from rendering an unqualified audit report on those financial statements), or (ii) cause them to be unwilling to rely on management's representations or be associated with the Company's financial statements, and therefore the discontinuation of the retention of PricewaterhouseCoopers did not prevent such an expansion of the scope of their audit or their ability to conduct such further investigation; and (D)(1) did not advise the Company that information had come to their attention that they had concluded materially impacted the fairness or reliability of either (i) a previously issued audit report or the underlying financial statements, or (ii) the financial statements issued or to be issued covering the fiscal period(s) subsequent to the date of the most recent financial statements covered by an audit report (including information that, unless resolved to PricewaterhouseCoopers' satisfaction, would prevent them from rendering an unqualified audit report on those financial statements), and therefore the dismissal of PricewaterhouseCoopers' did not prevent the resolution of any issue that had not been resolved to PricewaterhouseCoopers' satisfaction prior to discontinuation of the retention of PricewaterhouseCoopers. By letter to the Company dated as of December 18, 2001, a copy of which was filed with the Securities and Exchange Commission by the Company as an Amendment to its 2001 Proxy Statement on February 21, 2002, PricewaterhouseCoopers stated that it agreed with the Company's statements relating to the change in accountants that were included in the Company's Proxy Statement for the annual meeting of shareholders held on December 19, 2001. The Company's statements in that Proxy Statement are identical in all material respects to the statements contained herein. Since the appointment of Ernst & Young as the Company's independent auditors in 2001, the Company has had no disagreements with Ernst & Young regarding financial disclosure. PART III -------- Item 10 Directors and Executive Officers of the Registrant ----------------------------------------------------------- The following is a list of the directors and executive officers of the Company, and for each a description of the following: (i) current principal occupation or employment and the name, principal business and address of any corporation or organization in which the employment or occupation is conducted; (ii) material occupations, positions, offices or employment during the past five years, giving the starting and ending dates of each and the name, principal business and address of any corporation or other organization in which the occupation, position, office or employment was carried on; and (iii) country of citizenship. Unless otherwise noted below, none of the following persons has been convicted in a criminal proceeding during the past five years (excluding traffic violations or similar misdemeanors), and none of the following persons has during the past five years been a party to any judicial or administrative proceeding (except for matters that were dismissed without sanction or settlement) that resulted in a judgment, decree or final order enjoining the person from future violations of, or prohibiting activities subject to, federal or state securities laws, or a finding of any violation of federal or state securities laws. NAME AGE POSITION ---- --- -------- David McD. Mann 63 Chairman of the Board Christopher G. Huskilson 45 Director, Vice Chairman Jane J. Bush 57 Director Norman A. Ledwin 60 Director Elizabeth A. MacDonald 56 Director Ronald E. Smith 52 Director Raymond R. Robinson 44 Chief Operating Officer David R. Black 55 Treasurer, Controller, CFO David McD. Mann has been a Director and Chairman of the Board since Bangor Hydro's merger with Emera in October, 2001. Mr. Mann also serves as President and Chief Executive Officer and Director of Emera Inc. Until July, 1996, Mr. Mann was a senior partner with the Halifax, Nova Scotia law firm of Cox Downie. Mr. Mann's business address is 1894 Barrington Street, Halifax, Nova Scotia B3J 2A8. Mr. Mann is a citizen of Canada. Christopher G. Huskilson has been a Director and Vice Chairman of the Board since Bangor Hydro's merger with Emera in October, 2001. Mr. Huskilson also serves as Chief Operating Officer of Nova Scotia Power Inc., a subsidiary of Emera. Mr. Huskilson's business address is 1894 Barrington Street, Halifax, Nova Scotia B3J 2A8. Mr. Huskilson is a citizen of Canada. Jane J. Bush has been a Director since 1990. Ms. Bush is President and co-owner of Coastal Ventures, a retailing company. Ms. Bush's business address is 11 Addison Rd, Columbia Falls, ME 04623. Ms. Bush is a citizen of the United States. Norman A. Ledwin has been a Director since 1996. Mr. Ledwin is President and Chief Executive Officer and a Director of Eastern Maine Healthcare, a health care organization made up of not-for-profit and for-profit entities (including Eastern Maine Medical Center, a not-for-profit regional acute care hospital facility). Mr. Ledwin's business address is 489 State St., Bangor, Maine 04401. Mr. Ledwin is a citizen of the United States. Elizabeth A. MacDonald has been a Director since Bangor Hydro's merger with Emera in October, 2001. Ms. MacDonald also serves as Vice President, Human Resources of Emera. Until November, 2001, Ms. MacDonald was Vice President - Human Resources of Nova Scotia Power Inc. Ms. MacDonald's business address is 1894 Barrington Street, Halifax, Nova Scotia B3J 2A8. Ms. MacDonald is a citizen of Canada. Ronald E. Smith has been a Director since Bangor Hydro's merger with Emera in October, 2001. Mr. Smith also serves as Chief Financial Officer of Emera. From September, 1999 to October, 2000, Mr. Smith was an independent consultant. From March, 1999 to September, 1999, Mr. Smith was Chief Financial Officer, Telecommunications, for Aliant Inc. Prior to March 1999 was Chief Financial Officer for Maritime Tel & Tel Co. Ltd. Mr. Smith's business address is 1894 Barrington Street, Halifax, Nova Scotia B3J 2A8. Mr. Smith is a citizen of Canada. Raymond R. Robinson has been Chief Operating Officer of Bangor Hydro since April, 2002. From 2001 until 2002, Mr. Robinson served as Vice President, Utility Integration for Emera. Prior to 2001, Mr. Robinson served as President and Chief Executive Officer of Yukon Energy Corporation. Mr. Robinson's business address is 33 State St., Bangor, Maine 04401. Mr. Robinson is a citizen of Canada. David R. Black has been Treasurer and Controller and Chief Financial Officer of Bangor Hydro since April, 2002. Prior to April, 2002, Mr. Black was Controller of Bangor Hydro. Mr. Black's business address is 33 State St., Bangor, Maine 04401. Mr. Black is a citizen of the United States. In 2002, the Board met on six occasions. The Board of Directors has one standing committee, its Audit Committee. The Audit Committee reviews with the independent public accountants the scope and results of their audit and other services to the Company, reviews the adequacy of the Company's internal accounting controls and reports to the Board at the Directors' meeting following each Audit Committee meeting or as necessary. The Audit Committee presently consists of Jane J. Bush, who is Chair of the Committee, Norman A. Ledwin and Ronald E. Smith. Mr. Smith is not independent under the listing standards of the New York Stock Exchange or under Section 301 of the Sarbanes-Oxley Act (15 USC Sec. 78f) since he is an employee of Emera Inc., a parent of the Company. With respect to Mr. Ledwin, the Board determined that Mr. Ledwin's affiliation with Eastern Maine Healthcare, which has an indirect business relationship with the Company, does not interfere with his exercise of independent judgment. The Audit Committee met five times during 2002. Audit Committee members are appointed by the Board and the Chair of the Committee is selected by Committee members. The Board does not have a compensation, investment or nominating committee. Item 11 Executive Compensation ------- ---------------------- The following table shows, for the fiscal years ending December 31, 2002, 2001, and 2000, the cash compensation paid to the principal executive officer and to the other executive officers whose total salary and bonus exceeded $100,000: SUMMARY COMPENSATION TABLE - ANNUAL COMPENSATION
Annual Compensation Long term compensation ---------------------- ------------------------------ Awards Payouts ---------------------- Other ------------ Year Salary Bonus Annual Restricted Securities All Other Compen- Stock Underlying LTIP Payouts Compensation Sation Awards Options/SARs ($) ($) (#) (b) (c) (d) (e) (f) (g) (h) (i) ----------------------------------------------------------------------------------------------------------------- Carroll R. Lee 2002 $98,654 none none $454,638 President & Chief Operating Officer 2001 190,131 $101,760 $3,400 none (Retired June 2002) 2000 180,289 $5,029 $3,400 none ------------------------------------------------------------------------------------------------------------------ Raymond Robinson 2002 $117,337 $51,271 $160 17,500* $1,498 Chief Operating Officer (Appointed June 2002) ------------------------------------------------------------------------------------------------------------------ David R. Black 2002 $92,680 $10,243 $2,391 Controller ------------------------------------------------------------------------------------------------------------------ Frederick S. Samp 2002 $49,362 none none $272,743 Vice President - Finance & Law 2001 138,624 $61,283 $3,400 none (Resigned May 2002) 2000 131,206 $3,664 $3,046 none ------------------------------------------------------------------------------------------------------------------ Paul A. LeBlanc 2002 $68,654 none none $249,920 Vice President - Human Resources 2001 128,066 $51,186 $3,400 none & Information Services 2000 121,085 $3,383 $2,800 none (Retired June 2002) ------------------------------------------------------------------------------------------------------------------
* - The Stock Options granted to Mr. Robinson are for shares of Emera. Stock Options Granted During the Most Recent Fiscal Year - 2002 --------------------------------------------------------------- The following table shows information regarding grants of stock options made to the Named Executive Officers during the fiscal year ended December 31, 2002. The stock options are granted pursuant to Emera's stock option plan and are options to purchase the stock of Emera, Inc. granted by Emera, the Company's ultimate parent. Mr. Robinson is eligible to participate in the Emera corporate stock option plan as the principal executive officer of a significant operating subsidiary. Emera's shares are traded on the Toronto Stock Exchange under the symbol "EMA". Emera shares trade in Canadian dollars. The exchange rate as of December 31, 2002 was US$1.5796 to CAN$1.00.
Market Value of % of Total Securities Securities Options Exercise or Underlying Under Granted to Base Options on the Options Employees Price Date of Grant Granted in $/Common $/Common Expiration Name (#) 2002 Share Share Date Raymond Robinson 17,500 100%* 16.50 16.50 Feb. 13, 2012
* - Mr. Robinson's 2002 award represents 3.18% of the options granted under the Emera corporate stock option plan during 2002. If Mr. Robinson's 2002 options appreciated at 5% per year through February 13, 2012, the potential realizable value of the options in nominal U.S. dollars would be $94,397.59. If Mr. Robinson's 2002 options appreciated at 10% per year through February 13, 2012, the potential realizable value of the options in nominal U.S. dollars would be $240,491.90. Each of these calculations is based upon a December 31, 2002 stock price of CAN$16.05 per share of Emera common stock and an exchange rate of US$1.5796 to CAN$1.00. Stock Option Exercises During the Most Recent Fiscal Year - 2002 ---------------------------------------------------------------- The following table shows information regarding exercise of stock options by the Named Executive Officers during the fiscal year ended December 31, 2002. The stock options are options to purchase the stock of Emera, Inc. granted by Emera, the Company's ultimate parent. Emera shares trade in Canadian dollars. The exchange rate as of December 31, 2002 was US$1.5796 to CAN$1.00.
Securities Acquired Aggregate Unexercised Value of Unexercised On Value Options at In-the-Money Options at Exercise Realized December 31, 2002 December 31, 2002 Name (#) ($) (#) ($) Exercisable Unexercisable Exercisable Unexercisable Raymond Robinson 0 0.00 2,500* 25,000* 2,374 7,122
* - Mr. Robinson was awarded 10,000 stock options during 2001 as an employee of Emera prior to the October, 2001 completion of the Bangor Hydro merger with Emera. None of the Named Executive Officers received compensation under a Long Term Incentive Plan during 2002. Pension Plan Tables ------------------- Mr. Robinson participates in the Emera corporate pension plan. The Pension Plan Table below sets out the estimated annual benefits payable to participants in the Emera plan upon retirement at age 60 for the various salary/years of service combinations as shown. Pension payments and the average annual compensation upon which the pension payments are determined are in Canadian dollars. The table is shown in Canadian currency and the exchange rate as of December 31, 2002 was US$1.5796 to CAN$1.00. Years of Credited Service at Retirement Age of 60 Remuneration 15 20 25 30 35 _____________________________________________________________________________ ($) ($) ($) ($) ($) ($) 100,000 30,000 40,000 50,000 60,000 70,000 200,000 60,000 80,000 100,000 120,000 140,000 300,000 90,000 120,000 150,000 180,000 210,000 400,000 120,000 160,000 200,000 240,000 280,000 500,000 150,000 200,000 250,000 300,000 350,000 600,000 180,000 240,000 300,000 360,000 420,000 700,000 210,000 280,000 350,000 420,000 490,000 800,000 240,000 320,000 400,000 480,000 560,000 Pension benefits paid under this pension plan are based on two percent of the average of the five highest years' earnings multiplied by each year of credited service. The pension is payable upon the earlier of: (i) age 60; or (ii) age 55, provided that age and years of service add to at least 85. A member may also retire on a reduced formula provided the member has attained age 55 but does not qualify for the Rule of 85. Members of the Emera pension plan contribute 5.4 percent of eligible earnings up to the year's maximum pensionable earnings ("YMPE") under the Canada Pension Plan, and seven percent of earnings over the YMPE, to the maximum amount permitted by Canada Customs and Revenue Agency regulations. Pension amounts in excess of such regulations do not require employee contributions. Spousal benefits are paid on the death of a member at the rate of 60 percent of regular pension benefits. The pension plan is indexed to the consumer price index to a maximum of six percent per annum. Upon reaching age 65, pension benefits under the pension plan are reduced to reflect commencement of payments under the Canada Pension Plan (CPP). The major portion of the above pension will be provided by the pension plan. Due to Canada Customs and Revenue Agency's limitations on the maximum pension benefit which may be paid under the pension plan, a portion of the pension earned after January 1, 1992 will be provided under the terms of a Supplementary Employee Retirement Plan which will be secured by a letter of credit. Mr. Robinson's benefit service, which includes his service at Emera prior to assuming his duties with Bangor Hydro, is two years (rounded to the nearest year). Mr. Black participates in a tax-qualified defined benefit pension plan that is also applicable to all Bangor Hydro employees. The following table sets forth estimated annual benefit amounts payable upon retirement to persons in specified compensation and benefit service classifications assuming their retirement at the normal retirement age (65) in 2003. Years of Benefit Service --------------------------------------------------------------------------- Average Annual Compensation 5 10 15 20 25 30 $ 50,000 $ 4,339 $ 8,678 $13,016 $17,355 $21,694 $26,033 75,000 6,839 13,678 20,516 27,355 34,194 41,033 100,000 9,339 18,678 28,016 37,355 46,694 56,033 150,000 14,339 28,678 43,016 57,355 71,694 86,033 200,000 14,672 29,344 44,016 58,688 73,361 88,033 Compensation covered by the plan is total basic compensation exclusive of overtime, bonuses, and other extra, contingent or supplemental compensation, and is cash compensation plus compensation deferred pursuant to the Company's Section 401(k) Plan. It is essentially the same as the amount shown as "Salary" in the Summary Compensation Table above. The annual retirement benefit is the greater of the following: a. The benefit accrued as of December 31, 1988 under a prior plan formula. b. 2.0% "average annual compensation" minus 0.4% of "covered compensation", times years of "benefit service". The benefit may not be larger than limits set forth in IRC Section 415. "Average annual compensation" is computed using the 36 consecutive months yielding the highest average, and "benefit service" generally means years of employment after age 21 and one year of service, up to a maximum of 30 years. "Covered compensation" is the average (without indexing) of the Social Security Taxable Wage Bases for the 35 calendar years ending with the year an individual attains Social Security Normal Retirement Age. It is assumed that the taxable wage base in effect at the beginning of the plan calculation year will remain the same for all future years. The benefit amount is payable in a life annuity form in full upon retirement at age 62 and in proportionately reduced amounts upon termination down to age 55. In 2002, as part of an amendment to the defined benefit pension plan applicable to all Bangor Hydro employees designed to implement an early retirement program, all qualified employees' years of benefit service and ages were enhanced by five years and three years respectively. This enhancement increased Mr. Black's age for purposes of the plan to age 57. Prior to the enhancement, Mr. Black had already reached the maximum 30 years of benefit service. Messrs. Lee, Samp, and LeBlanc participated in the tax qualified defined benefit pension plan applicable to all Bangor Hydro employees at the time of their respective retirement/resignation from the Company in 2002. In addition, Messrs. Lee, Samp, and LeBlanc are parties to Supplemental Benefit Agreements with the Company under which additional retirement benefits are to be paid. Said agreements define the total pension amount to be paid to the executive officer by the Company, with the supplemental amount defined as the difference between this total amount due and the amount due to the executive officer under the tax qualified pension plan applicable to all employees. The total amount of pension benefit, as defined under the Supplemental Benefit Agreements, is a function of the executive officer's age at retirement and his average total compensation over a three-year period. Under the Supplemental Benefit Agreements, no pension amount would be due until the executive officer reaches age 55. At age 55, the executive officer would be entitled to receive 50% of his or her average total compensation over a three-year period. The total pension amount to be paid upon retirement would increase proportionately until a retirement age of 62, at which point the executive officer would be entitled to receive upon retirement 75% of his or her average total compensation over a three-year period. Pursuant to modifications to his individual agreements prior to his resignation in 2002, Mr. Samp's age was enhanced from 51 to 53. At the time of their respective retirements in 2002, Mr. Lee had attained a natural age of 53 and Mr. LeBlanc had attained a natural age of 54. In addition, pursuant to the amendment to the tax qualified defined benefit pension plan applicable to all Bangor Hydro employees designed to implement an early retirement program, Messrs. Lee, Samp, and LeBlanc each had their benefit service enhanced by five years and age enhanced by three years, so that their respective ages and years of benefit service for purposes of this tax qualified plan at the times of their respective retirement/resignation in 2002, rounded to the nearest year, were as follows: Mr. Lee, age - 56, years of service - 30 (the maximum); Mr. Samp, age - 54, years of service - 21; and Mr. LeBlanc, age - 58, years of service - 30 (the maximum). The following table sets forth estimated annual benefit amounts payable upon retirement after age 55 to Messrs. Lee, Samp, and LeBlanc under the Supplemental Benefit Agreements: Age at Retirement ___________________________________________________________________________ Average Total Compensation 55 56 57 58 59 60 61 62+ $100,000 $50,000 $53,000 $57,000 $60,000 $64,000 $68,000 $72,000 $75,000 $150,000 75,000 79,500 85,500 90,000 96,000 102,000 108,000 112,500 $200,000 100,000 106,000 114,000 120,000 128,000 136,000 144,000 150,000 $250,000 125,000 132,500 142,500 150,000 160,000 170,000 180,000 187,500 $300,000 150,000 159,000 171,000 180,000 192,000 204,000 216,000 225,000 Compensation covered by the Supplemental Benefit Agreements is total compensation inclusive of bonuses, and other, contingent or supplemental compensation, and compensation deferred pursuant to the Company's Section 401(k) Plan. "Average Total Compensation" under the Supplemental Benefit Agreements is computed using the average of the total annual compensation actually paid by the Company to the Executive during the thirty-six consecutive calendar months in which the Executive's total compensation from the Company was the highest. The total annual pension amounts shown in the Pension Plan Table above are payable for the remainder of the executive officer's life after retirement. If the executive officer's spouse survives the executive officer, the spouse will receive an annual benefit for the remainder of her life equal to 50% of the annual benefit to the executive officer. The total annual pension amounts shown in the Pension Plan Table are not subject to any deduction for Social Security or other offset amounts. Employment Contracts -------------------- Mr. Robinson is party to an employment agreement with Emera that specifies his entitlement to salary, participation in compensation plans and other benefits, and an automobile allowance. In addition, Mr. Robinson is entitled to a severance payment of 18 months if he is removed from office without just cause. Mr. Black is party to an employment agreement with the Company that specifies his entitlement to salary and participation in benefit plans. Mr. Black is entitled to receive his salary and benefits for the remaining term of his employment contract if he is removed from office without cause. Mr. Black's employment agreement expires March 31, 2003. Messrs. Lee, Samp, and LeBlanc are parties to agreements under which in the event 1) of a change of control of the Company as defined in the agreements and 2) the covered party leaves the employment of the Company within one year after the change of control, he would be entitled to receive a payment equal to two years' salary based upon his average salary over the past three years. He would also be entitled to receive the Company's standard health, life insurance and disability benefits for a period of two years. Based upon the completion of the Company's merger with Emera Inc., Messrs. Lee, Samp, and LeBlanc were entitled to receive this benefit upon leaving the employment of the Company prior to October 10, 2002. The respective retirement/resignation of Messrs. Lee, Samp, and LeBlanc during 2002 constituted such termination of employment pursuant to the terms of these agreements. Compensation of Directors ------------------------- Directors who are not employees of the Company, Emera Inc. or other Emera affiliates are paid a fee of $500 per meeting for attendance at regular or special meetings of the Board, and $500 per meeting for attendance at committee meetings (unless the committee meeting is held the same day as another meeting for which a full meeting fee is paid, in which case the fee is $250). The directors are also paid an annual retainer of $6,000. Directors who are employees of the Company, Emera Inc. or other Emera affiliates receive no fee for their services as directors. Item 12 Security Ownership of Certain Beneficial Owners and Management ------- -------------------------------------------------------------- (a) Security Ownership of Certain Beneficial Owners As of February 1, 2003, the Company had outstanding 47,340 shares of Preferred Stock having general voting rights of one vote per share and 7,363,424 shares of Common Stock having general voting rights of one-twelfth of one vote per share. The following table sets forth as of February 1, 2003 information with respect to persons known to management to be the beneficial owners of more than 5% of any class of voting securities of the Company: Title of Class --------------- Common Stock Name and Address of Beneficial Owner ------------------------------------------------ BHE Holdings Inc. 566 Washington Road Rye, New Hampshire 03870 Amount and Nature of Beneficial Ownership ------------------------------------------------------ 7,363,424 shares Percent of Class -------------------- 100.0% (see (b) below) (b) Security Ownership of Management The following table sets forth as of February 1, 2003 information with respect to the beneficial ownership of equity securities by directors, nominees for the office of director and named executive officers: Title of Class Name of Beneficial Owner Beneficially Owned* --------------------------------------------------------------------------- Common Jane J. Bush 1 Common Christopher G. Huskilson 1 Common Norman A. Ledwin 1 Common Elizabeth A. MacDonald 1 Common David McD. Mann 1 Common Ronald E. Smith 1 Common David R. Black 0 Common Raymond R. Robinson 0 Common Directors & Executive Officers as a group (8) 6 Preferred Directors & Executive Officers as a group (8) 0 * The directors and executive officers of the Company as a group own a beneficial interest in less than 1% of the Company's Common and Preferred Stock. (c) Changes in Control Effective October 10, 2001, pursuant to an Agreement and Plan of Merger, the Company became a wholly owned subsidiary of Emera Inc. of Halifax, Nova Scotia through Emera's purchase of 100% of the Company's common equity. The Company is unaware of any arrangements, including any pledge by any person of securities of the Company or any of its parents, the operation of which may at a subsequent date result in a change in control of the registrant. Item 13 Certain Relationships and Related Transactions ------- ---------------------------------------------- Compensation Committee Interlocks - None. The Company does not have a compensation committee. Certain Relationships and Related Transactions - During 2002, the Company made payments to Eastern Maine Healthcare, its subsidiaries and affiliates, of $906,655. Mr. Ledwin, who serves on the Board of Directors and the Board's Compensation Committee, is President, Chief Executive Officer and a Director of Eastern Maine Healthcare. Eastern Maine Healthcare owns and operates Eastern Maine Medical Center, the second largest hospital in the State of Maine and the largest in the region served by the Company, as well as several other health care organizations in the region. The Company provides health care benefits to its employees through a self insured managed care plan. An independent plan administrator negotiates on behalf of the Company the rates for health care services paid to individual providers under the plan, including Eastern Maine Healthcare and its affiliates. PART IV ------- Item 14 Controls and Procedures ------- ----------------------- During the 90-day period prior to the filing date of this report, management, including the Company's Principal Executive Officer and Chief Financial Officer, evaluated the effectiveness of the design and operation of the Company's disclosure controls and procedures. Based upon, and as of the date of that evaluation, the Principal Executive Officer and Chief Financial Officer concluded that the disclosure controls and procedures were effective, in all material respects, to ensure that information required to be disclosed in the reports the Company files and submits under the Exchange Act is recorded, processed, summarized and reported as and when required. There have been no significant changes in the Company's internal controls or in other factors that could significantly affect internal controls subsequent to the date the Company carried out its evaluation. Item 15 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, 2002, 2001 and 2000 Consolidated Balance Sheets - December 31, 2002 and 2001 Consolidated Statements of Capitalization - December 31, 2002 and 2001 Consolidated Statements of Cash Flows for the Years Ended December 31, 2002, 2001 and 2000 Consolidated Statements of Common Stock Investment for the Years ended December 31, 2002, 2001 and 2000 Notes to Consolidated Financial Statements Report of Independent Accountants (b) Schedules Report of Independent Accountants Schedule II - Valuation and Qualifying Accounts and Reserves 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. (d) Reports on Form 8-K Current reports on Form 8-K for the Fourth Quarter of 2002 dated December 9, 2002 and December 31, 2002 were filed regarding the Company's announced redemption of its 4% and 4 1/4% series of preferred stock. 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/ Raymond R. Robinson ----------------------- By: Raymond R. Robinson Chief Operating Officer 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/ David McD. Mann ---------------- ------------------- Jane J. Bush David McD. Mann Director Chairman of the Board /s/ Christopher G. Huskilson /s/ Ronald E. Smith ---------------------------- ------------------- Christopher G. Huskilson Ronald E. Smith Vice Chairman, Director Director /s/ Norman A. Ledwin /s/ David R. Black -------------------- ------------------ Norman A. Ledwin David R. Black Director Treasurer, Controller, CFO -------------------------- Elizabeth A. MacDonald Director Each of the above signatures is affixed as of March 28, 2003. CERTIFICATIONS CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350 AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Annual Report of Bangor Hydro-Electric Company (the Company) on Form 10-K for the year ending December 31, 2002 as filed with the Securities and Exchange Commission on March 28, 2003, we, the undersigned, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that: (1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, and (2) The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company. /s/ David R. Black ------------------ David R. Black Chief Financial Officer March 28, 2003 /s/ Raymond R. Robinson ----------------------- Raymond R. Robinson Principal Executive Officer March 28, 2003 This certification is made solely for purpose of 18 U.S.C. Section 1350, subject to the knowledge standard contained therein, and not for any other purpose. I, David R. Black, certify that: 1. I have reviewed this annual report on Form 10-K of Bangor Hydro-Electric Company; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officer and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: March 28, 2003 /s/ David R. Black ------------------ David R. Black Chief Financial Officer I, Raymond R. Robinson, certify that: 1. I have reviewed this annual report on Form 10-K of Bangor Hydro-Electric Company; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officer and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: March 28, 2003 /s/ Raymond R. Robinson ----------------------- Raymond R. Robinson Principal Executive Officer SCHEDULE II Valuation and Qualifying Accounts and Reserves ------------------------------------------------------------
Additions ----------------------------- Balance at Charged to Charged to Balance at Beginning Costs and Other End Of Period Expenses Accounts Deductions of Period ------------------------------------------------------ ------------- 2002 Reserve for Doubtful Accounts $ 761,000 $1,801,158 $ 249,052 $1,726,158 (A) $1,085,052 ---------- ---------- ---------- ---------- ---------- 2001 Reserve for Doubtful Accounts $ 761,000 $1,884,630 $ - $1,884,630 (A) $ 761,000 ---------- ---------- ---------- ---------- ---------- 2000 Reserve for Doubtful Accounts $1,075,000 $1,275,016 $ - $1,589,016 (B) $ 761,000 ---------- ---------- ---------- ---------- ---------- NOTE: (A) Accounts written off, less recoveries. (B) Accounts written off, less recoveries. For 2000 includes reduction in reserve for doubtful accounts of $314,000.
EXHIBIT INDEX Exhibits Included Herewith -------------------------- 3. Articles of Incorporation and By-Laws 3(a) Articles of Amendment dated May 15, 2002, granting the Board of Directors authority to repurchase stock and to make equity distributions to shareholders 3(b) Articles of Amendment dated June 17, 2002, reducing the par value of the Company's common stock from $5.00 to $0.00. 10. Material Contracts 10(a) Note Purchase Agreement dated as of December 20, 2002 By and Among the Company and Thrivent Financial for Lutherans 10(b) Amendment No. 4 entered into as of March 29, 2002 to the 1998 Amended and Restated Revolving Credit Agreement and Term Loan Agreement By and Among the Company and Fleet National Bank as Agent 10(c) Amendment No. 5 entered into as of September 13, 2002 to the 1998 Amended and Restated Revolving Credit Agreement and Term Loan Agreement By and Among the Company and Fleet National Bank as Agent EXHIBIT INDEX 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 Articles of Amendment Form 10-K, 1998, Exhibit 3(a) Allowing Use of Similar Name 3.5 Articles of Merger dated October Form 10-K, 2001, Exhibit 3(a) 10, 2001 3.6 Articles of Amendment dated January Form 10-K, 2001, Exhibit 3(b) 8, 2002, reducing the minimum number of directors from 9 to 3 3.7 By-Laws of the Company, Amended Form 10-K, 2001, Exhibit 3(c) and Restated as of December 19, 2001 4. Instruments Defining the Rights of Security Holders --------------------------------------------------- 4.1 Mortgage and Deed of Form S-1, Reg. No. 2-54452, Trust dated as of Exhibit 4(b)(1) July 1, 1936, re First Mortgage Bonds 4.2 Supplemental Indenture Form S-1, Reg. No. 2-54452, dated as of December 1, Exhibit 4(b)(2) 1945, amending the Mortgage 4.3 Supplemental Indenture Form S-1, Reg. No. 2-54452 dated as of September 1, Exhibit 4(b)(4) 1969, re 8 1/4% Series Bonds, together with form of purchase agreement. (Supplemental indentures and purchase agreements with respect to prior issues are substantially identical in substantive content to the 8 1/4% Series documents). 4.4 Supplemental Indenture Form 10-K, 1975, Exhibit B dated as of November 1, 1975, re 10 1/2% Series Bonds, together with form of purchase agreement 4.5 Supplemental Indenture Form 8-K, 6/28/76, Exhibit A dated as of June 1, 1976, re 9 1/4% Series Bonds 4.6 Supplemental Indenture Form S-7, Reg. No. 2-61589, dated as of January 1, Exhibit 5(a)(7) 1978, re 8.6% Series Bonds, together with form of purchase agreement 4.7 Supplemental Indenture Form 10-Q, 3rd Quarter 1979, dated as of August 1, Exhibit A 1979, re 10.25% Series Bonds, together with form of purchase agreement Common Stock Purchase Plan 4.8 Supplemental Indenture Form 10-Q, 1st Quarter, 1981, dated as of April 1, Exhibit A 1981 re 15.25% Series Bonds, together with form of purchase agreement 4.9 Supplemental Indenture Form 10-Q, 2nd Quarter 1981, dated as of July 30, Exhibit (4) 1981 re 16.50% Series Bonds, together with form of purchase agreement 4.10 Bond Purchase Agreement, Form 10-K, 1983, Exhibit 4(a) including form of supplemental indenture, with respect to First Mortgage Bonds, 12.50% Series due 1998 4.11 Bond Purchase Agreement, Form 10-K, 1984, Exhibit 4(a) including form of supplemental indenture, with respect to First Mortgage Bonds, 17.35% Series due 1994 4.12 Bond Purchase Agreement Form 10-Q, First Quarter, dated as of March 1, 1989 1989, Exhibit 4.1 including form of supplemental indenture, with respect to First Mortgage Bonds, 10.25% Series due 2019 4.13 Bond Purchase Agreement Form 10-K, 1990, Exhibit 4(b) dated as of June 15, 1990 including form of supplemental indenture, with respect to First Mortgage Bonds, 10.25% Series due 2020 4.14 Loan Agreement by and Form 10-Q, 3rd Quarter 1995, Finance Authority of Exhibit 4.1 Maine and Bangor Hydro- Electric Company 4.15 Purchase Contract dated Form 10-Q, 3rd Quarter 1995, as of June 28, 1995 among Exhibit 4.3 the Finance Authority of Maine and Bangor Hydro- Electric Company and Prudential Securities Incorporated 4.16 General and Refunding Form 10-Q, 3rd Quarter 1995, Mortgage Indenture and Exhibit 4.4 Deed of Trust - Bangor Hydro-Electric Company to Chemical Bank, As Trustee, Dated as of June 1, 1995 4.17 Supplemental Indenture Form 10-Q, 3rd Quarter 1995, Dated as of June 15, 1995 Exhibit 4.5 to General and Refunding Mortgage Indenture and Deed of Trust dated as of June 1, 1995 (Bangor Hydro- Electric Company to Chemical Bank). 4.18 Supplemental Indenture as Form 10-Q, 3rd Quarter 1995, of June 29, 1995 to Mortgage and Deed of Trust dated as of July 1, 1936 (Bangor Hydro-Electric Company to Citibank, N.A. at Trustee). 4.19 Supplemental Indenture Form 10-K, 1995, Exhibit 4(a) Dated as of October 1, 1995 (Identified as Exhibit 10(a)) to General and Refunding Mortgage and Deed of Trust dated as of June 1, 1995 (Bangor Hydro-Electric Company to Chemical Bank). 4.20 TERM LOAN AGREEMENT Form 10-Q, First Quarter 1998, dated as of March 31, 1998 Exhibit 4(a) among BANGOR ENERGY RESALE, INC., BANKBOSTON, N.A. and the certain other lending institutions and BANKBOSTON, N.A., as Agent, including all Exhibits thereto 4.21 GUARANTY, dated as of March 31, Form 10-Q, First Quarter 1998, 1998, by BANGOR HYDRO Exhibit 4(b) -ELECTRIC COMPANY, in favor of (a) BANKBOSTON, N.A., as Agent, for itself and the other lending institutions which are or may become parties to a Term Loan Agreement, dated as of March 31, 1998 4.22 Warrant to Purchase Form 10-Q, Second Quarter 1998, Common Stock Granted to Exhibit 4(a) the Municipal Review Committee, Inc. on June 26, 1998 4.23 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 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 10.11 Third Amendment dated Form 10-K, 1983, Exhibit 10.2 as of November 1, 1982 to Preliminary Quebec Interconnection Support Agreement 10.12 Second Amendment dated Form 10-K, 1983, Exhibit 10.3 as of November 1, 1982 to Agreement With Respect to Use of Quebec Interconnection 10.13 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) 10.14 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) 10.15 Fourth Amendment Form 10-Q, 1st Quarter 1983, dated as of March 1, Exhibit 10.1 1983, to Preliminary Quebec Interconnection Support Agreement 10.16 Amendment dated as of Form 10-Q, 2nd Quarter 1983, September 1, 1981 Exhibit 10.3 to New England Power Pool Agreement 10.17 Amendment dated as of Form 10-Q, 2nd Quarter 1983, June 1, 1982 to New Exhibit 10.4 England Power Pool Agreement 10.18 Amendment dated as of Form 10-Q, 2nd Quarter 1983, June 15, 1983 to New Exhibit 10.5 England Power Pool Agreement 10.19 Amendment dated as of Form 10-Q, 3rd Quarter 1983, October 1, 1983 to Exhibit 10.1 New England Power Pool Agreement 10.20 Amendment No. 1 to the Form 10-K, 1983, Exhibit 10(b) Maine Yankee Power Contract 10.21 Amendment No. 2 to the Form 10-K, 1983, Exhibit 10(c) Maine Yankee Power Contract 10.22 Additional Power Con- Form 10-K, 1983, Exhibit 10(d) tract between Maine Yankee and its sponsors, including the Company 10.23 Preliminary Support Form 10-K, 1984, Exhibit 10(b) Agreement - Phase 2 of Hydro-Quebec Inter- connection 10.24 Amendment dated September 1, Form 10-K, 1985, Exhibit 10(b) 1985 to Agreement with respect to Use of Quebec Interconnection 10.25 Energy Contract dated Form 10-K, 1985, Exhibit 10(c) March 1983 between NEPOOL and Hydro-Quebec re: Hydro-Quebec Phase I interconnection project 10.26 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 10.27 Interconnection Agreement Form 10-K, 1985, Exhibit 10(e) dated March 1983 between NEPOOL and Hydro-Quebec re: Hydro-Quebec Phase I interconnection project 10.28 Amendment dated September 1 Form 10-K, 1985, Exhibit 10(f) 1985 to NEPOOL Agreement re: Hydro-Quebec Phase II interconnection project 10.29 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 10.30 Boston Edison AC Facilities Form 10-K, 1985, Exhibit 10(h) Support Agreement dated June 1, 1985 re: Hydro-Quebec Phase II interconnection project 10.31 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 10.32 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 10.33 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 10.34 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 10.35 Amendment No. 3 dated Form 10-K, 1985, Exhibit 10(m) October 1, 1984 to Maine Yankee Power Contract 10.36 Amendment No. 1 dated Form 10-K, 1985, Exhibit 10(n) August 1, 1985 to Maine Yankee Capital Funds Agreement 10.37 Amendments dated August 1, Form 10-K, 1985, Exhibit 10(o) 1985, August 15, 1985, and January 1, 1986 to NEPOOL Agreement 10.38 Third Amendment to Vermont Form 10-Q, 1st Quarter 1986, Transmission Line Support Exhibit 10.2 Agreement 10.39 First Amendment to Hydro- Form 10-Q, 1st Quarter 1986, Quebec Phase I Intercon- Exhibit 10.3 nection Agreement 10.40 First Amendment to Hydro- Form 10-Q, 2nd Quarter 1986, Quebec Phase II Exhibit 10.1 Massachusetts Trans- mission Facilities Support Agreement 10.41 First Amendment to Hydro- Form 10-Q, 2nd Quarter 1986, Quebec Phase II New Exhibit 10.2 Hampshire Transmission Facilities Support Agreement 10.42 First Amendment to Hydro- Form 10-Q, 2nd Quarter 1986, Quebec Phase II New England Exhibit 10.3 Power AC Facilities Support Agreement 10.43 First Amendment to Form 10-Q, 2nd Quarter 1986, Hydro-Quebec Phase II Exhibit 10.4 Boston Edison Company AC Facilities Support Agreement 10.44 Amendment Number 3 to Form 10-Q, 3rd Quarter 1986, Hydro-Quebec Phase l Exhibit 10.1 Terminal Facility Support Agreement 10.45 Amendment Number 3 to Form 10-Q, 3rd Quarter 1986, Hydro-Quebec Phase I Exhibit 10.2 Vermont Transmission Line Support Agreement 10.46 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. 10.47 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 10.48 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) 10.49 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 10.50 Third Amendment to Pre- Form 10-K, 1987, Exhibit 10(a) liminary Quebec Intercon- nection Support Agreement - Phase II 10.51 Fourth Amendment to Pre- Form 10-K, 1987, Exhibit 10(b) liminary Quebec Intercon- nection Support Agreement - Phase II 10.52 Fifth Amendment to Pre- Form 10-K, 1987, Exhibit 10(c) liminary Quebec Intercon- nection Support Agreement - Phase II 10.53 Sixth Amendment to Pre- Form 10-K, 1987, Exhibit 10(d) liminary Quebec Intercon- nection Support Agreement - Phase II 10.54 Seventh Amendment to Pre- Form 10-K, 1987, Exhibit 10(e) liminary Quebec Intercon- nection Support Agreement - Phase II 10.55 Amendment to New England Form 10-K, 1987, Exhibit 10(f) Power Pool Agreement dated March 1, 1988 10.56 Ninth Amendment to Form 10-K, 1988, Exhibit 10(b) Preliminary Quebec Interconnection Support Agreement - Phase II 10.57 Tenth Amendment to Form 10-K, 1988, Exhibit 10(c) Preliminary Quebec Interconnection Support Agreement - Phase II 10.58 Second Amendment to Form 10-K, 1988, Exhibit 10(d) Massachusetts Trans- mission Facilities Support Agreement 10.59 Third Amendment to Form 10-K, 1988, Exhibit 10(e) Massachusetts Trans- mission Facilities Support Agreement 10.60 Fourth Amendment to Form 10-K, 1988, Exhibit 10(f) Massachusetts Trans- mission Facilities Support Agreement 10.61 Fifth Amendment to Form 10-K, 1988, Exhibit 10(g) Massachusetts Trans- mission Facilities Support Agreement 10.62 Sixth Amendment to Form 10-K, 1988, Exhibit 10(h) Massachusetts Trans- mission Facilities Support Agreement 10.63 Second Amendment to Form 10-K, 1988, Exhibit 10(i) New Hampshire Trans- mission Facilities Support Agreement 10.64 Third Amendment to Form 10-K, 1988, Exhibit 10(j) New Hampshire Trans- mission Facilities Support Agreement 10.65 Fourth Amendment to Form 10-K, 1988, Exhibit 10(k) New Hampshire Trans- mission Facilities Support Agreement 10.66 Fifth Amendment to Form 10-K, 1988, Exhibit 10(l) New Hampshire Trans- mission Facilities Support Agreement 10.67 Sixth Amendment to Form 10-K, 1988, Exhibit 10(m) New Hampshire Trans- mission Facilities Support Agreement 10.68 Second Amendment to Form 10-K, 1988, Exhibit 10(n) Phase II AC New England Power Facilities Sup- port Agreement 10.69 Third Amendment to Form 10-K, 1988, Exhibit 10(o) Phase II AC New England Power Facilities Sup- port Agreement 10.70 Fourth Amendment to Form 10-K, 1988, Exhibit 10(p) Phase II AC New England Power Facilities Sup- port Agreement 10.71 Fifth Amendment to Form 10-K, 1988, Exhibit 10(q) Phase II AC New England Power Facilities Sup- port Agreement 10.72 Second Amendment to Form 10-K, 1988, Exhibit 10(r) Phase II Boston Edison AC Facilities Support Agreement 10.73 Third Amendment to Form 10-K, 1988, Exhibit 10(s) Phase II Boston Edison AC Facilities Support Agreement 10.74 Fourth Amendment to Form 10-K, 1988, Exhibit 10(t) Phase II Boston Edison AC Facilities Support Agreement 10.75 Fifth Amendment to Form 10-K, 1988, Exhibit 10(u) Phase II Boston Edison AC Facilities Support Agreement 10.76 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 10.77 401 (k) Plan for Non- Form 10-K, 1988, Exhibit 10(x) Union Employees 10.78 Agreement for the Form S-2, Reg. No. 33-39181, Purchase and Sale o Exhibit 10.82 Electricity dated as of June 21, 1984 between Penobscot Energy Recovery Company and the Company 10.79 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 10.80 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. 10.81 Purchase Agreement between Form 10-Q, 3rd Quarter 1995, Babcock-Ultrapower Exhibit 10.1 Jonseboro and Bangor Hydro- Electric Company 10.82 Purchase Agreement between Form 10-Q, 3rd Quarter 1995, Babcock-Ultrapower West Exhibit 10.2 Enfield and Bangor Hydro- Electric Company 10.83 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. 10.84 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. 10.85 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. 10.86 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. 10.87 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 10.88 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 10.89 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 10.90 Asset Purchase Agreement Form 8-K, September 25, 1998 dated as of September 25, Exhibit 2 1998 between Bangor Hydro- Electric Company and PP&L Global, Inc. (schedules and exhibits omitted). 10.91 Asset Purchase Implementation Form 10-K, 2000, Exhibit 10(a) Agreement, dated as of May 27, 1999, by and among Bangor Hydro- Electric Company, Penobscot Hydro Co., Inc. and Penobscot Hydro, LLC 10.92 33rd Amendment to the NEPOOL Form 10-K, 2000, Exhibit 10(b) Agreement dated December 1, 1996 10.93 Form of Agreement with Form 10-K, 2000, Exhibit 10(c) certain Executive Officers providing benefits upon a change of control 10.94 Form of Agreement with Form 10-K, 2000, Exhibit 10(d) certain Executive Officers providing supplemental death and retirement benefits 10.95 Agreement and Plan of Merger by Form 8-K, June 29, 2000, and Among Bangor Hydro-Electric Exhibit 2.1 Company and NS Power Holdings Incorporated dated as of June 29, 2000 10.96 Amendment No. 1 to Agreement Form 8-K, October 10, 2001, and Plan of Merger dated as of Exhibit 2.2 August 28, 2001 by an Among the Company and Emera, Inc. 10.97 Line Agreement dated as of June Form 10-K, 2001, Exhibit 10(a) 29, 2001 Agreement By and Among the Company and Fleet National Bank 10.98 Promissory Note dated as of June 29, Form 10-K, 2001, Exhibit 10(b) 2001 Agreement By and Among the Company and Fleet National Bank 10(a) 10.99 Promissory Note dated as of October Form 10-K, 2001, Exhibit 10(c) 10, 2001 from the Company to the Municipal Review Committee, Inc. 10.100 Amendment No. 3 entered into as of Form 10-K, 2001, Exhibit 10(b) December 31, 2001 to the 1998 Amended and Restated Revolving Credit Agreement and Term Loan Agreement By and Among the Company and Fleet National Bank as Agent 10.101 Amendment No. 2 dated as of December Form 10-K, 2001, Exhibit 10(b) 31, 2001 to Promissory Note By and Among the Company and Fleet National Bank