10-K 1 k10k2001.txt 10K 2001 BANGOR HYDRO-ELECTRIC COMPANY FORM 10-K SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the Fiscal year ended December 31, 2001 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 March 1, 2002 of the voting stock held by non-affiliates of the registrant was $3.32 million. 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 Executive Officers of the Registrant 9 PART II Item 5. Market for Registrant's Common Equity and Related Stockholder Matter 9 Item 6. Selected Financial Data 10 Item 7. Management's Discussion and Analysis of Results of Operations and Financial Condition 12 Item 8. Financial Statements and Supplementary Data 25 Consolidated Statements of Income 25 Consolidated Balance Sheets 26 Consolidated Statements of Capitalization 28 Consolidated Statements of Cash Flows 29 Consolidated Statements of Common Stock Investment 30 Notes to Consolidated to Financial Statements 31 Report of Independent Accountants 58 Item 7A Quantitative and Qualitative Disclosures About Market Risk 59 Item 9. Changes in and Disagreements with Independent Accountants on Accounting and Financial Disclosure 59 PART III Item 10. Directors and Executive Officers of the Registrant 59 Item 11. Executive Compensation 59 Item 12. Security Ownership of Certain Beneficial Owners and Management 60 Item 13. Certain Relationships and Related Transactions 60 PART IV Item 14. Exhibits, Financial Statement Schedule, and Reports on Form 8-K 61 Signatures 62 Schedule VIII - Reserve for Doubtful Accounts 63 Exhibits Delivered with this Report 64 Exhibits Incorporated Herein by Reference 65 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, 2001, see 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 - Current Rate Filings" and Item 8, "Notes to Consolidated Financial Statements - Note 11 - 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 - Contingencies and Disclosures About Market Risk" and Item 8, "Notes to Consolidated Financial Statements - Note 14 - Contingencies" for a discussion of Environmental Matters. (xiii) Number of employees As of December 31, 2001, the Company had 423 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 4,600 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 - Current Rate Filings." See also Item 7, "Management's Discussion and Analysis of Results of Operations and Financial Condition - Contingencies and Disclosures About Market Risk" and Item 8, "Notes to Consolidated Financial Statements - Note 14 - 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 At a meeting of shareholders held on December 19, 2001, the following actions were taken. Note that Common Shares are weighted at 1/12 of a vote per share in calculating the total vote. "Non-Votes" are the aggregation of unreturned ballots, abstentions, and ballots on which no vote was cast for the particular question. 1) Election of Directors: Nominees: Class I (for terms expiring in 2002): Robert S. Briggs Common For: 7,363,424 Common Against: 0 Preferred For: 36,541 Preferred Against: 440 Preferred Non-Vote: 10,359 Total For: 650,160 Total Against: 440 Total Non-Vote: 10,359 Norman A. Ledwin Common For: 7,363,424 Common Against: 0 Preferred For: 36,591 Preferred Against: 390 Preferred Non-Vote: 10,359 Total For: 650,210 Total Against: 390 Total Non-Vote: 10,359 Elizabeth A. MacDonald Common For: 7,363,424 Common Against: 0 Preferred For: 36,591 Preferred Against: 390 Preferred Non-Vote: 10,359 Total For: 650,210 Total Against: 390 Total Non-Vote: 10,359 Class II (for terms expiring in 2003): Jane J. Bush Common For: 7,363,424 Common Against: 0 Preferred For: 36,591 Preferred Against: 390 Preferred Non-Vote: 10,359 Total For: 650,210 Total Against: 390 Total Non-Vote: 10,359 David McD. Mann Common For: 7,363,424 Common Against: 0 Preferred For: 36,591 Preferred Against: 390 Preferred Non-Vote: 10,359 Total For: 650,210 Total Against: 390 Total Non-Vote: 10,359 Richard J. Smith Common For: 7,363,424 Common Against: 0 Preferred For: 36,591 Preferred Against: 390 Preferred Non-Vote: 10,359 Total For: 650,210 Total Against: 390 Total Non-Vote: 10,359 Class III (for terms expiring in 2004): Christopher G. Huskilson Common For: 7,363,424 Common Against: 0 Preferred For: 36,591 Preferred Against: 390 Preferred Non-Vote: 10,359 Total For: 650,210 Total Against: 390 Total Non-Vote: 10,359 Carroll R. Lee Common For: 7,363,424 Common Against: 0 Preferred For: 36,591 Preferred Against: 390 Preferred Non-Vote: 10,359 Total For: 650,210 Total Against: 390 Total Non-Vote: 10,359 Ronald E. Smith Common For: 7,363,424 Common Against: 0 Preferred For: 36,591 Preferred Against: 390 Preferred Non-Vote: 10,359 Total For: 650,210 Total Against: 390 Total Non-Vote: 10,359 2) RESOLVED that the Articles of Incorporation of the Company, as amended to date, be further amended to reduce the minimum number of Directors of the Company from 9 Directors to 3 Directors. Common For: 7,363,424 Common Against: 0 Preferred For: 35,250 Preferred Against: 1,614 Preferred Non-Vote: 10,516 Total For: 648,829 Total Against: 1,614 Total Non-Vote: 10,516 3) RESOLVED that the By-Laws of the Company, as amended to date, be further amended to eliminate the requirement that Directors be stockholders of the Company, thereby conforming the Company's By-Laws with the minimum requirement under the Maine Business Corporations Act. Common For: 7,363,424 Common Against: 0 Preferred For: 14,214 Preferred Against: 3,785 Preferred Non-Vote: 29,341 Total For: 627,833 Total Against: 3,785 Total Non-Vote: 29,341 4) RESOLVED that the By-Laws of the Company, as amended to date, be further amended to remove references to and special conditions related to the 8.76% series of non-voting preferred stock, such series having been redeemed in 1999. Common For: 7,363,424 Common Against: 0 Preferred For: 17,182 Preferred Against: 136 Preferred Non-Vote: 30,022 Total For: 627,833 Total Against: 136 Total Non-Vote: 30,022 5) RESOLVED to ratify and approve the actions of the Officers and the Board of Directors taken since the most recent Annual Meeting of Shareholders. Common For: 7,363,424 Common Against: 0 Preferred For: 34,674 Preferred Against: 297 Preferred Non-Vote: 12,369 Total For: 648,293 Total Against: 297 Total Non-Vote: 12,369 ------------------------------------- Executive officers of the Registrant Name Age Positions, offices and business experience - January 1997 to date Carroll R. Lee 52 President (from October 17, 2001); Senior Vice President and Chief Operating Officer prior thereto. Frederick S. Samp 51 Vice President - Finance & Law; Chief Financial Officer Paul A. LeBlanc 54 Vice President - Human Resources & Information Services The officers hold office until their respective successors are elected and qualified. 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 Statements of Cash Flows; and Consolidated Statement of Common Stock Investment. BANGOR HYDRO-ELECTRIC COMPANY Item 6 Selected Financial Data Six-Year Statistical Summary (Unaudited)

2001 2000 1999 1998 1997 1996 ~~1995~~ Megawatt Hours (MWH) Generated And Purchased Hydro Generation (Company) 65,392 90,719 205,265 275,379 262,377 321,532 ~~275,810~~ Nuclear Generation (Maine Yankee) - - - - - 348,719 ~~13,606~~ Oil (Company) 2,435 3,142 69,026 96,476 69,580 26,912 ~~50,706~~ Biomass/Refuse 150,401 152,060 137,384 156,051 159,990 163,279 ~~177,558~~ NEPOOL/Other Purchases 1,782,797 1,914,615 1,629,643 1,522,125 1,583,093 1,359,116 ~~1,540,530~~ ----------- ----------- ----------- ----------- ----------- ----------- Total Generated & Purchased 2,001,025 2,160,536 2,041,318 2,050,031 2,075,040 2,219,558 ~~2,058,210~~ Less Line Losses and Company Use 130,067 140,470 143,198 139,028 147,298 141,426 ~~140,128~~ ----------- ----------- ----------- ----------- ----------- ----------- Remainder-MWH sold 1,870,958 2,020,066 1,898,120 1,911,003 1,927,742 2,078,132 ~~1,918,082~~ =========== =========== =========== =========== =========== =========== Classification of Sales-MWH Residential 546,144 558,596 533,566 522,836 533,161 536,490 ~~513,076~~ Commercial 583,829 570,963 545,087 524,292 515,904 508,331 ~~507,243~~ Industrial 462,792 604,959 667,059 662,382 687,365 652,087 ~~690,863~~ Lighting 8,742 8,859 8,911 8,901 8,780 8,945 ~~9,547~~ Wholesale 2,676 2,799 2,716 2,704 3,841 4,486 ~~10,961~~ ----------- ----------- ----------- ----------- ----------- ----------- Total MWH Billed to Customers 1,604,183 1,746,176 1,757,339 1,721,115 1,749,051 1,710,339 ~~1,731,690~~ Unbilled Sales-Net Increase (Decrease) 4,343 2,629 11,772 1,040 33,011 2,998 ~~4,658~~ ----------- ----------- ----------- ----------- ----------- ----------- Total Delivered Sales (MWH) 1,608,526 1,748,805 1,769,111 1,722,155 1,782,062 1,713,337 ~~1,736,348~~ (Less) Interruptible Sales 7822,305 178,943 230,378 248,091 265,438 237,553 ~~295,818~~ ----------- ----------- ----------- ----------- ----------- ----------- Total Firm Delivered Sales (MWH) 1,~~669~~586,221 1,569,862 1,538,733 1,474,064 1,516,624 1,475,784 ~~1,440,530~~ Off-System Sales 262,432 271,261 129,009 188,848 145,680 364,795 ~~181,734~~ ----------- ----------- ----------- ----------- ----------- ----------- Total Energy Sales (MWH) 1,870,958 2,020,066 1,898,120 1,911,003 1,927,742 2,078,132 ~~1,918,082~~ =========== =========== =========== =========== =========== =========== Electric Operating Revenues and Expenses (000's) Electric Operating Revenues Residential $ 50,264 $ 57,746 $ 73,304 $ 71,396 $ 67,532 $ 66,805 $Commercial 6637,~~061~~795 ~~Commercial~~ 44,329 63,093 60,191 55,391 54,010 ~~54,702~~ Industrial 15,516 23,749 43,560 42,645 41,930 39,105 ~~40,257~~ Lighting 1,837 1,929 2,268 2,207 2,065 2,032 ~~2,051~~ Wholesale 19 63 220 235 310 314 ~~859~~ ----------- ------------ ------------ ------------ ------------ ------------ Total Revenue from Customers $ 105,431 $ 127,816 $ 182,445 $ 176,674 $ 167,228 $ 162,266 ~~$ 163,930~~ Standard Offer Service Revenue 5684,~~657~~589 -66,134 - - - - ~~Total Operating Revenue $ 184,473 $ 182,445 $ 176,674 $ 167,228 $ 162,266 $ 163,930~~ ----------- ------------ ------------ ------------ ------------ ------------ Total Operating Revenue $ 190,020 $ 193,950 $ 182,445 $ 176,674 $ 167,228 $ 162,266 Unbilled Sales-Net Increase (Decrease) 1815 (5,~~651~~014) 2,042 481 2,375 408 ~~210~~ ----------- ------------ ------------ ------------ ------------ ------------ Total Revenue $ ~~186~~190,~~124~~835 $ 188,936 $ 184,487 $ 177,155 $ 169,603 $ 162,674 ~~$ 164,140~~ (Less) Interruptible Revenue 1,687 4,973 10,049 11,064 11,215 9,537 ~~11,149~~ ----------- ------------ ------------ ------------ ------------ ------------ Total Firm Revenue $ ~~181~~189,~~151~~148 $ 183,963 $ 174,438 $ 166,091 $ 158,388 $ 153,137 ~~$ 152,991~~ Off-System Revenue 19,125 19,352 12,947 14,630 13,615 18,384 ~~14,098~~ ----------- ------------ ------------ ------------ ------------ ------------ Total Electric Operating Revenues $ ~~205~~209,~~476~~960 $ 208,288 $ 197,434 $ 191,785 $ 183,218 $ 181,058 ~~$ 178,238~~ =========== ============ ============ ============ ============ ============ Operating Expenses Fuel for Generation and Purchased Power $ 34,299 $ 44,144 $ 80,748 $ 82,027 $ 92,792 $ 78,477 ~~$ 98,684~~ Standard Offer Service Purchased Power 82,839 65,553 - - - - - Operating and Maintenance Expense 38,868 37,212 36,492 34,448 32,471 32,441 ~~35,711~~ Depreciation and Amortization 26,205 26,776 30,565 31,891 35,104 29,965 ~~20,544~~ Taxes 11,752 12,228 14,032 11,642 3,168 10,249 ~~6,306~~ ----------- ------------ ------------ ------------ ------------ ------------ Total Operating Expenses $ 193,963 $ 185,913 $ 161,837 $ 160,008 $ 163,535 $ 151,132 ~~$ 161,245~~ =========== ============ ============ ============ ============ ============ Summary of Operations (000's) Operating Revenue $ 217,580 $ 212,338 $ 197,994 $ 195,144 $ 187,324 $ 187,374 ~~$ 184,914~~ Operating Expenses 193,963 185,913 161,837 160,008 163,535 151,132 ~~161,245~~ Other Income (Loss) (including equity AFDC) (654) 613 2,806 1,292 1,292 1,466 ~~760~~ Interest Expense (net of borrowed AFDC) 14,273 15,936 20,683 24,963 25,467 26,425 ~~20,092~~ ----------- ------------ ------------ ------------ ------------ ------------ Net Income (Loss) $ 8,690 $ 11,102 $ 18,280 $ 11,465 $ (386) $ 11,283 ~~$ 4,337~~ Less Preferred Dividends 266 266 945 1,244 1,376 1,537 ~~1,702~~ ----------- ------------ ------------ ------------ ------------ ------------ Earnings (Loss) on Common Stock $ 8,424 $ 10,836 $ 17,335 $ 10,221 $ (1,762)$ ~~9,746~~ $ 2,635 =========== ============ ============ ============ ============ ============ Selected Financial Data Total Assets (000's) $ 532,220 $ 543,950 $ 605,688 $ 600,583 $ 556,629 $ 566,076 Electric Plant (000's) Total Electric Plant $ 327,247 $ 318,435 $ 372,782 $ 358,878 $ 341,526 $ 323,664 Depreciation Reserve 86,684 84,825 101,633 96,595 87,736 81,934 ----------- ------------ ------------ ------------ ------------ ------------ Net Electric Plant $ 240,563 $ 233,610 $ 271,149 $ 262,283 $ 253,790 $ 241,730 =========== ============ ============ ============ ============ ============ Capitalization (000's) Short-Term Debt $ - $ - $ 12,000 $ 34,000 $ 32,500 $ 35,000 Long-Term Debt 161,960 183,300 263,028 221,643 274,221 288,075 Redeemable Preferred Stock - - 7,604 9,137 10,670 12,070 Preferred Stock 4,734 4,734 4,734 4,734 4,734 4,734 Common Equity 137,420 132,722 118,864 106,558 108,321 103,192 ----------- ------------ ------------ ------------ ------------ ------------ Total $ 304,114 $ 320,756 $ 406,230 $ 376,072 $ 430,446 $ 443,071 =========== ============ ============ ============ ============ ============ Capital Structure Ratios (%) Short-Term Debt - % - % 3.0 % 9.1 % 7.5 % 7.9 % Long-Term Debt 53.2 % 57.1 % 64.7 % 58.9 % 63.7 % 65.0 % Preferred Stock 1.6 % 1.5 % 3.0 % 3.7 % 3.6 % 3.8 % Common Stock 45.2 % 41.4 % 29.3 % 28.3 % 25.2 % 23.3 % ----------- ------------ ------------ ------------ ------------ ------------ Total 100.0 % 100.0 % 100.0 % 100.0 % 100.0 % 100.0 % =========== ============ ============ ============ ============ ============ Miscellaneous Statistics Shares Outstanding (Average) 7,363,424 7,363,424 7,363,424 7,363,424 7,336,174 7,264,360 Shares Outstanding (Year End) 7,363,424 7,363,424 7,363,424 7,363,424 7,363,424 7,301,557 Number of Common Stockholders (Year End) 6,222 5,678 6,328 6,868 7,734 8,250 Basic Earnings (Loss) Per Common Share $ 1.47 $ 2.35 $ 1.39 $ (0.24) $ 1.33 $ 0.36 Diluted Earnings (Loss) Per Common Share $ 1.30 $ 2.08 $ 1.33 $ (0.24) $ 1.33 $ 0.36 Dividends Declared Per Common Share $ 0.80 $ 0.45 $ - $ - $ 0.72 $ 0.87 Book Value Per Common Share $ 18.66 $ 18.02 $ 16.14 $ 14.47 $ 14.71 $ 14.13 Return on Common Equity 7.98 % 13.81 % 9.11 % (1.64)% 9.09 % 2.51 % Ratio of AFDC to Common Stock Earnings 3 % (4)% 11 % (48)% 12 % 48 % Ratio of Earnings to Fixed Charges 2.11 % 2.25 % 1.59 % 0.86 % 1.50 % 1.14 % Payout Ratio 54 % 26 % - % - % 54 % 242 % Percentage of Construction Expenditures Funded Internally 100 % 100 % 100 % 100 % 100 % 86 % =========== =========== =========== =========== =========== =========== Residential Customer Data Average Number of Customers 92,656 91,726 90,888 90,433 89,769 86,194 Kilowatt-Hours per Customer 6,029 5,817 5,753 5,896 5,976 5,953 Revenue per Customer $ 623.23 $ 799.16 $ 785.54 $ 746~~.76~~ ~~$ 744.19 $ 766.42 Revenue per Kilowatt-Hour in Cents 10.34 13.74 13.65 12.67 12.45 12.88~~ =========== ============ =========== =========== =========== =========== Miscellaneous System Data Net System Capability at Time of Peak (MW) Firm* 98.98 273.72 381.54 344.44 373.04 330.01 System Peak Demand (MW) 304.71 293.08 281.63 277.06 274.32 267.98 Reserve Margin at Time of Peak** (67.5)% (6.6)% 35.5 % 24.3 % 36.0 % 23.2 % System Load Factor 70.8 % 74.5 % 75.4 % 79.5 % 77.0 % 79.9 % =========== ============ =========== =========== =========== =========== * The net system capability was reduced in 2000 and 1999 as a result of the generation asset sale. ** While the reserve margin at time of peak in 2000 and 1999 was negative, the system requirements were met through spot market purchases.

BANGOR HYDRO-ELECTRIC COMPANY Item 6 Selected Financial Data Six-Year Statistical Summary (Unaudited)

2001 2000 1999 1998 ~~Electric~~1997 ~~Operating~~1996 ~~Revenues~~Selected ~~Electric~~Financial ~~operating~~Data ~~revenue~~Total Assets (~~Note~~000's) 1$ 678,245 $ 532,220 $ 543,950 $ 605,688 $ 600,583 $ 556,629 Electric Plant (000's) Total Electric Plant $ ~~146~~341,~~204~~143 $ 327,~~013~~247 $ ~~197~~318,~~994~~435 $ 372,~~796~~782 $ ~~195~~358,~~144~~878 $ 341,~~007~~526 ~~Standard~~Depreciation ~~offer~~Reserve ~~service~~93,985 ~~(Note~~86,684 ~~10)~~84,825 66101,~~133~~633 96,~~532~~595 -87,736 - ----------~~---~~ -----------~~----~~ -----------~~----~~ ~~$ 212,337,545 $ 197,994,796 $ 195,144,007~~ ------------- -----------~~----~~ -----------~~----~~ ~~Operating~~Net ~~Expenses:~~Electric ~~Fuel~~Plant ~~for~~$ ~~generation~~247,158 ~~and~~$ ~~purchased~~240,563 ~~power~~$ ~~(Notes~~233,610 ~~1 and 3)~~ $ 44271,~~144,334~~149 $ 80262,~~748,385~~283 $ 82253,~~026,860~~790 ~~Standard~~=========== ~~offer~~=========== ~~service~~=========== ~~purchased~~=========== ~~power~~=========== ~~(Note~~=========== 10Capitalization (000's) ~~65,552,980~~ Short-Term -Debt ~~Other~~$ ~~operation~~8,000 ~~and~~$ ~~maintenance~~- ~~(Notes~~$ 1- ~~and~~$ ~~5) 37~~12,~~211,862~~000 ~~36,491,666~~$ 34,~~448,324~~000 ~~Depreciation~~$ ~~and~~32,500 ~~amortization~~Long-Term ~~(Note~~Debt 1)131,968 9161,~~158~~960 183,~~885~~300 8263,~~063~~028 221,~~939~~643 9274,~~749,229~~221 ~~Amortization~~Redeemable ofPreferred ~~Seabrook~~Stock ~~nuclear~~- ~~unit~~- ~~(Note~~- 7~~) 1~~,~~699,050~~604 19,~~699,050~~137 110,~~699,050~~670 ~~Amortization~~Preferred ofStock ~~contract~~4,734 ~~buyouts~~4,734 ~~and restructuring (Note 6) 22~~4,~~311,448~~734 204,~~801,816~~734 204,~~442,441~~734 ~~Amortization of deferred asset sale gain (Note 10) (6~~4,~~393,038)~~734 -Common -Equity ~~Taxes - Local property and other 4~~205,~~795,698~~557 5137,~~059,140~~420 5132,~~549,049~~722 ~~Income (Note 2) 7~~118,~~432,261~~864 8106,~~973,166~~558 6108,~~093,286~~321 ------------- -----------~~----~~ -----------~~----~~ ~~$ 185,913,480 $ 161,837,162 $ 160,008,239~~ ------------- -----------~~----~~ -----------~~----~~ ~~Operating~~Total ~~Income~~$ 350,259 $ 26304,~~424~~114 $ 320,~~065~~756 $ 36406,~~157~~230 $ 376,~~634~~072 $ 35430,~~135,768~~446 ~~Other~~=========== ~~Income~~=========== ~~And~~=========== =========== =========== =========== Capital Structure Ratios (~~Deductions~~%): ~~Allowance~~Short-Term ~~for~~Debt ~~equity~~2.3 ~~funds~~% ~~used~~- ~~during~~% ~~construction~~- ~~(Note~~% 3.0 % 9.1) $% ~~158,698~~7.5 $% ~~(326,026)~~Long-Term $Debt ~~430,028~~37.7 ~~Other,~~% ~~net~~53.2 of% ~~applicable~~57.1 ~~income~~% ~~taxes~~64.7 ~~(Notes~~% 58.9 % 63.7 % Preferred Stock 1,.3 2,% 1.6 ~~and~~% ~~11)~~1.5 ~~454,715~~% 3~~,132,097~~.0 ~~862,723~~% 3.7 % 3.6 % Common Stock 58.7 % 45.2 % 41.4 % 29.3 % 28.3 % 25.2 % ------------- -----------~~----~~ -----------~~----~~ ~~Income Before Interest Expense $ 27,037,478 $ 38,963,705 $ 36,428,519~~ ------------- -----------~~----~~ -----------~~----~~ ~~Interest~~Total ~~Expense:~~100.0 ~~Long-term~~% ~~debt~~100.0 ~~(Notes~~% 4100.0 ~~and~~% 13100.0 % 100.0 % 100.0 % =========== =========== =========== =========== =========== =========== Miscellaneous Statistics Shares Outstanding (Average) $7,363,424 157,~~211~~363,~~905~~424 $7,363,424 197,~~004~~363,~~624~~424 $7,363,424 227,~~906~~336,~~021~~174 ~~Other~~Shares Outstanding (~~Note~~Year 4End) ~~893~~7,~~455~~363,424 17,~~393~~363,~~547~~424 27,~~750~~363,~~863~~424 ~~Allowance~~7,363,424 ~~for~~7,363,424 ~~borrowed~~7,363,424 ~~funds~~Number ~~used~~of ~~during~~Common ~~construction~~Stockholders (~~Note~~Year End) 1 6,222 5,678 6,328 6,868 7,734 Basic Earnings (Loss) Per Common Share $ 1.14 $ 1.47 $ 2.35 $ 1.39 $ (~~169,929~~0.24) ~~284,933~~$ 1.33 Diluted Earnings (~~693,682~~Loss) ~~-------------~~Per ~~---------------~~Common ~~---------------~~Share $ ~~15,935,431~~1.08 $ ~~20,683,104~~1.30 $ 2.08 $ 1.33 $ (0.24~~,963,202~~) ~~-------------~~$ 1.33 Dividends Declared Per Common Share $ 0.60 $ 0.80 $ 0.45 $ -~~--------------~~ $ -~~--------------~~ ~~Net~~$ ~~Income~~0.72 Book Value Per Common Share $ ~~11,102,047~~17.26 $ 18~~,280,601~~.66 $ 18.02 $ 16.14 $ 14.47 $ 14.71 Return on Common Equity 6.30 % 7.98 % 13.81 % 9.11~~,465,317~~ ~~Dividends~~% On(1.64)% ~~Preferred~~9.09 % Ratio of AFDC to Common Stock ~~(Note~~Earnings 14 % 3 % (4)% ~~265,570~~11 ~~945,396~~% ~~1,244,488~~(48)% ~~-------------~~12 ~~---------------~~% ~~---------------~~Ratio of Earnings ~~Applicable~~to ToFixed ~~Common~~Charges ~~Stock~~1.89 $% ~~10,836,477~~2.11 $% ~~17,335,205~~2.25 $% ~~10,220,829~~1.59 ~~-------------~~% 0.86 % 1.50 % Payout Ratio 53 % 54 % 26 % -~~--------------~~ % -~~--------------~~ ~~Weighted~~% 54 % Percentage of Construction Expenditures Funded Internally 100 % 100 % 100 % 100 % 100 % 100 % =========== =========== =========== =========== =========== =========== Residential Customer Data Average Number Ofof ~~Shares~~Customers ~~Outstanding~~93,398 ~~(Note~~92,656 3)91,726 790,~~363~~888 90,~~424~~433 789,~~363~~769 Kilowatt-Hours per Customer 5,~~424~~847 76,~~363~~029 5,~~424~~817 ~~-------------~~5,753 ~~---------------~~5,896 ~~---------------~~5,976 ~~Earnings~~Revenue ~~Per~~per ~~Common~~Customer ~~Share~~$ ~~(Note~~538.17 ~~3):~~$ ~~Basic~~623.23 $ 1799.4716 $ 2785.3554 $ 1746.3976 ~~Diluted~~$ 1744.3019 2Revenue per Kilowatt-Hour in Cents 9.20 10.34 13.74 13.65 12.67 12.45 =========== =========== =========== =========== =========== =========== Miscellaneous System Data Net System Capability at Time of Peak (MW) Firm* 182.23 98.98 273.72 381.54 344.44 373.04 System Peak Demand (MW) 290.37 304.71 293.08 1281.3363 ~~-------------~~277.06 ~~---------------~~274.32 ~~---------------~~Reserve ~~Dividends~~Margin ~~Declared~~at ~~Per~~Time ~~Common~~of ~~Share~~Peak** $(37.2)% (67.805)% $(6.6)% 35.455 $% -24.3 ~~-------------~~% ~~---------------~~36.0 ~~---------------~~% System Load Factor 68.4 % 70.8 % 74.5 % 75.4 % 79.5 % 77.0 % =========== =========== =========== =========== =========== =========== * The ~~accompanying~~net ~~notes~~system ~~are~~capability anwas ~~integral~~reduced ~~part~~subsequent to the generation asset sale, which accord in May 1999.. ** While the reserve margin at time of ~~these~~peak ~~consolidated~~in ~~financial~~2001, ~~statements~~2000 and 1999 was negative, the system requirements were met through spot market purchases.

ITEM 7 MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION RECENT EVENTS AFFECTING THE COMPANY MERGER WITH EMERA - In early October 2001, final regulatory approvals for the merger between the Company and Emera, Inc. (Emera) were received. On October 10, 2001, Emera completed the acquisition of all of the outstanding common stock of the Company for US$26.806 per share in cash. The purchase increases Emera's customer base by 25% and broadens the Company's presence in the expanding northeast energy market. 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 at December 31, 2001, is recorded as goodwill on the consolidated balance sheets. Emera is a diversified energy and services company, with about 440,000 customers and (Cdn)$2.9 billion in assets. It owns 100% of Nova Scotia Power, Inc., the primary electricity supplier in the province of Nova Scotia. Emera's energy product line also includes bunker oil, diesel fuel and light fuel oil, and the company has a 12.5% interest in the Maritimes & Northeast Pipeline, which delivers Sable Island natural gas to markets in Maritime Canada, and the northeastern United States. CURRENT RATE FILINGS - On October 12, 2001, the Company filed a proposal with the MPUC for an alternative rate plan (ARP) that would govern its rates for distribution service over a four year period. Such a filing was required by the Maine Public Utilities Commission (MPUC) as a condition of its approval of the Company's acquisition by Emera. In addition to distribution service rates, the Company's ARP proposal included proposed incentives to improve the efficiency and the service quality of power delivery services to Bangor Hydro's customers. The Company's proposal included an initial increase in distribution rates of approximately $3.4 million, with additional annual adjustments during the term of the ARP at a rate below that of inflation. However, as a result of a scheduled reduction in standard offer service, the combined impact of rate changes for most customers would be a reduction of approximately 10% (or about $8 per month for a typical residential customer) during 2002. There is no legal deadline for the MPUC to complete such a proceeding. On October 18, 2001, the Company filed a notice of its intent to file a request for a general increase in distribution rates of approximately $6.4 million. Under Maine law, utilities are required to provide a minimum of sixty days notice of their intent to file such a request. This filing was made as an alternative to the Company's ARP filing, although it does not preclude simultaneous or subsequent implementation of an ARP. Once filed, the MPUC must process such a request within nine months. In November 2001, the MPUC Hearing Examiner administering the ARP proceeding suspended that proceeding pending the Company's filing of a request for a general increase in distribution rates. On January 11, 2002, the MPUC requested comments on a Draft Order that would initiate a management investigation of the Company, as permitted by Maine law, as part of its investigation of the Company's anticipated request for a general increase in distribution rates. On January 17, 2002, in response to this Draft Order, the Company offered to defer filing its request for a general increase in distribution rates and asked the MPUC to defer initiating the management investigation to permit the Company and interested parties a three month period to pursue a settlement of the ARP proceeding with the expectation that such a settlement would also terminate the proposed request for a general increase in rates and the management investigation. At a deliberative session held on January 22, 2002, the MPUC deferred issuing an order initiating a management investigation for 90 days to allow the parties to pursue a settlement of these related rate matters. On February 14, 2002, the Company presented to the MPUC a proposed resolution of the ongoing ARP proceeding that calls for a multi-year freeze in the distribution portion of the Company's electric rates. In order to comply with such a rate freeze without an adverse impact on the Company's earnings, the Company believes that it will be necessary to implement significant reductions in its operating costs as compared to current levels. The Company believes that such operating cost reductions can be implemented without adversely affecting service quality. At this time, however, management cannot predict the outcome of the ARP proceeding with the MPUC, and the Company has not identified the timing or the nature of the cost reductions to be implemented. RESULTS OF OPERATIONS EARNINGS - Basic earnings per common share were $1.14, $1.47, and $2.35, for the years ended 2001, 2000 and 1999, respectively. The earned return on average common equity was 6.3% in 2001, 8% in 2000 and 13.8% in 1999. The reduction in earnings in 2001 as compared to 2000 was due to several factors. In 2001, the Company incurred approximately $3.9 million ($.33 reduction in earnings per common share) of costs associated with the merger with Emera, as compared to $3 million in 2000 ($.24 reduction in earnings per common share). Also, 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). 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). The relatively high level of earnings in 1999 as compared to 2000 was in part attributable to a number of one-time benefits in 1999 amounting to approximately $.52 per common share. The largest of these was a $1.5 million income tax benefit recorded in the fourth quarter of 1999 (approximately $.20 per common share) from the flow through of unamortized deferred investment tax credits and excess deferred income taxes associated with the 1999 sale of the Company's generation assets. Other one-time items for 1999 include a gain on the sale of a subsidiary as part of the mandatory divestiture of generation assets (approximately $.04 per common share after taxes) recorded in the third quarter of 1999. In the second quarter the Company recorded a one-time benefit of $896,000 ($.07 per common share after taxes) because of the settlement of a dispute related to the NEPOOL transmission rates, and in the first quarter the Company recorded a one-time benefit of $802,000 ($.07 per common share after taxes) due to the settlement by the NEPOOL of a contract dispute with Hydro-Quebec (HQ). Finally, in 1999 the Company participated in a major construction project for a third party unrelated to its core utility business. This activity, now completed, allowed the Company to charge some of its fixed costs directly to that third party resulting in a reduction to operation and maintenance expense and producing a benefit to 1999 earnings of $.14 per common share after taxes. Several other major changes account for the difference between 2000 and 1999 earnings. The largest change is attributable to new rates implemented by order of the MPUC effective March 1, 2000 that reflect a lower authorized return on equity of 11% in Maine's restructured electric industry. Also affecting earnings in 2000 were costs billed to the Company associated with transmission constraints in New England ($.15 per common share after taxes), as well as the recognition of costs related to the merger ($.24 per common share after taxes) with Emera, and a write-off associated with power costs to replace generation from the Maine Yankee nuclear power plant ($.16 per common share after taxes). Somewhat offsetting these charges to earnings was a $1.2 million ($.10 per common share after taxes) gain on the sale of the Company's wholly-owned subsidiary, Penobscot Natural Gas (Penobscot Gas). REVENUES - With the previously discussed implementation of competition in the electric utility industry starting March 1, 2000, and excluding the standard-offer service, the Company is no longer selling electricity to customers. The Company's T&D and stranded cost charges to customers, though, continue to be based on customers' electricity usage measured in kilowatt-hours (kWh). Consequently, discussion related to electric operating revenues will continue to have a kWh sales, or hereafter referred to as "energy sales" component. 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 $5.2 million, or 2.5%, 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 has 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. Electric operating revenue increased by $14.3 million in 2000 as compared to 1999 due to several factors. Other revenues (not attributable to kWh sales) were approximately $12.7 million greater in 2000 as compared to 1999 due principally to four factors. First, as a result of the previously discussed deferral mechanism for the standard- offer service revenues and costs, the Company recorded additional revenue of $3 million in 2000 to recognize the standard-offer service expenses in excess of revenues. Off-system sales, which are sales related to power pool and interconnection agreements and resales of purchased power, were approximately $6.4 million higher in 2000 as a result of the Company's requirement to resell the capacity and energy from its six purchased power contracts pursuant to Chapter 307 of Maine's 1997 law restructuring the State's electric industry (See the Note 7 to the Consolidated Financial Statements for a more complete discussion). Also, primarily as a result of electric generators in the Company's service territory wheeling power over the Company's transmission lines and out of its service territory, the Company recorded approximately $1.8 million in higher transmission wheeling revenues in 2000 as compared to 1999. Finally, in 2000 the Company recorded approximately $1.4 million of revenues associated with the previously discussed deferral mechanism for special rate contracts. Total electric operating revenues attributable to energy sales were $1.6 million greater in 2000 than in 1999. Total energy sales were 1.2% or 20.3 million KWH's lower in 2000 as compared to 1999, largely attributable to reduced sales to the Company's largest special rate contract customers (64.5 million KWH reduction in energy sales and $6.9 million reduction in electric operating revenues). These reduced special contract customer sales and revenues were attributable to the previously discussed shutdown of Holtrachem on September 15, 2000, and sales to another large industrial customer in 2000. Sales to this customer, which contribute a relatively low profit margin to the Company, can vary greatly from year to year as they own self-generation facilities. Reduced revenues for this group of customers were also affected by certain of these large customers choosing a competitive electricity supplier starting March 1, 2000 (197.5 million KWH's or 62% of total large special contract energy sales for the period from March through December 2000) and not contributing to the Company's standard- offer service revenues. For those who have chosen standard-offer service, corresponding revenues have been impacted by the various associated rate changes in 2000 discussed below. Exclusive of the Company's largest special contract customers, total T&D and stranded cost revenues related to energy sales were $8.5 million higher in 2000 as compared to 1999 principally as a result of a 5.3% increase in energy sales and effect of various rate changes discussed below. As with the large special contract customers, certain non-special contract commercial customers have been able to purchase electricity from competitive energy providers starting in March 2000 (37 million KWH's or 3% of total non-special contract energy sales for the period from March through December 2000), and consequently, the Company's electric operating revenues have been reduced. The increased energy sales in 2000 were impacted by the previously discussed strength in the local economy and colder weather in 2000 as compared to 1999. As a result of the February 2000 rate order from the MPUC, the Company's overall rates, including the impact of the initial standard- offer prices, were reduced by approximately 2.9% starting March 1, 2000. The Company has also implemented various rate changes for its standard-offer service as approved by the MPUC. The result of these standard-offer rate changes for the period from March 1 through October 1, 2000 was an increase in the standard-offer prices of 36% for residential and small commercial customers and 25% for large industrial customers as compared to the prices when initially set by the MPUC on March 1, 2000. EXPENSES - 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 establishment of the previously discussed reserve in connection with potential regulatory loss exposure. 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. Fuel for generation and purchased power expense increased $28.9 million in 2000 as compared to 1999. Total power purchases in 2000 were fairly consistent with those in 1999 due to the Company continuing to fulfill its long-term power purchase contract obligations subsequent to the implementation of the electric industry restructuring on March 1, 2000 and also procuring power to serve the standard-offer load. In 2000, though, the Company purchased significantly more power on the spot power market as compared to 1999 as a result of having fewer power contracts in place than in 1999. These factors resulted in higher fuel and purchased power costs in 2000. With more of the Company's power purchases being made in the spot power market in 2000, the price of the power was negatively affected by very high oil prices in 2000 and new market rules implemented by NEPOOL in May 1999, which set prices for replacement purchases from the pool at market levels related to supply and demand as opposed to actual marginal fuel costs. Also impacting power cost increases in each year were very unusual circumstances in NEPOOL for one day in each of the respective years, with record- breaking loads occurring while many generators were still out of service for maintenance. The result was on-peak power prices that, for the June 1999 event were two to three times as great as would normally occur during June. However, the May 2000 event resulted in prices that were approximately five times as high as the prices paid on the comparable day in June 1999. The Company incurred approximately $2 million more in purchased power costs on the day in 2000 as compared to the day in 1999. In connection with the previously discussed standard- offer service deferral mechanism, the high power costs for the day in May 2000 have been deferred and are recoverable from customers in the future. Increased fuel and purchased power expense was also impacted by higher ISO New England (ISO) expenses in 2000 as compared to 1999, due to the implementation of NEPOOL new market rules in May 1999 and $1.9 million in previously discussed ISO costs in 2000 associated with transmission constraints. Also increasing fuel and purchased power expense in 2000 was $2 million charged to expense in connection with the previously discussed write-off associated with power costs to replace generation from the Maine Yankee nuclear power plant. The increased expense in 2000 as compared to 1999 was also due to the previously discussed settlement of the dispute with HQ which resulted in a $747,000 reduction in expense in the first quarter of 1999, and the settlement of a dispute related to NEPOOL, which resulted in a $896,000 reduction in expense in the second quarter of 1999. Other operation and maintenance (O&M) expense increased by approximately $1.7 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. Other O&M expense increased by approximately $720,000 in 2000 as compared to 1999. Increasing other O&M expense in 2000 was a $1.7 million increase in O&M payroll due principally to less labor in 2000 being charged to capital projects as compared to 1999 as a result of less construction activity in 2000, and the impact of a 4% wage rate increase for bargaining unit employees on January 1, 2000 and various wage rate increases for non-bargaining unit employees. Further increasing other O&M in 2000 was the amortization expense of approximately $680,000 associated with incremental costs deferred in connection with the implementation of the electric utility industry restructuring (see Note 11 to the Consolidated Financial Statements). Recovery of the cost deferrals was allowed in rates in the Company's February 2000 rate order from the MPUC over a three year period starting March 1, 2000. Decreasing other O&M expense in 1999 was a $706,000 increase in overhead expenses allocated to capital projects. This increased overhead allocation in 1999 was principally a result of major construction activities being performed by the Company in connection with the Maine Independence Station, a new 520 megawatt gas fired generation facility in Veazie, Maine, which has subsequently become operational and is connected to the regional transmission power grid. The Company was reimbursed by the owner of the facility for the construction costs incurred, including overhead expense. Offsetting these increases to some extent in 2000 was a $1.3 million decrease in incremental expenditures related to electric utility industry restructuring activities, costs associated with assessment and testing of systems for year 2000 compliance, and an upgrade to the Company's customer information system which was completed in May 1999. Also reducing other O&M expense in 2000 was a decrease in pension and other postretirement benefit expense of $1 million, resulting principally from plan amendments in 1999 and changes in actuarial assumptions. Depreciation and amortization expense increased by approximately $866,000 in 2001 relative to 2000 and by approximately $1.1 million in 2000 as compared to 1999 due principally to two factors, the first being additions to the Company's electric plant in service in both 2001 and 2000. Also increasing depreciation expense in 2001 was the effect of a depreciation study conducted in December 1996, which determined that the Company's reserve for depreciation was overaccumulated by approximately $3.6 million. In connection with the MPUC's rate order in February 1998, the Company was allowed to amortize this balance over a two-year period, starting in February 1998. The amortization was increased in June 1999 as a result of the Company's generation asset sale. See Note 1 to the Consolidated Financial Statements for a complete discussion of this transaction. The amortization recorded as a reduction in depreciation expense in 1999 amounted to $2.2 million as compared to $308,000 of amortization in 2000. The Company's expenses over the period 1999-2001 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 are the allowable recovery of the Company's abandoned investment in the Seabrook nuclear project and the costs associated with the 1993 and 1995 purchased power contract terminations. The Company's recoverable investment in Seabrook Unit 1 is being amortized at a rate of $1.7 million per year, beginning in 1985, for a period of 30 years. Effective March 1, 1994, as authorized in the base rate order from the MPUC, the Company began amortizing the deferred costs associated with the Beaver Wood purchased power contract termination at a rate of $3.9 million annually over a nine-year period. With the July 1, 1997 temporary rate increase, the MPUC required the Company to accelerate the amortization of this deferred regulatory asset. Effective December 12, 1997, the MPUC ordered the amortization of this regulatory asset to be returned to the level before the temporary rate order. Effective with the rate order in February 1998, the amortization was reduced, so that the unamortized balance of the regulatory asset would be the same as under the original amortization schedule as of March 1, 2000. Consequently, as a result of the rate orders, amortization associated with this regulatory asset was $3.9 million in 2001, $3.7 million in 2000 and $2.8 million in 1999. The approximately $170 million of costs associated with the 1995 purchased power contract buy-back were deferred and recorded as a regulatory asset, to be amortized and collected over a ten-year period, beginning July 1, 1995. Amortization expense related to this contract buyout amounted to $17 million in each of 2001, 2000 and 1999. Prior to the implementation of new rates in March 2000, the Company was recovering deferred PERC restructuring costs at an annual rate of $1 million. Effective March 1, 2000, recovery of PERC restructuring costs was adjusted to include the estimated future value of warrants to be exercised. The adjusted annual amortization amounted to $1.6 million. The amortization expense associated with PERC contract restructuring costs was $1.6 million in 2001, $1.5 million in 2000 and $1 million in 1999. In connection with the electric utility industry restructuring in Maine, the Company was required to sell its generation related assets. As a result, in May 1999 the Company completed the sale of its generation assets and certain transmission rights to PP&L Global, Inc. (PP&L). The Company realized a gain on this sale of approximately $29.8 million, of which $29.3 million was required by the MPUC to be deferred for the future benefit of ratepayers. Effective with the implementation of new rates on March 1, 2000, the Company began amortizing the deferred asset sale gain over a 70 month period. The annual amortization amounts are to be recorded in an uneven manner in order to levelize the Company's revenue requirement over this period. As a result of an increase in the Company's FERC regulated transmission rates on June 1, 2000, and the desire to not increase rates to its retail customers close to the implementation of electric industry restructuring, which occurred on March 1, 2000, the Company agreed to reduce its MPUC jurisdictional distribution rates in an amount equal to the increase in its transmission rates. The reduction in the distribution rates was accomplished by accelerating the amortization of the deferred asset sale gain 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 is expected to be increased by approximately $2.5 million over the 10 1/2 month period the reduced rates are in effect. Also, the Company's FERC jurisdictional transmission rates changed on June 1, 2001. Consistent with 2000, the Company has proposed to reduce 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. 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 property and other taxes in 2000 period was due principally to reductions in property taxes as a result of the sale of the Company's generation assets. This reduction in property taxes was offset to some extent by increased electric plant additions and higher property tax rates. The decrease in total federal and state income taxes for both 2001 as compared to 2000 and for 2000 in relation to 1999 was principally a function of lower earnings in 2001 and 2000 as compared to the prior years. See Footnote 2 to the Consolidated Financial Statements for a reconciliation of the Company's effective income tax rate. OTHER INCOME AND (DEDUCTIONS) AND INTEREST EXPENSE - Allowance for funds used during construction (AFDC), which includes carrying costs on certain regulatory assets and liabilities, increased by $445,000 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 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. AFDC increased by approximately $940,000 in 2000 relative to 1999 due mainly to a $1.25 million increase in carrying costs being recorded on the deferred asset sale gain in 1999. This increase was offset to some extent by a $378,000 reduction in AFDC being recorded on construction work in progress in 2000 due principally to decreased construction costs. Other income, net of income taxes decreased by approximately $1.7 million in 2001 principally as a result of the previously discussed $1.2 million gain on the sale of Penobscot Gas in 2000. Also incremental costs associated with the Company's merger with Emera were $3.9 million in 2001 as compared to $3 million in 2000. Finally, investment income decreased by approximately $539,000 in the 2001 period due principally to reductions in the Company's available cash balances from the 1999 generation asset sale (see the section on Liquidity and Capital Resources). Other income decreased by approximately $2.7 million in 2000 relative to 1999 principally as a result of a $1.5 million income tax benefit recorded in 1999 associated with the flow-through of unamortized investment tax credits and excess deferred income taxes related to generation assets sold to PP&L in May 1999 and the effect of incremental merger related costs ($1.8 million, net of tax) incurred in 2000. Also decreasing other income in 2000 as compared to 1999 was a $310,000, net of tax, gain on sale of the Company's wholly-owned subsidiary, Penobscot Hydro Co., Inc. (Penobscot Hydro), in July 1999 (See Note 7 to the Consolidated Financial Statements for a discussion of this sale). These decreases in other income in 2000 were offset to some extent by the previously discussed gain on sale of Penobscot Gas in 2000. Long-term debt interest expense decreased $1.4 million in 2001 in relation to 2000 due primarily to repayments on the Company's long-term debt in each year. In June 2001 and June 2000, the Company made $15.1 million and $14 million in principal payments, respectively, on the Finance Authority of Maine (FAME) Revenue Notes. Also, monthly principal payments on the $24.8 million medium term notes amounting to approximately $6.2 million and $5.5 million, respectively, in 2001 and 2000. These were offset to some extent by interest expense in 2001 associated with a $13.7 million note established in October 2001 with the Municipal Review Committee in connection with the exercise of common stock warrants. See note 5 to the consolidated financial statements for a discussion of this new debt. Long-term debt interest expense decreased $3.8 million in 2000 as compared to 1999 as a result of principal repayments in 2000 and 1999 on various long-term debt issues. See the section on liquidity, capital requirements and capital resources for a more complete discussion of the long-term debt repayments in 2000 and 1999. Other interest expense increased by approximately $116,000 in 2001 due principally to borrowings and fees under the Company's revolving credit facility. Weighted average borrowings outstanding were approximately $3 million in 2001, while 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. Other interest expense decreased $500,000 in 2000 due principally to a reduction in the amortization of debt issuance costs in 2000. The amortization decrease was primarily attributable to the end of the amortization of certain deferred debt issuance costs in 1999 as a result of the repayment of long-term debt through the utilization of generation asset sale proceeds and the end of the amortization period of certain deferred debt issuance costs in June 2000. Also impacting the reduction in other interest expense was $11 million in weighted average borrowings under the Company's revolving credit facility for the first quarter of 1999 as compared to no outstanding borrowings in 2000. LIQUIDITY, CAPITAL REQUIREMENTS, AND CAPITAL RESOURCES The Consolidated Statements of Cash Flows reflect events for the years ended December 2001, 2000 and 1999 as they affect the Company's liquidity. Net cash provided by operations was approximately $25.3 million in 2001, $37.6 million in 2000 and $47.4 million in 1999. 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 (See Note 7 to the Consolidated Financial Statements). 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. Also cash flows were negatively impacted by the previously discussed $.008/kWh rate reductions provided to certain large customers starting in April 2001. While earnings impacts of the rate discounts are 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 are in effect. 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. 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 11 to the Consolidated Financial Statements for a discussion of this transaction. Negatively impacting cash flows in the 2000 as compared to 1999 was $3 million in previously discussed deferred costs associated with the Company providing standard-offer service to customers, as well as $1.4 million in deferred costs for the period from March 1, 2000 through December 31, 2000, associated with a deficiency in actual revenues realized from customers under special rate contracts as compared to the estimated revenues for these customers utilized in setting the Company's new electric rates starting March 1, 2000. The Company was granted a deferral mechanism for the differences in these revenues in its February 2000 rate order from the MPUC. Also negatively impacting cash flows in 2000 was the impact of a lower authorized return on equity of 11% ordered by the MPUC effective March 1, 2000 with the advent of the electric industry restructuring. Positively impacting cash flows from operations in the 1999 period was the receipt of a $1.75 million payment related to a terminated purchased power contract (See the 1999 Form 10-K). These decreases in cash flows from operations for 2000 as compared to 1999 were offset to some extent by a $5.8 million reduction in interest payments in 2000 principally as a result of long-term debt principal payments discussed below. Also the Company incurred $5.3 million in closing and selling costs associated with the generation asset sale in 1999. Over the last three years, capital expenditures have been $16.4 million in 2001, $16.7 million in 2000 and $20.3 million in 1999. In 2001, approximately $9.5 million of the capital expenditures were related to the Company's electric distribution system, $1.6 million was associated with the electric transmission system, and the remaining $5.3 million was expended in connection with customer information system changes necessitated by the electric industry restructuring, other general property and equipment, software, and internal combustion facilities. In 2000, approximately $8.2 million of the capital expenditures were related to the electric distribution system, $4.2 million was associated with the electric transmission system, $2.4 million was expended in connection with customer information system changes necessitated by the electric industry restructuring, and the remainder related to other general property and equipment, software, and internal combustion facilities. In 1999, approximately $8 million of the capital expenditures were related to the Company's electric distribution system, $5.6 million was associated with the electric transmission system and certain fiber optic equipment, $3.2 million was expended in connection with Y2K compliance and restructuring related activities, and the remainder related to other general property and equipment, software, and internal combustion facilities. The Company expects its capital expenditures to total between $45 and $50 million over the next three years, although it may be necessary to adjust the budget for capital expenditures on a year-to-year basis. As previously discussed, in July 2000 the Company received $1.25 million in connection with the sale of Penobscot Gas. As discussed in the 1999 Form 10-K, the Company received approximately $79.6 million in proceeds related to its generation asset sale in late May 1999 and an additional $10 million in late July 1999 in connection with the sale of Penobscot Hydro. Also impacting cash flows in 1999 were Graham Station property sale proceeds. This sale is discussed in note 11 to the consolidated financial statements. The $6.2 million in proceeds associated with the sale of this property were required to be deposited with a third party trustee in September 1998. In January 1999 the trustee released the $6.2 million to the Company, and the funds were utilized to repay outstanding medium term notes. 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 common dividends paid in 2000 relative to 1999 was a result of the reinstatement of the Company's common dividend in the second quarter of 1999, as well as the increase in the common dividend in March 2000. The reduction in preferred dividends paid in 2000 as compared to 1999 resulted from the final redemption of the remaining outstanding 8.76% mandatory redeemable preferred stock in October 1999. In 2000 the Company made $19.5 million in repayments on long-term debt, including a $14 million principal payment at the end of June 2000 on the Finance Authority of Maine Revenue Notes and $5.5 million in payments on the $24.8 million medium term notes which are discussed below. In 1999 the Company made $85.8 million in repayments on long-term debt. The increase in repayments in 1999 was due principally to the utilization of generation asset sale proceeds. The Company made $3.7 million in principal repayments on the Company's 12.25% first mortgage bonds (which were fully repaid in August 1999); a $13.1 million principal payment at the end of June 1999 on the Finance Authority of Maine Revenue Notes; $4.7 million in payments on the $24.8 million medium term notes; principal repayments of $6.2 million and $38.8 million in January and June 1999, respectively, on the $45 million medium term notes which were issued on June 29, 1998; the full redemption of $15 million in outstanding 10.25% series first mortgage bonds in early July 1999; and the redemption of $4.2 million in outstanding variable rate Pollution Control Revenue Bonds in early September 1999. In 1999, through the use of generation asset sale proceeds, the Company redeemed the remaining outstanding 90,000 shares of its 8.76% mandatory redeemable preferred stock amounting to $9 million. The Company also made approximately $563,000 in payments to the institutional holder of the 8.76% series preferred stock related to a "make whole provision" under the preferred stock purchase agreement. Of this amount approximately $320,000 was recorded as a reduction of the deferred asset sale gain, while approximately $243,000 was recorded as a reduction in the 8.76% preferred stock balance. 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 million. The Company's utilization of the line of credit was also impacted by the approximately $3.8 million in incremental merger costs in 2001 and the cash payments to common stock warrant holders in 2001 amounting to approximately $14.2 million. 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, 2001, and the agreement was further extended until March 31, 2002. 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. Capital and operating needs in 2001, 2000 and 1999 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 until a longer term financing structure is implemented. The Company has approximately $121.7 million of first mortgage bonds and other long-term debt maturities in the period 2002-2006. 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. Decommissioning of the Plant site continued, with major emphasis directed to maintaining the schedule on critical-path projects such as construction of the ISFSI and preparation of the Plant's reactor vessel for eventual shipment to an off-site disposal facility. 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. That amount represents full payment under the performance bond, plus an additional amount under the payment bond reflecting certain payments 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. The deposit was reflected on Maine Yankee's 2001 financial statements. Maine Yankee is continuing to pursue its claim 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 has asserted a right to recover an additional $21 million in that court from the bankrupt estate. The hearing on the claim was held in late 2001, and Maine Yankee expects a decision from the court later in 2002. Recovery of such an additional amount in the Bankruptcy Court is contingent on a number of factors beyond Maine Yankee's control, including the extent to which the bankrupt estate has assets available to pay any amount determined to be recoverable. Maine Yankee therefore cannot predict what amount, if any, it will recover on this claim. On February 27, 2002, Stone & Webster filed a claim for approximately $6.9 million against Maine Yankee in the Bankruptcy Court in Delaware for alleged breaches of contract and to subordinate Maine Yankee's claims. Maine Yankee cannot predict the outcome of the new claim. In connection with the state of Maine's electric industry restructuring law, the Company was allowed the recovery of Maine Yankee decommissioning costs as a component of its stranded costs. In the Company's rate order from the MPUC that became effective March 1, 2000, the Company was allowed to defer the amount of any future FERC ordered changes in Maine Yankee's decommissioning collections. Consequently, management does not believe that Maine Yankee's decommissioning contractor difficulties will have a material adverse impact on the Company's results of operations, financial condition or cash flows. 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. 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." OTHER - Management's discussion and analysis of results of operations and financial condition contains items that are "forward-looking" as defined in the Private Securities Litigation Reform Act of 1995. These statements are subject to certain risks and uncertainties that could cause actual results to differ materially from those anticipated in the forward-looking statements. Readers should not place undue reliance on forward-looking statements, which reflect management's view only as of the date hereof. The Company undertakes no obligation to publicly revise these forward-looking statements to reflect subsequent events or circumstances. Factors that might cause such differences include, but are not limited to, the Company's merger with Emera, future economic conditions, relationships with lenders, earnings retention and dividend payout policies, electric utility restructuring, developments in the legislative, regulatory and competitive environments in which the Company operates and other circumstances that could affect revenues and costs. CONTINGENCIES AND DISCLOSURES ABOUT MARKET RISK ENVIRONMENTAL MATTERS - The Company is regulated by the United States Environmental Protection Agency (EPA) as to compliance with the Federal Water Pollution Control Act, the Clean Air Act, and several federal statutes governing the treatment and disposal of hazardous wastes. The Company is also regulated by the Maine Department of Environmental Protection (DEP) under various Maine environmental statutes. The Company is actively engaged in complying with these federal and state acts and statutes, and it has not, to date, encountered material difficulties in connection with such compliance. In 1992, the Company received notice from the DEP that it was investigating the cleanup of several sites in Maine that were used in the past for the disposal of waste oil and other hazardous substances, and that the Company, as a generator of waste oil that was disposed at those sites, may be liable for certain cleanup costs. The Company learned in October 1995 that the EPA placed one of those sites on the National Priorities List under the Comprehensive Environmental Response, Compensation and Liability Act and would pursue potentially responsible parties. With respect to this site, the Company is one of a number of waste generators under investigation. The Company has recorded a liability, based on currently available information, for what it believes are the estimated environmental remediation costs that the Company expects to incur for this waste disposal site. Additional future environmental cleanup costs are not reasonably estimable due to a number of factors, including the unknown magnitude of possible contamination, the appropriate remediation methods, and possible effects of future legislation or regulation and the possible effects of technological changes At December 31, 2001, the liability recorded by the Company for its estimated environmental remediation costs amounted to approximately $435,000. The Company's actual future environmental remediation costs may be different as additional factors become known. In 2001 the Company expended approximately $544,000 in operations to comply with environmental standards for air, water and hazardous materials. DISCLOSURES ABOUT MARKET RISK - The Company's major financial market risk exposure is changing interest rates. Changes in interest rates will affect interest paid on variable rate debt and the fair value of fixed rate debt. The Company manages interest rate risk through a combination of both fixed and variable rate debt instruments and an interest rate swap, which is associated with the Company's medium term notes (See Note 13 to the Consolidated Financial Statements). As of December 31, 2001, the Company had $5.5 million of medium term notes outstanding which bear floating, LIBOR-based rates (1.87375% LIBO rate at December 31, 2001). The interest rate swap fixes the interest rate on the medium term notes at 5.72% for the full notional amount of the debt. See Note 5 to the Consolidated Financial Statements for a discussion of these medium term notes. Item 8 Financial Statements & Supplementary Data BANGOR HYDRO-ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF INCOME For the Years Ended December 31,

~~Assets~~Predecessor ~~2000~~--------------------------------------------------- ~~1999~~Period ~~Investment~~From InPeriod ~~Utility~~From ~~Plant:~~January ~~Electric plant in service~~1, atAcquisition ~~original~~2001 ~~cost~~Date ~~(Notes~~to 6,Through 10December ~~and 12) $ 316~~31,~~167,622~~ $Acquisition ~~306,970,789~~2001 ~~Less~~Date -2000 ~~Accumulated~~1999 ~~depreciation and amortization (Notes 1, 6 and 10) 86,684,205 84,825,432~~ -------------- -------------- ~~$ 229,483,417 $ 222,145,357 Construction work in progress (Note 1) 5,457,707 5,668,246~~ -------------- -------------- $Electric ~~234,941,124~~Operating $Revenues: ~~227,813,603~~Electric ~~Investments~~operating inrevenue ~~corporate joint ventures:~~ (~~Notes~~Note 1 ~~and 6~~) ~~Maine~~$ ~~Yankee~~34,326,272 ~~Atomic~~$ ~~Power~~98,664,499 ~~Company~~ $ 4146,~~949~~204,~~696~~013 $ 5197,~~266~~994,~~697~~796 ~~Maine~~Standard ~~Electric~~offer ~~Power~~service ~~Company,~~(Note ~~Inc.~~11) ~~672~~17,~~581~~476,348 ~~529~~67,~~630~~112,864 66,133,532 - -- ------------ - ------------ $- ~~240,563,401 $ 233,609,930~~ ------------ - ------------- ~~Other~~$ ~~Investments~~51,802,620 at$ ~~cost~~165,777,363 ~~(Notes 6 and 9)~~ $ 3212,~~174~~337,~~561~~545 $ 3197,~~629~~994,~~431~~796 -- ------------ - ------------ ~~Funds~~- ~~held by trustee, at cost (Notes 4, 9 and 10) $ 22,696,405 $ 22,698,843~~ ------------ - ------------- ~~Current~~Operating ~~Assets~~Expenses: ~~Cash~~Fuel for generation and ~~cash~~purchased ~~equivalents~~power (Notes 1 and 94) $ 128,~~462~~711,~~780~~924 $ 1525,~~691~~587,~~166~~586 ~~Accounts~~$ ~~receivable~~44, ~~net of reserve ($761~~144,~~000~~334 ~~in 2000 and~~ $~~1,075,000~~ ~~in 1999) 21~~80,~~731~~748,~~869~~385 ~~18,269,672~~Standard ~~Unbilled~~offer ~~revenue~~service ~~receivable~~purchased power (Note 111) 1516,~~778~~945,~~696~~383 1465,~~127~~893,~~645~~732 ~~Inventories~~65,552,980 at- ~~average~~Other ~~cost:~~operation ~~Material~~and maintenance (Notes 1 and ~~supplies~~6) 210,~~585~~019,~~107~~568 228,~~792~~848,~~904~~107 ~~Fuel oil 93~~37,~~746 45~~211,~~310~~862 ~~Prepaid expenses 829~~36,~~181 927~~491,~~998~~666 ~~-------------~~Depreciation ~~-------------~~and ~~Total~~amortization ~~current~~(Note ~~assets~~1) $2,198,158 537,~~481~~826,~~379~~371 $9,158,885 518,~~854~~063,~~695~~939 ~~-------------~~Amortization ~~-------------~~of ~~Regulatory Assets and Deferred Charges: Investment in~~ Seabrook nuclear ~~project,~~unit ~~net~~(Note of8) ~~accumulated~~424,763 ~~amortization~~1,274,287 of1,699,050 ~~$33~~1,~~571~~699,~~296~~050 inAmortization ~~2000~~of ~~and~~contract ~~$31,872,246~~buyouts inand ~~1999~~restructuring (~~Notes~~Note 7 ~~and 10~~) ~~$ 25~~5,~~270~~639,~~779~~281 ~~$ 26~~16,~~969~~917,~~829~~843 ~~Costs to terminate/restructure purchased power contracts~~22,311,448 ~~net of accumulated amortization of $123~~20,~~171~~801,~~966~~816 inAmortization ~~2000~~of ~~and~~deferred ~~$100,860,518~~asset insale ~~1999~~gain (~~Notes~~Note 611) ~~and 10~~(2,105,076) 99(5,~~312~~971,~~319~~057) ~~118~~(6,~~565~~393,~~234~~038) ~~Maine~~- ~~Yankee~~Taxes ~~decommissioning~~- ~~costs~~Local ~~(Notes~~property 6 and ~~10)~~other 431,~~028~~181,~~107~~771 463,~~041~~817,~~644~~948 ~~Other regulatory assets (Notes 2~~4,795,698 5,6059,~~10,~~140 ~~and~~Income 13(Note 3) 412,~~025~~038,~~080~~384 364,~~925~~713,~~665~~760 ~~Other deferred charges 3~~7,~~667~~432,~~769~~261 38,~~655~~973,~~009~~166 -- ------------ - ------------- ~~Total~~- ~~regulatory~~------------ ~~assets~~- ~~and~~------------ ~~deferred~~$ ~~charges~~45,054,156 $ ~~212~~148,~~304~~908,~~054~~577 $ ~~232~~185,~~157~~913,~~381~~480 $ 161,837,162 -- ------------ - ------------- ~~Total~~- ~~Assets~~------------ - ------------ Operating Income $ ~~532~~6,~~219~~748,~~800~~464 $ ~~543~~16,~~950~~868,~~280~~786 ~~=============~~$ ~~=============~~26,424,065 ~~Stockholders'~~$ ~~Investment~~36,157,634 ~~and~~Other ~~Liabilities~~Income ~~Capitalization:~~And (~~see~~Deductions): ~~accompanying~~Allowance ~~statement)~~for ~~Common~~equity ~~stock~~funds ~~investment~~used during construction (Note 31) $ ~~137~~139,~~419,659~~532 $ ~~132~~464,~~721,895~~541 ~~Preferred~~$ ~~stock~~158,698 ~~(Note~~$ 3(326,026) 4Other,~~734,000~~ ~~4,734,000 Long-term debt,~~ net of ~~current~~applicable ~~portion~~income taxes (Notes 41, 93, 7 and 1311) ~~161~~157,~~960~~452 (1,~~000~~416,135) ~~183~~454,~~300~~715 3,~~000~~132,097 -- ------------ - ------------- ~~Total~~- ~~capitalization $ 304,113,659 $ 320,755,895~~ ------------ - ------------- ~~Current~~Income ~~Liabilities:~~Before ~~Notes~~Interest ~~payable~~Expense -$ ~~banks~~7,045,448 ~~(Note~~$ 4)15,917,192 $ -27,037,478 $ 38,963,705 -- ------------ - ------------- ~~Other~~- ~~current~~------------ ~~liabilities~~- ------------ ~~Current~~Interest ~~portion~~Expense: ~~of long~~Long-term debt (Notes 45 and 913) $ 213,~~340~~393,~~000~~733 $ 1910,~~460~~429,~~000~~419 ~~Accounts~~$ ~~payable 24~~15,~~785~~211,~~193~~905 14$ 19,~~175~~004,~~408~~624 ~~Dividends~~Other ~~payable~~(Note 15) 286,~~539,114~~443 1722,~~170,942~~586 ~~Accrued interest 2~~893,~~529,237~~455 21,~~552~~393,~~758~~547 ~~Customers'~~Allowance ~~deposits~~for ~~502,276~~borrowed ~~398,897~~funds ~~Current~~used ~~income~~during ~~taxes~~construction ~~payable~~(Note ~~305~~1) (135,~~323~~676) 4(423,~~125~~431) (169,~~696~~929) 284,933 -- ------------ - ------------- ~~Total~~- ~~other current liabilities $ 51,001,143 $ 41,883,701~~ ------------ - ------------- ~~Total~~$ ~~current~~3,544,500 ~~liabilities~~$ 10,728,574 $ 5115,~~001~~935,~~143~~431 $ 4120,~~883~~683,~~701~~104 -- ------------ - ------------- ~~Commitments~~- ~~and~~------------ ~~Contingencies (Notes 6, 12 and 15) Regulatory and Other Long~~-~~term~~ ~~Liabilities (Note 2) Deferred income taxes~~ ------------ ~~Seabrook~~Net Income $ 133,~~109~~500,~~098~~948 $ 135,~~994~~188,~~668~~618 ~~Other~~$ ~~accumulated deferred income taxes 58~~11,~~314~~102,~~350~~047 55$ 18,~~826~~280,~~890~~601 ~~Maine~~Dividends ~~Yankee~~On ~~decommissioning~~Preferred ~~liability~~Stock (Note 64) 4366,~~028~~429 199,~~107~~141 46265,~~041~~570 945,~~644~~396 ~~Deferred~~-- ~~gain~~------------ on- ~~asset~~------------- ~~sale~~- ~~(Note~~------------ ~~10)~~- ~~22,788,408~~------------ ~~29,357,358~~Earnings ~~Other~~Applicable ~~regulatory~~To ~~liabilities~~Common ~~(Note~~Stock ~~10)~~$ 123,~~556~~434,~~052~~519 9$ 4,~~872~~989,~~188~~477 ~~Unamortized~~$ ~~investment tax credits 1~~10,~~452~~836,~~059~~477 1$ 17,~~591~~335,~~727~~205 ~~Accrued~~== ~~pension~~============ ~~and~~= ~~postretirement~~============= ~~benefit~~= ~~costs~~============ ~~(Note~~= 5)============ ~~12,124,106~~Weighted ~~11,301,057~~Average ~~Other~~Number ~~long-term~~Of ~~liabilities~~Shares Outstanding (~~Notes~~Note 64) ~~and~~7,363,424 ~~12)~~7,363,424 137,~~732~~363,~~818~~424 137,~~325~~363,~~152~~424 -- ------------ - ------------- ~~Total regulatory and other long~~-~~term~~ ~~liabilities $ 177,104,998 $ 181,310,684~~ ------------ - ------------- ~~Total~~Earnings ~~Stockholders'~~Per ~~Investment~~Common ~~and~~Share ~~Liabilities~~(Note 4): Basic $ ~~532,219,800~~.47 $ ~~543,950,280~~.67 $ 1.47 $ 2.35 Diluted .47 .61 1.30 2.08 == ============ = ============= = ============ = ============ Dividends Declared Per Common Share $ - $ .60 $ .80 $ .45 == ============ = ============= = ============ = ============ The accompanying notes are an integral part of these consolidated financial statements.

BANGOR HYDRO-ELECTRIC COMPANY CONSOLIDATED BALANCE SHEETS December 31,

~~2000~~Predecessor ~~1999~~Assets ~~----~~2001 ~~----~~2000 ~~Common Stock~~ Investment ~~(Notes~~In 1Utility ~~and~~Plant: 3)Electric ~~Common~~plant ~~stock~~in service, ~~par~~at ~~value~~original $5cost ~~per~~(Note ~~share-~~12) $ 36328,~~817~~559,~~120~~986 $ 36316,~~817~~167,~~120~~622 ~~Authorized~~Less -- ~~10,000,000~~Accumulated ~~shares~~depreciation ~~Outstanding -- 7,363,424 shares in 2000~~ and ~~1999~~amortization ~~Amounts~~(Note ~~paid~~1) ~~in excess of par value 58~~93,~~642~~984,~~367~~836 5886,~~890~~684,~~342~~205 ~~Retained~~- ~~earnings 41,960,172 37,014,433~~ ------------ -- ------------- ~~Total common stock investment~~ $ ~~137~~234,~~419~~575,~~659~~150 $ ~~132~~229,~~721~~483,~~895~~417 ~~Preferred~~Construction ~~Stock,~~work ~~Non-participating,~~in ~~cumulative,~~progress ~~par~~(Note ~~value~~1) ~~$100~~7,307,837 ~~per share~~5,457,707 - ------------ - ------------- ~~authorized~~$ ~~600~~241,~~000~~882,987 ~~shares~~$ ~~(Note~~234,941,124 ~~3):~~Investments ~~Not~~in ~~redemable~~corporate orjoint ~~redeemable~~ventures: ~~solely~~(Notes at1 ~~the~~and ~~option of the issuer-~~ 7%,) ~~Noncallable,~~Maine ~~25,000~~Yankee ~~shares~~Atomic ~~authorized~~Power ~~and~~Company ~~outstanding~~ $ 24,~~500~~421,~~000~~884 $ 24,~~500~~949,~~000~~696 ~~4.25%,~~Maine ~~Callable~~Electric atPower ~~$100~~Company, 4Inc. 853,~~840~~562 ~~shares~~672,581 ~~authorized~~- ~~and~~------------ ~~outstanding~~- ~~484,000~~------------ ~~484,000~~$ 4%247,158,433 ~~Series~~$ A240,563,401 ~~Callable~~- at------------ ~~$110,~~- 17------------ Other Investments,~~500~~ ~~shares~~at ~~authorized~~cost ~~and~~(Note ~~outstanding~~9) 1$ 3,~~750~~497,~~000~~681 1$ 3,~~750~~174,~~000~~561 - ------------ - ------------- $Funds ~~4,734,000~~held $by 4trustee,~~734,000~~ ~~Long-Term~~at ~~Debt~~cost (Notes 4,5 9 and 149) $ 22,694,648 $ 22,696,405 - ------------ - ------------- ~~First~~Current ~~Mortgage~~Assets: ~~Bonds-~~Cash ~~10.25%~~and ~~Series~~cash ~~due~~equivalents ~~2020~~(Notes 1 and 9) $ 30884,~~000,000~~617 $ 3012,~~000~~462,~~000~~780 ~~8.98%~~Accounts ~~Series~~receivable, ~~due~~net ~~2022~~of 20reserve ($761,000 in 2001 and 2000) 19,~~000~~268,889 2021,~~000~~731,~~000~~869 ~~7.38%~~Unbilled ~~Series~~revenue ~~due~~receivable ~~2002~~(Note 201) 15,~~000~~379,~~000~~708 2015,~~000~~778,~~000~~696 ~~7.30%~~Inventories, ~~Series~~at ~~due~~average ~~2003~~cost: 15Material and supplies 2,~~000~~531,~~000~~853 152,~~000~~585,~~000~~107 Fuel oil 53,320 93,746 Prepaid expenses 671,267 829,181 - ------------ - ------------- Total current assets $ 8538,~~000~~789,~~000~~654 $ 8553,~~000~~481,~~000~~379 ~~Other Long~~-~~Term~~ ~~Debt~~- ----------- --- ------------- ~~Finance~~Regulatory ~~Authority~~Assets ofand ~~Maine~~Deferred Charges: Goodwill-EMERA ~~Taxable~~Acquisition ~~Electric~~(Note ~~Rate~~2) ~~Stabilization~~$ ~~Revenue~~82,537,291 ~~Notes~~$ - Investment in Seabrook nuclear project, ~~7.03%~~net ~~Series~~of ~~1995A~~accumulated amortization of $35,270,346 ~~due~~in ~~2005~~2001 and $33,571,296 86in 2000 (Notes 8 and 11) 23,~~600~~571,~~000~~729 25,270,779 Costs to terminate/restructure purchased power contracts, net of accumulated amortization of $145,729,090 ~~100~~in 2001 and $123,~~600~~171,~~000~~966 ~~Medium~~in ~~Term~~2000 (Notes 7 and 11) 92,057,206 ~~Variable~~99,312,319 ~~interest~~Maine ~~rate-LIBO~~Yankee ~~rate~~decommissioning ~~plus~~costs ~~1.125%,~~(Notes ~~due~~7 ~~2002~~and 11) 37,~~700~~306,~~000~~576 1743,~~160~~028,~~000~~107 Above-~~-------------~~market ~~-------------~~purchased $power ~~98,300,000~~contract $obligation ~~117~~(Notes 11 and 13) 73,~~760~~954,000 ~~Less:~~- ~~Current~~Other ~~portion~~regulatory ofassets ~~long-term~~(Notes ~~debt~~3,5,6 21and 11) 52,~~340~~657,~~000~~562 1941,~~460~~025,~~000~~080 ~~--------------~~Other ~~-------------~~deferred $charges 764,~~960~~019,~~000~~969 ~~$ 98~~3,~~300~~667,~~000~~769 - ------------ - ------------- Total ~~Long-Term~~regulatory ~~Debt~~assets and deferred charges $ ~~161~~366,~~960~~104,~~000~~333 $ ~~183~~212,~~300~~304,~~000~~054 - ------------ - ------------- Total ~~Capitalization~~Assets $ ~~304~~678,~~113~~244,~~659~~749 $ ~~320~~532,~~755~~219,~~895~~800 ============== ============== The accompanying notes are an integral part of these consolidated financial statements.

BANGOR HYDRO-ELECTRIC COMPANY CONSOLIDATED BALANCE SHEETS December 31,

~~2000~~Predecessor ~~1999~~Stockholders' ~~1998~~Investment ~~----~~and ~~---~~Liabilities ~~----~~2001 ~~Cash~~2000 ~~Flows From Operating Activities~~Capitalization: ~~Net~~(see ~~income~~accompanying $statement) ~~11,102,047~~Common $stock ~~18,280,601~~investment ~~$ 11,465,317 Adjustments to reconcile net income to net cash from operating activities: Depreciation and amortization 9,158,885 8,063,939 9,749,229 Amortization of Seabrook nuclear project~~ (Note 74) ~~1,699,050~~$ 1205,~~699~~556,~~050~~673 1$ 137,~~699~~419,~~050~~659 ~~Amortization~~Preferred ofstock ~~contract buyouts and restructuring~~ (Note 64) 224,~~311~~734,~~448~~000 204,~~801~~734,~~816~~000 ~~20,442,441 Amortization of deferred asset sale gain (Note 10) (6,393,038)~~ Long-term ~~- Other amortizations 1~~debt,~~896,179~~ ~~2,590,725~~net ~~2,035,505~~of ~~Allowance~~current ~~for~~portion ~~equity funds used during construction~~ (~~Note~~Notes ~~1) (158~~5,~~698)~~ ~~326,026~~9 ~~(430,028) Deferred income tax provision~~ and ~~amortization of investment tax credits (Note 2~~13) ~~(2,765,264) (~~131,~~897) 5~~967,~~876,874~~827 ~~Gain on sale of subsidiary (Notes 6 and 10) (1~~161,~~205~~960,~~727)~~000 ~~(523,390)~~ - ~~Deferred Maine Yankee replacement power cost write~~-~~off (Note 6) 1,992,848~~ - - ~~Flow~~-~~through of unamortized investment tax credits and excess deferred income taxes (Note 2)~~ - ~~(1,485,131)~~ - ~~Changes in assets and liabilities: Costs to restructure purchased power contract (Note 6) (1,000,000) (1,099,000) (7,704,185) Deferred standard~~-~~offer service costs (Note 10) (2,988,823)~~ - - ~~Deferred special rate contract revenues (Note 10) (1,368,948)~~ - - ~~Deferred incremental Maine Yankee costs (Note 6) 807,616 2,886,401 (793,608) Deferred incremental ice storm costs (Note 11)~~ - ~~1,817,851 (4,200,423) Deferred costs associated with generation asset sale (Note 10) 107,765 (5,266,689) (2,317,688) Exercise of PERC warrants~~-~~cash~~ ~~paid in lieu of issuing shares (Note 6) (2,129,387) (3,321,710)~~ - ~~Payment received related to terminated purchased power contract (Note 6~~ - ~~1,750,000~~ - ~~Deferred revenue~~ - -------- ~~(1,285,101)~~Total ~~Accounts~~capitalization ~~receivable,~~$ ~~net and unbilled revenue (5~~342,~~113~~258,~~248)~~500 ~~(2,759,315)~~$ (1304,~~423~~113,~~947)~~659 ~~Accounts~~- payable 10,609,785 (11,081) 724,721 Accrued interest (23,521) (921,611) (192,272) Current and deferred income taxes (10,093) 3,755,913 121,153 Accrued postretirement benefit costs (Note 5) 1,322,206 1,608,414 600,699 Other current assets and liabilities, net 202,486 (356,034) (22,036) Other, net (433,387) (345,523) (3,413,741) ------------- -~~-------------~~ ------------- ~~Net~~Current ~~Increase~~Liabilities: inNotes ~~Cash~~payable ~~From~~- ~~Operating~~banks ~~Activities:~~(Note $5) ~~37,620,181~~ $ 478,~~359~~000,~~355~~000 $ ~~30,931,960~~- ~~Cash~~- ~~Flows From Investing Activities:~~ ------------- -~~-------------~~ ------------- ~~Construction~~Other ~~expenditures~~current $liabilities ~~(16,680,501)~~- $Current ~~(20,323,360)~~portion $of ~~(18,240,226)~~long-term ~~Asset~~debt ~~sale~~(Notes ~~proceeds~~5 ~~(Note~~and 109) -$ 7943,~~587~~245,~~841~~891 6$ 21,~~200~~340,000 ~~Proceeds~~Accounts ~~from~~payable ~~sale of subsidiary (Notes 6 and 10) 1~~22,~~250~~491,~~000~~785 1024,~~000~~785,~~000~~193 -Dividends ~~Release~~payable ~~(deposit)~~66,429 of1,539,114 ~~Graham~~Accrued ~~Station~~interest ~~property sale proceeds held by trustee (Note 10) - 6~~2,~~200~~663,~~000~~225 (62,~~200~~529,~~000)~~237 ~~Allowance~~Customers' ~~for~~deposits ~~borrowed~~572,867 ~~funds~~502,276 ~~used~~Current ~~during~~income ~~construction~~taxes ~~(Note~~payable 1~~) (169~~,~~929) 284~~916,~~933~~892 ~~(693~~305,~~682)~~323 - ------------ -~~-------------~~ ------------- ~~Net~~Total ~~(Decrease)~~other ~~Increase~~current inliabilities ~~Cash From Investing Activities~~ $ ~~(15~~70,~~600~~957,~~430)~~089 $ 7551,~~749~~001,~~414~~143 $- ~~(18,933,908)~~------------ ~~Cash~~- ~~Flows From Financing Activities:~~ ------------ Total current liabilities $ 78,957,089 $ 51,001,143 - ------------ -- ------------- ~~Dividends~~Regulatory onand ~~preferred~~Other ~~stock~~Long-term $Liabilities (~~$265,570~~Note 3) Deferred income taxes - Seabrook $ (112,~~127~~223,~~882)~~523 $ (113,~~216~~109,~~434)~~098 ~~Dividends~~Other onaccumulated ~~common~~deferred ~~stock~~income (5taxes 47,~~522~~405,~~567)~~476 (258,~~209~~314,~~028)~~350 -Maine ~~Payments~~Yankee ondecommissioning ~~long-term~~liability ~~debt~~ (Note 47) ~~(19~~37,~~460~~306,~~000)~~576 ~~(85~~43,~~782~~028,~~897)~~107 ~~(53,478,554)~~Deferred ~~Payments~~gain on ~~mandatory~~asset ~~redeemable~~sale ~~preferred stock~~ (Note 411) ~~- (9~~14,~~243~~574,~~742)~~316 (122,~~593~~788,~~914)~~408 ~~Issuance of long~~Above-~~term~~market ~~debt,~~purchased ~~net~~power ofcontract ~~capital~~obligation ~~reserve fund requirements~~ (Note 413) ~~- - 68~~73,~~300~~954,000 ~~Short~~-~~term~~ ~~debt,~~Other ~~net~~regulatory liabilities (Note 411) ~~- (12~~18,~~000~~961,~~000)~~715 ~~(22~~12,~~000~~556,~~000)~~052 ~~-------------~~Unamortized ~~--------------~~investment ~~-------------~~tax ~~Net~~credits ~~Decrease~~1,311,928 in1,452,059 ~~Cash~~Accrued ~~From~~pension ~~Financing~~and ~~Activities~~postretirement $benefit costs (25Note 6) 39,~~248~~655,~~137)~~265 ~~$ (110~~12,~~363~~124,~~549)~~106 $Other long-term liabilities (9Notes 7 and 12) 11,~~988~~636,~~902)~~361 13,732,818 - ------------ -~~-------------~~ ------------- ~~Net~~Total ~~(Decrease)~~regulatory ~~Increase in Cash~~ and ~~Cash~~other ~~Equivalents~~long-term $liabilities ~~(3,228,386)~~ $ 12257,~~745~~029,~~220~~160 $ 2177,~~009~~104,~~150~~998 ~~Cash~~- ~~and Cash Equivalents at Beginning of Year 15,691,166 2,945,946 936,796~~ ------------- -~~-------------~~ ------------- ~~Cash~~Total ~~and~~Stockholders' ~~Cash~~Investment ~~Equivalents~~and atLiabilities ~~End of Year~~ $ 12678,~~462~~244,~~780~~749 $ 15532,~~691~~219,~~166~~800 $= ~~2,945,946~~ ============= =~~=============~~ ============= The accompanying notes are an integral part of these consolidated financial statements.

BANGOR HYDRO-ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF CAPITALIZATION December 31,

~~Amounts~~Predecessor ~~Paid~~2001 ~~Total~~2000 Common Stock Investment (Notes 1,2 and 4) Common stock, par value $5 per share- $ 36,817,120 $ 36,817,120 Authorized -- 10,000,000 shares Outstanding -- 7,363,424 shares in ~~Excess~~2001 and 2000 Amounts paid in excess of ~~Retained~~par ~~Stock~~value ~~Stock~~165,352,312 ~~Par~~58,642,367 ~~Value~~Accumulated ~~Earnings~~other ~~Investment~~comprehensive loss (47,278) - Retained earnings 3,434,519 41,960,172 - -------------- ------------- Total common stock investment $ 205,556,673 $ 137,419,659 - -------------- ------------- ~~Balance~~Preferred ~~December 31~~Stock, ~~1997 $36~~Non-participating,~~817,120~~ ~~$56~~cumulative,~~969,428~~ par value $12100 per share,~~771,940~~ ~~$106~~authorized 600,~~558,488~~000 ~~Net~~shares ~~income~~(Note -4): Not redemable or redeemable solely at the option of the issuer- 117%,~~465~~ Noncallable,~~317~~ 1125,~~465,317~~000 ~~Cash~~shares ~~dividends~~authorized ~~declared~~and ~~on-~~outstanding ~~Preferred~~$ ~~stock~~2,500,000 -$ ~~- (1~~2,~~183~~500,~~584)~~000 (14.25%,~~183~~ Callable at $100,~~584)~~ ~~Issuance~~4,840 ofshares ~~warrants~~authorized ~~(Note~~and 6)outstanding -484,000 2484,~~084~~000 4%,~~775~~ -Series 2A,~~084~~ Callable at $110,~~775~~ ~~Other~~17,500 ~~(Note~~shares 3)authorized -and -outstanding ~~(60~~1,~~904)~~750,000 ~~(60~~1,~~904)~~750,000 - -------------- ------------- $ 4,734,000 $ 4,734,000 - -------------- ------------- ~~Balance~~Long-Term ~~December~~Debt ~~31,~~(Notes ~~1998 $36~~5,~~817,120~~ ~~$59,054,203~~9 ~~$22,992,769~~and ~~$118,864,092~~14) ~~Net~~First ~~income~~Mortgage Bonds- -10.25% ~~18,280,601~~Series ~~18,280,601~~due ~~Cash~~2020 ~~dividends~~$ ~~declared~~30,000,000 ~~on-~~$ ~~Preferred stock - - (899~~30,~~718) (899~~000,~~718)~~000 ~~Common~~8.98% ~~stock~~Series -due -2022 (320,~~313~~000,~~541)~~000 (320,~~313~~000,~~541)~~000 ~~Exercise~~7.38% ofSeries ~~warrants-cash~~due ~~paid~~2002 ~~in lieu of issuing shares (Note 3) - (410~~20,~~052)~~000,000 ~~- (410~~20,~~052)~~000,000 ~~Transfer of mandatory redeemable 8~~7.7630% ~~preferred~~Series ~~stock~~due ~~issuance~~2003 ~~costs to the deferred asset sale gain (Note 10) 246~~15,~~191~~000,000 ~~246~~15,~~191~~000,000 ~~Other (Note 3)~~ - - ~~(45,678) (45,678)~~ ------------- ------------- $ 85,000,000 $ 85,000,000 - -------------- ------------- ~~Balance~~Other ~~December~~Long-Term ~~31,~~Debt- ~~1999~~Finance ~~$36,817,120~~Authority ~~$58,890,342~~of ~~$37,014,433~~Maine ~~$132,721,895~~- ~~Net~~Taxable ~~income~~Electric -Rate -Stabilization ~~11,102,047~~Revenue 11Notes,~~102,047~~ ~~Cash~~7.03% ~~dividends~~Series ~~declared~~1995A, ~~on-~~due ~~Preferred~~2005 ~~stock~~$ -71,500,000 -$ ~~(265~~86,~~570)~~600,000 ~~(265~~Medium Term Notes,~~570)~~ ~~Common~~Variable ~~stock~~interest rate-LIBO -rate (plus 1.125%, due 2002 5,~~890~~460,~~738)~~000 (511,~~890~~700,~~738)~~000 ~~Exercise~~Municipal ofReview ~~warrants-cash~~Committee ~~paid~~Note, in5%, ~~lieu~~due of2008 ~~issuing~~13,234,394 ~~shares~~- ~~(Note~~Other miscellaneous notes payable, 3).90%, -due ~~(247~~2003 19,~~975)~~324 - ~~(247,975)~~- -------------- ------------- $ 90,213,718 $ 98,300,000 Less: Current portion of long-term debt 43,245,891 21,340,000 - -------------- ------------- ~~Balance December 31, 2000~~ $~~36,817,120~~ ~~$58~~46,~~642~~967,~~367~~827 $41 76,960,~~172~~000 ~~$137,419,659~~- -------------- ------------- Total Long-Term Debt $ 131,967,827 $ 161,960,000 - -------------- ------------- Total Capitalization $ 342,258,500 $ 304,113,659 = ============ = ============ The accompanying notes are an integral part of these consolidated financial statements.

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 2001 Date 2000 ~~Reserve~~1999 ~~for~~Cash ~~Doubtful~~Flows ~~Accounts~~From Operating Activities: Net income $ 13,~~075~~500,~~000~~948 $ 15,~~275~~188,~~016~~618 $ -11,102,047 $ 18,280,601 Adjustments to reconcile net income to net cash from operating activities: Depreciation and amortization 2,198,158 7,826,371 9,158,885 8,063,939 Amortization of Seabrook nuclear project (Note 8) 424,763 1,~~589~~274,~~016~~287 1,699,050 1,699,050 Amortization of contract buyouts and restructuring (CNote 7) $5,639,281 ~~761~~16,917,843 22,311,448 20,801,816 Amortization of deferred asset sale gain (Note 11) (2,105,076) (5,971,057) (6,393,038) - Other amortizations 375,024 1,193,607 1,896,179 2,590,725 Allowance for equity funds used during construction (Note 1) (139,532) (464,541) (158,698) 326,026 Deferred income tax provision and amortization of investment tax credits (Note 3) (212,917) (5,976,077) (2,765,264) (131,897) Gain on sale of subsidiary (Notes 7 and 11) - - (1,205,727) (523,390) Deferred Maine Yankee replacement power cost write-off (Note 7) - - 1,992,848 - Flow-through of unamortized investment tax credits and excess deferred income taxes (Note 3) - - - (1,485,131) Changes in assets and liabilities: Costs to restructure purchased power contract (Note 7) (250,000) (750,000) (1,000,000) (1,099,000) Deferred standard-offer service costs (Note 11) 4,265,218 4,580,779 (2,988,823) - Deferred special rate contract revenues (Note 11) (910,954) (1,404,194) (1,368,948) - Exercise of PERC warrants-cash paid in lieu of issuing shares (Note 7) (4,951,550) (9,225,892) (2,129,387) (3,321,710) Deferred Wyman#4 litigation settlement proceeds (Note 11) 2,592,294 - - - Deferred incremental Maine Yankee costs (Note 7) - - 807,616 2,886,401 Deferred incremental ice storm costs - - - 1,817,851 Deferred costs associated with generation asset sale (Note 11) - - 107,765 (5,266,689) Payment received related to terminated purchased power contract (Note 7) - - - 1,750,000 Accounts receivable, net and unbilled revenue (1,291,684) 1,298,321 (5,113,248) (2,759,315) Accounts payable (1,032,699) (1,359,942) 10,609,785 (11,081) Accrued interest (703,043) 837,030 (23,521) (921,611) Current and deferred income taxes (293,705) 2,253,111 (10,093) 3,755,913 Accrued postretirement benefit costs (Note 6) 589,050 1,533,939 1,322,206 1,608,414 Other current assets and liabilities, net (257,941) 580,127 202,486 (356,034) Other, net (5,530) (501,752) (433,387) (345,523) - -------------- --------------- --------------- -------------- ~~1999~~Net ~~Reserve~~Increase ~~for~~in ~~Doubtful~~Cash ~~Accounts~~From Operating Activities: $ 17,~~075~~430,~~000~~105 $ 117,~~475~~830,~~395~~578 $ 37,620,181 $ 47,359,355 - -------------- --------------- --------------- -------------- Cash Flows From Investing Activities: Construction expenditures $ 1(6,~~475~~264,~~395~~489) $ (B10,083,839) $ (16,680,501) $ (20,323,360) Allowance for borrowed funds used during construction (Note 1) (135,~~075~~676) (423,431) (169,929) 284,933 Asset sale proceeds (Note 11) - - - 79,587,841 Proceeds from sale of subsidiary (Notes 7 and 11) - - 1,250,000 10,000,000 Release of Graham Station property sale proceeds held by trustee (Note 11) - - - 6,200,000 - -------------- --------------- --------------- -------------- Net (Decrease) Increase in Cash From Investing Activities $ (6,400,165) $ (10,507,270) $ (15,600,430) $ 75,749,414 - -------------- ~~1998~~--------------- ~~Reserve~~--------------- ~~for~~-------------- ~~Doubtful~~Cash ~~Accounts~~Flows From Financing Activities: Dividends on preferred stock $ 1(66,~~450~~380) $ (199,~~000~~190) $ (265,570) $ (1,~~345~~127,~~536~~882) $Dividends -on $common stock (1,472,685) (4,418,054) (5,522,567) (2,209,028) Payments on long-term debt (Note 4) (2,054,457) (19,720,~~536~~645) (A19,460,000) $(85,782,897) 1Payments on mandatory redeemable preferred stock (Note 4) - - - (9,~~075~~243,742) Short-term debt, net (Note 5) 2,000,000 6,000,000 - (12,000,000) - -------------- --------------- --------------- -------------- Net Decrease in Cash From Financing Activities $ (1,593,522) $ (18,337,889) $ (25,248,137) $ (110,363,549) - -------------- ~~NOTE:~~--------------- --------------- -------------- Net (ADecrease) ~~Accounts~~Increase ~~written~~in ~~off~~Cash and Cash Equivalents $ (563,582) ~~less~~$ ~~recoveries.~~(11,014,581) ~~For~~$ ~~1998~~(3,228,386) ~~includes~~$ ~~reduction~~12,745,220 inCash ~~reserve~~and ~~for~~Cash ~~doubtful~~Equivalents ~~accounts~~at Beginning of ~~$375~~Year 1,~~000.~~448,199 ~~(B)~~12,462,780 ~~Accounts~~15,691,166 ~~written~~2,945,946 ~~off~~- -------------- --------------- --------------- -------------- Cash and Cash Equivalents at End of Year $ 884,617 ~~less~~$ ~~recoveries.~~1,448,199 ~~(C)~~$ ~~Accounts~~12,462,780 ~~written~~$ ~~off~~15,691,166 ~~less~~============ ~~recoveries.~~============= ~~For~~============= ~~2000~~============== ~~includes~~The ~~reduction~~accompanying innotes ~~reserve~~are ~~for~~an ~~doubtful~~integral ~~accounts~~part of ~~$314,000~~these consolidated financial statements.

BANGOR HYDRO-ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF COMMON STOCK INVESTMENT

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 11) 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 11). Competitive energy providers are paid only after the funds are collected from customers. The Company records accounts receivable for the amounts billed to competitive energy customers and a corresponding accounts payable for the amounts due to the energy supplier. No revenue is recognized as the Company is acting as an agent. DEPRECIATION OF ELECTRIC PLANT AND MAINTENANCE POLICY- Depreciation of electric plant is provided using the straight-line method at rates designed to allocate the original cost of properties over their estimated service lives. The composite depreciation rate (excluding intangible assets), expressed as a percentage of average depreciable plant in service, and considering the amortization of overaccu-mulated depreciation (discussed below), was approximately 2.9% in 2001, 2.9% in 2000 and 2.1% in 1999. A study conducted as of December 31, 1996 determined that the Company's reserve for depreciation was overaccumulated by approximately $3.6 million. In connection with the MPUC's rate order in February 1998, the Company was allowed to amortize this balance over a two-year period, starting in February 1998. The Company recorded approximately $307,000 in amortization in 2000 and $2.4 million in 1999 which reduced depreciation expense. The 1999 and 2000 amortizations were increased as a result of the sale of the Company's hydroelectric plant assets in May 1999. The Company follows the practice of charging to maintenance the cost of repairs, replacements and renewals of minor items considered to be less than a unit of property. Costs of additions, replacements and renewals of items considered to be units of property are charged to the utility plant accounts, and any items retired are removed from such accounts. The original costs of units of property retired and removal costs, less salvage, are charged to the depreciation reserve. Depreciation, local property taxes and other taxes not based on income, which were charged to operating expenses, are stated separately in the Consolidated Statements of Income. Rents, advertising and research and development expenses are not significant. No royalty expenses were incurred. Maintenance expense was $10.1 million in 2001, $10 million in 2000 and $9.5 million in 1999. 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 Combination", 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 11), were also capitalized and included in AFDC in the Consolidated Statements of Income. The average AFDC (carrying costs) rates computed by the Company were 9.1% in 2001, 9.3% for 2000 and 9.5% in 1999. 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 $14.1 million, $15.1 million and $20.9 million in 2001, 2000 and 1999, respectively. Cash paid for income taxes was approximately $10.4 million, $10 million and $8.9 million in 2001, 2000 and 1999, 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 combin-ation of both fixed and variable rate debt instruments and an interest rate swap (see Notes 5 and 15). 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". RECLASSIFICATIONS-Certain prior year amounts have been reclassified to conform with the presentation used in the 2001 Consolidated Financial Statements. NOTE 2. MERGER WITH EMERA, INC. In early October 2001, final regulatory approvals for the merger between the Company and Emera, Inc. (Emera) were received. On October 10, 2001, Emera completed the acquisition of all of the outstanding common stock of the Company for US$26.806 per share in cash. The purchase increases Emera's customer base by 25% and broadens the Company's presence in the expanding northeast energy market. 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 at December 31, 2001, is recorded as goodwill on the consolidated balance sheet. As previously discussed, the goodwill will not be amortized, but instead will be subject to an impairment test at least annually in accordance with the provisions of Statement No. 142. Goodwill associated with the Emera acquisition was not adjusted for any impairment losses in 2001. The following table summarizes the purchase accounting adjustments to the accounts of the Company as of December 31, 2001: Purchase Accounting Adjustments ---------------- Unbilled revenue receivable $ (2,855,331) Goodwill 82,537,291 Regulatory assets (1,660,375) ---------------- Total Assets $ 78,021,585 ============= Common stock investment $ 78,359,333 Current liabilities (1,582,637) Deferred asset sale gain 12,222 Other regulatory liabilities 1,232,667 --------------- Total Liabilities and Stockholders Equity $ 78,021,585 ============= As a result of the merger on October 12, 2001, 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 have been recorded as a component of Other Income (Expense) in the Consolidated Statements of Income for 2001 and 2000. NOTE 3. INCOME TAXES The individual components of federal and state income taxes reflected in the Consolidated Statements of Income for 2001, 2000 and 1999 are stated in the table below. Year Ended December 31, 2001 2000 1999 Current: Federal $ 9,300,188 $ 7,445,626 $7,390,387 State 2,958,075 2,920,769 2,314,251 ---------------- -------------- ----------- $12,258,263 $10,366,395 $9,704,638 --------------- ------------- -------------- Deferred: Federal $ (3,935,012) $ (1,618,863) $ (252,473) State (2,113,851) (1,006,733) (447,641) --------------- --------------- -------------- $(6,048,863) $ (2,625,596) $ (700,114) --------------- --------------- -------------- Investment Tax Credits, Net $ 42,951 $ (139,668) $ (317,877) --------------- --------------- -------------- Total Provision $ 6,252,351 $ 7,601,131 $ 8,686,647 Allocated to Other Income 499,793 (168,870) 286,519 --------------- --------------- -------------- Charged to Operating Expens $ 6,752,144 $ 7,432,261 $ 8,973,166 ============= =========== =============== Under the federal income tax laws, the Company received investment tax credits (ITC) on qualified property additions through 1986. ITC utilized were deferred and are being amortized over the life of the related property. In 1999 the Company utilized the remaining available ITC of about $3.2 million to reduce its federal income tax obligation. In 2000, the Company utilized the remaining $3.6 million of federal alternative minimum tax credits to reduce its regular income tax liability while in 1999, the Company utilized $4.2 million of federal and state alternative minimum tax credits. These net operating losses were principally due to the Company deducting for income tax reporting purposes the costs of the purchased power contract terminations in 1995, which were deferred for financial reporting purposes (see Note 7). The table below reconciles the income tax provision, calculated by multiplying income before federal income taxes (as reported on the Consolidated Statements of Income) by the statutory federal income tax rate to the federal income tax expense reported on the Consolidated Statements of Income. The difference is represented by the permanent and timing differences for which deferred taxes are not provided for ratemaking purposes. 2001 2000 1999 ----------------------------------- (Dollars in Thousands) Amount % Amount % Amount % ---------------------------------------- Federal income tax provision at statutory rate $5,230 35.0% $6,546 35.0% $9,439 35.0% Less (Plus) permanent differences in tax expense resulting from statutory exclusions from taxable income: Dividend received deduction related to earnings of associated companies 74 .5 164 .9 253 .9 Equity component of AFDC 170 1.1 138 .7 185 .7 Asset sale gain permanent differences (349) (2.3) (276) (1.5) - - Amortization of equity component of AFDC on recoverable Seabrook investment (160) (1.0) (160) (.8) (160) (.6) Other 2 - 32 .1 (29) (.1) ------------------------------------------- Federal income tax provision before effect of 0 timing differences $5,493 36.7% $6,648 35.6% $9,190 34.1% 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) (1.0) (151) (.8) (151) (.6) Book depreciation greater than tax depreciation (85) (.6) (69) (.4) (85) (.3) Equity earnings in excess of (less than) dividends 102 .7 (41) (.2) (276) (1.0) State income tax liability deducted for federal income tax purposes 424 2.8 550 2.8 673 2.5 Reversal of excess deferred income taxes 230 1.5 147 .8 167 .6 Amortization of investment tax credits 140 .9 140 .8 350 1.3 Investment tax credits and excess deferred taxes flowed through - - - - 1,485 5.5 Other (392) (2.6) 43 .4 27 .1 ------------------------------------------- Federal income tax provision $5,225 35.0% $6,029 32.2% $7,000 26.0% =========================================== 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 $10.3 million as of December 31, 2001 and $16.4 million as of December 31, 2000. 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 ($16.0 million and $25.3 million as of December 31, 2001 and 2000, 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 ($4.9 million and $8.1 million as of December 31, 2001 and 2000, respectively), and the establishment of deferred tax assets on unamortized investment tax credits ($776,000 and $858,000 as of December 31, 2001 and 2000, respectively). These latter amounts have been recorded in Other Regulatory Liabilities at December 31, 2001 and 2000. 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, 2001 and 2000: 2001 2000 --------------- ----------------- Deferred Income Tax Liabilities: Costs to terminate/restructure purchased power contracts $26,362,744 $ 35,091,730 Excess book over tax basis of electric plant in service 37,117,206 37,156,847 Investment in jointly-owned companies 1,476,037 1,358,081 Other regulatory assets 2,547,116 3,655,033 Other 138,374 120,104 ---------------- -------------- $ 67,641,477 $ 77,381,795 ------------------- ---------------- Deferred Income Tax Assets: Deferred asset sale gain $ 5,901,889 $ 8,776,804 Accrued pension and postretirement benefit costs 5,734,119 4,500,464 Other regulatory liabilities 5,369,662 1,441,734 Other 3,230,331 4,348,443 ------------------ --------------- $ 20,236,001 $ 19,067,445 ------------------ ---------------- Total other accumulated deferred income taxes $ 47,405,476 $ 58,314,350 ============ ============ As a result of the Company's generation asset sale to PP&L Global in 1999 (see Note 11), the Company realized $1.5 million in income tax benefits associated with the recognition of previously unamortized deferred ITC associated with the generation assets sold and the reversal of the excess deferred income taxes associated with these assets. These income tax benefits have been recorded as a component of Other Income in the Consolidated Statements of Income in 1999. NOTE 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. In 2000, 212,786 common stock warrants, which were issued in connection with the PERC purchased power contract restructuring, were exercised at market prices ranging from $14.75 to $24.8125 per share. The Company exercised its option to pay cash to the holders of the warrants instead of actually issuing shares of common stock. These payments amounted to approximately $2.5 million. Since the common shares were not issued, and the Company had recorded the estimated fair value of these warrants when issued in June 1998 as a $248,000 addition to paid-in capital, an adjustment has been made in connection with the cash payments option to reduce paid-in capital by this amount as of December 31, 2000. In 1999, 349,999 common stock warrants, which were issued in connection with the PERC purchased power contract restructuring, were exercised at market prices ranging from $16.0625 to $16.75 per share. The Company exercised its option to pay cash to the holders of the warrants instead of actually issuing shares of common stock. These payments amounted to approximately $3.3 million. Since the common shares were not issued, and the Company had recorded the estimated fair value of these warrants when issued in June 1998 as a $410,000 adjustment to paid-in capital, an adjustment was made in connection with the cash payments option to reduce paid-in capital by this amount as of December 31, 1999. EARNINGS PER SHARE - The following table reconciles basic and diluted earnings per common share assuming all outstanding common stock warrants were converted to common shares (see Note 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 2001 2001 2000 1999 ------------- ------------- ---------- ---------- Earnings applicable to common stock $3,434,519 $4,989,477 $10,836,477 $17,335,205 ----------- ------------- ------------ ----------- 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 - 791,745 990,099 984,200 ------------ --------- ----------- --------- Average common shares outstanding plus assumed warrants converted 7,363,424 8,155,169 8,353,523 8,347,624 ------------- ----------- ----------- ---------- Basic earnings per common share $.47 $.67 $1.47 $2.35 ------------- ------------- ----------- ---------- Diluted earnings per common share $.47 $.61 $1.30 $2.08 ======== ========= ========= ======== NOTE 5. LENDING AGREEMENTS AND MONETIZATION OF POWER SALE CONTRACT On June 29, 1998, the Company entered into an Amended and Restated Revolving Credit and Term Loan Agreement with a new group of lenders that provided a two-year term loan of $45 million and a 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. The terms of the amended credit agreement have been extended to March 31, 2002 and the First Mortgage Bonds have expired. 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 FleetBoston Financial 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 subsequently been extended to March 31, 2002. Both facilities contain certain financial covenants related to the Company's debt ratio, fixed charge coverage, net worth, and limitation on the payment of common dividends. The Company was in compliance with all covenants associated with these agreements during 2001 and 2000. The Company provided power directly to UNITIL Power Corp. (UNITIL), a New Hampshire based electric utility, at significantly above-market rates, with the contract term ending in the year 2003. On March 31, 1998, the Company completed a transaction with lenders and one of its wholly owned subsidiaries, BERI (see below) that provided a loan of approximately $23.3 million in net proceeds secured by the value of the UNITIL contract. As a requirement of the financing, the Company established BERI, a special purpose entity which holds the medium term notes and acts as a conduit between Bangor Hydro and UNITIL for the procurement of power under the terms of the original power sales contract between the two parties. The loan was comprised of $24.8 million in medium term notes, with a term of 53 months. BERI must maintain a capital reserve fund of $1.5 million, funded with proceeds from the loan, which will be used to pay the final installment of principal and interest due in 2002. The assets in the capital reserve fund are held by a third party trustee and invested in money market funds whose investments are limited to commercial paper, corporate notes and bonds, certificates of deposit, municipal bonds, U.S. Agency obligations and repurchase agreements. Interest is payable, at the Company's option, under the agreement at the LIBO rate plus 1.125% or the base rate, which is the higher of (a) the lending bank's reported "base rate" and (b) one-half of one percent (1/2%) above the federal funds effective interest rate. The Company has historically selected the LIBO rate interest option. To provide interest rate protection through the maturity date of the term loan, in April 1998, BERI entered into an interest rate swap agreement with one of the lending banks. The interest rate swap fixed the LIBO interest rate on the medium term notes at 5.72%. As a result of the interest rate swap agreement, BERI incurred additional interest expense in 2001 amounting to approximately $103,000, while in 2000 BERI realized reduced interest expense of approximately $96,000. The agreement also contains certain financial covenants, with which BERI was in compliance during 2001 and 2000. 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. Current maturities of the first mortgage bonds and other long-term debt for the five years subsequent to December 31, 2001, amounting to $121,619,152, are $43,245,904 in 2002, $33,909,192 in 2003, $20,314,371 in 2004, $21,830,717 in 2005, and $2,318,968 in 2006. Certain information related to total short-term borrowings under the Credit Agreements and the lines of credit is as follows: 2001 2000 1999 ------------- ----------- --------------- Total credit available at end of period $40,000,000 $30,000,000 $30,000,000 Unused credit at end of period $32,000,000 $30,000,000 $30,000,000 Borrowings outstanding at end of period $ 8,000,000 - - Effective interest rate (exclusive of fees) on borrowings outstanding at end of period 4.4% -% -% Average daily outstanding borrowings for the period $ 3,031,507 $ - $ 2,802,740 Weighted daily average annual interest rate exclusive of fees) 4.4% -% 6.7% Highest level of borrowings outstanding at any month-end during the period $ 8,000,000 $ - $13,000,000 =========== ============= =========== 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 management employees. There were no employer contributions to the noncontributory pension plan in 2001, 2000 or 1999. The plan's assets are composed of fixed income securities, equity securities and cash equivalents. The following tables detail the funded status of the plan, the amounts recognized in the Company's Consolidated Financial Statements, the components of pension (income) expense for 2001, 2000 and 1999 and the major assumptions used to determine these amounts (includes both the funded and unfunded plans). Total pension expense (income) included the following components: 2001 2000 1999 ------------- ----------- ----------- Service cost-benefits earned during the period $1,387,841 $1,186,910 $1,439,047 Interest cost on projected benefit obligation 3,622,633 3,479,260 3,295,172 Expected return on plan assets (4,260,894) (4,460,416) (4,317,379) Amortization of unrecognized asset and gains (losses) (6,958) (664,911) 252,043 ------------- ------------- ---------- Total pension expense (income) $ 742,622 $ (459,157) $ 668,883 =========== =========== =========== 2001 2000 1999 ---------- --------- --------- Significant assumptions used were- Discount rate* 7.75% / 7.25% 8.0% 6.75% Rate of increase in future compensation levels 4.0% 4.0% 4.0% Expected long-term rate of return on plan assets 9.0% 9.0% 9.0% * In 2001, a 7.75% discount rate was used prior to the acquisition, and 7.25% was subsequent to the acquisition. The following table sets forth the plans' funded status at December 31, 2001 and 2000: 2001 2000 -------------- --------------- Change in Projected Benefit Obligation Balance as of December 31, 2000 and 1999 $ 47,951,796 $45,165,460 Service cost 1,387,841 1,186,910 Interest cost 3,622,633 3,479,260 Benefits paid (2,863,257) (2,900,824) (Gains) and losses 3,283,569 1,020,990 -------------- ------------- Balance as of December 31, 2001 and 2000 $ 53,382,582 $47,951,796 -------------- ------------- Change in Plan Assets Balance as of December 31, 2000 and 1999 $ 48,425,866 $51,834,730 Employer contributions 54,142 40,000 Benefits paid (2,863,257) (2,900,824) Actual return, less expenses (4,185,796) (548,040) -------------- -------------- Balance as of December 31, 2001 and 2000 $ 41,430,955 $48,425,866 -------------- -------------- Funded status $(11,951,627) $ 474,070 Unrecognized net transition asset - (390,175) Unrecognized prior service cost - 2,630,838 Unrecognized gain (1,180,767) (4,756,609) ---------------- ------------- Accrued pension at December 31, 2001 and 2000 $(13,132,394) $ (2,041,876) ============== ============ As a result of purchase accounting, all unrecognized actuarial gains and losses, prior service cost and the net transition asset were eliminated as of October 10, 2001, the merger date 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 $211,670 in 2001 for the period subsequent to the merger. The discount rate and rate of increase in future compensation levels used to determine pension obligations, effective January 1, 2002, are 7.25% and 4%, respectively, and were used to calculate the plans' funded status at December 31, 2001. The accumulated benefit obligation for the unfunded supplemental pension plan with accumulated benefit obligations in excess of plan assets was $2,201,171 and $1,999,298 as of December 31, 2001 and 2000, 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 actuarially determined net periodic postretirement benefit cost for 2001, 2000 and 1999 and the major assumptions used to determine these amounts are shown in the following tables: 2001 2000 1999 ------------- ----------- ---------- Service cost of benefits earned $ 632,590 $ 573,740 $ 583,385 Interest cost on accumulated postretirement benefit obligation 1,848,813 1,716,563 1,518,092 Actual return on plan assets (37,836) (22,002) (9,710) Amortization of unrecognized transition obligation 375,900 501,200 501,200 Other deferrals, net 271,727 280,255 405,834 ------------- ------------ ------------ Net periodic postretirement benefit cost $3,091,194 $3,049,756 $2,998,801 ========== ========== ========== The following table sets forth the benefit plan's funded status at December 31, 2001 and 2000. 2001 2000 -------------- ------------ Change in Accumulated Postretirement Benefit Obligation Balance as of December 31, 2000 and 1999 $ 23,874,192 $ 20,720,833 Service cost 632,590 573,740 Interest cost 1,848,813 1,716,563 Claims paid (979,648) (1,091,334) Gains and losses 2,112,497 1,954,390 --------------- ------------- Balance as of December 31, 2001 and 2000 $ 27,488,444 $ 23,874,192 --------------- ------------- Change in Plan Assets Balance as of December 31, 2000 and 1999 $ 879,734 $ 358,971 Employer contributions 1,250,743 1,727,550 Retiree contributions 44,038 43,428 Claims paid (979,648) (1,091,334) Actual return, less expenses (180,829) (158,881) -------------- ------------- Balance as of December 31, 2001 and 2000 $ 1,014,038 $ 879,734 ------------- ------------- Funded status $(26,474,406) $(22,994,458) Unrecognized net transition obligation - 6,013,600 Unrecognized (gain) loss (48,465) 6,898,628 -------------- ------------- Accrued postretirement benefit cost at December 31, 2001 and 2000 $(26,522,871) $(10,082,230) ============= ============ 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 $282,537 in 2001 for the period subsequent to the merger. The MPUC in 1993 issued a final accounting rule in connection with Statement of Financial Accounting Standards No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" (SFAS 106), which adopted this pronouncement for ratemaking purposes and authorized the Company to defer the excess of the net periodic postretirement benefit cost recognized under SFAS 106 over the pay-as- you-go amount in 1993 through February 28, 1994, and to include such excess as a regulatory asset pending inclusion in the new base rates, effective March 1, 1994. This regulatory asset, which amounted to $705,283 at February 28, 1994, is being recovered, beginning March 1, 1994, over a ten-year period. In 1994 the Company established an irrevocable external Voluntary Employee Benefit Association Trust Fund (VEBA) to fund the payment of postretirement medical and life insurance benefits. Company contributions to the VEBA amounted to approximately $1.3 million in 2001 and $1.7 million in 2000. 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. 2001 2000 1999 ------------ -------- ------- Significant assumptions used were- Discount rate * 7.75% /7.25% 8.0% 6.75% Health care cost trend rate, employees less than age 65- Near-term 7.5% 7.0% 7.5% Long-term 5.0% 5.0% 4.5% Health care cost trend rate, employees greater than age 65- Near-term 7.5% 7.0% 7.5% Long-term 5.0% 5.0% 4.5% 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. The discount rate used to determine postretirement benefit obligations, effective January 1, 2002, and the Plan's funded status at December 31, 2001, was 7.25%. 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% Decreas ------------- ------------ Effect on total of service and interest cost components $ 451,011 $ (355,321) Effect on postretirement benefit obligation 4,580,571 (3,658,701) In 1999 the Company incurred $469,000 and $175,587 in special termination benefits associated with enhanced pension and postretirement medical benefits, respectively, provided to employees who were displaced due to the asset sale to PP&L Global (see Note 11). The state of Maine electric utility restructuring legislation allowed utilities to recover the costs of providing such benefits to the workers displaced due to the sale of the Company's generation assets, and consequently, the special termination benefits expense of $644,587 was deferred and is recorded as a regulatory asset at December 31, 1999. Recovery of this regulatory asset began starting March 1, 2000 over a three-year period as specified in the Company's 2000 rate order from the MPUC. The estimates of the Company's accrued pension and postretirement benefit costs involve the utilization of significant assumptions. Changes in any one of these assumptions could impact the liabilities in the near term. The Company also provides a defined contribution 401(k) savings plan for substantially all of its employees. The Company's matching of employee voluntary contributions amounted to approximately $363,000 in 2001, $370,000 in 2000 and $331,000 in 1999. 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 2001 to 2008, excluding funds already collected, is $596 million (undiscounted). The Company's share of the estimated cost at December 31, 2001 is approximately $37.3 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 11) allowing the Company future recovery of nuclear decommissioning expenses related to Maine Yankee, as well as the Company being allowed a recovery mechanism in its February 2000 rate order for Maine Yankee non-decommissioning plant closure costs. Accumulated decommissioning funds at December 31, 2001 had an adjusted market value of $157.1 million of which the Company's share was approximately $11 million. MEPCO - The Company owns 14.2% of the common stock of MEPCO. MEPCO owns and operates electric transmission facilities from Wiscasset, Maine, to the Maine-New Brunswick border. Information relating to the operations and financial position of Maine Yankee and MEPCO appears later in Note 6. In connection with the Company's generation asset sale in May 1999 (see Note 11), the Company sold certain of its rights to MEPCO transmission capacity. NEPOOL/Hydro-Quebec Project - The Company is a 1.6% participant in the NEPOOL/Hydro-Quebec Phase 1 project (Phase 1), a 690 MW DC intertie between the New England utilities and Hydro-Quebec constructed by a subsidiary of another New England utility at a cost of about $140 million. The participants receive their respective share of savings from energy transactions with Hydro-Quebec, and are obliged to pay for their respective shares of the costs of ownership and operation whether or not any savings are realized. The Company is also a 1.5% participant in the NEPOOL/Hydro-Quebec Phase 2 project (Phase 2), which involves an increase to the capacity of the Phase 1 intertie to 2,000 MW. As in the Phase 1 project, the Company receives a share of the anticipated energy cost savings derived from purchases from Hydro-Quebec and capacity benefits provided by the intertie and is required to pay its share of the costs of ownership and operation whether or not any savings are obtained. In connection with the generation asset sale in May 1999, the Company sold its rights as a participant in the regional utilities agreement with Hydro-Quebec (see Note 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 $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, 2001 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. 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. Summary Financial Information for Maine Yankee and MEPCO is as follows (dollars in thousands): ---------------------------------------------------------------------------- Maine Yankee MEPCO ---------------------------------------------------------------------------- 2001 2000 1999 2001 2000 1999 ------ -------- ------ ------ ------- ------- Operations: As reported by investee- Operating revenue $ 61,994 $ 43,813 $ 69,439 $ 4,514 $ 4,029 $ 2,936 -------- --------- --------- --------- ------- ------- Amortization/depreciation and decommissioning collections $ 47,586 $ 47,611 $ 55,286 $ 274 $ 319 $ 326 Interest and preferred dividends 10,987 14,829 14,079 40 55 72 Other (income) expenses, net (950) (23,267) (4,789) 3,008 2,274 (771) ----------- ----------- ---------- ------- -------- ------- Operating expenses $ 57,623 $ 39,173 $ 64,576 $ 3,322 $ 2,648 $ (373) ----------- --------- ---------- -------- -------- ------ Earnings applicable to common stock $ 4,371 $ 4,640 $ 4,86 $ 1,192 $ 1,381 $3,309 ========== ======== ======== ======= ======= ====== Amounts reported by the Company- Purchased power costs $ 5,198 $ 5,013 $ 4,368 $ - $ - $ - Equity in net income (310) (320) (83) ( 19 (157) (199) ----------- --------------------- ------- -------- ----- Net purchased power expense $ 4,888 $ 4,693 $ 4,285 $ (195) $ (157) $ (199) ========= ======== ======== ====== ====== ===== Financial Position: As reported by investee- Plant in service $ 685 $ 685 $ 685 $25,860 $25,593 $23,493 Accumulated depreciation - - - (23,231) (23,075) (23,015) Other assets and deferred charges 801,433 914,412 1,049,287 4,241 3,355 7,589 ---------- --------- ----------- --------- ------- ------ Total assets $ 802,118 $915,097 $1,049,972 $ 6,870 $5,873 $8,067 Less- Preferred stock - 15,000 15,000 - - - Long-term debt 31,200 40,800 54,000 - - - Other liabilities and deferred credits 707,643 788,703 905,994 770 863 4,339 --------- --------- ----------- --------- -------- ------ Net assets $ 63,275 $ 70,594 $ 74,978 $6,100 $5,010 $ 3,728 ========= ======== ========== ====== ====== ======= Company's reported equity- Equity in net assets $ 4,429 $ 4,942 $ 5,248 $ 866 $ 711 $ 529 Adjust Company's estimated to actual (7) 8 19 (12) (38) 1 ------------ ----------- ------------ -------- --------- ---- Equity in net assets as reported $ 4,422 $ 4,950 $ 5,267 $ 854 $ 673 $ 530 =========== ======== ========== ======== ====== ====== Power Supply Commitments - As of the end of 2001, the Company had contracts with six in-dependent, non-utility power producers known as "small power production facilities." The West Enfield Project, described below, is one such facility. There are four other relatively small hydroelectric facilities, and a 20 MW facility fueled by municipal solid waste (see PERC discussion below). The cost of power from the small power production facilities is more than the Company would incur from other sources if it were not obligated under these contracts, and, in the case of the solid waste plant, substantially more. The prices were negotiated at a time when oil prices were much higher than at present, and when forecasts for the costs of the Company's long-term power supply were higher than current forecasts. West Enfield Project - In 1986, the Company entered into a joint venture with a development subsidiary of Pacific Lighting Corporation for the purpose of financing and constructing the redevelopment of an old 3.8 MW hydroelectric plant which the Company owned on the Penobscot River in Enfield and Howland, Maine, into a 13 MW facility for the purpose of operating the facility once it was completed. Commercial operation of the redeveloped project began in April 1988. PHC was formed to own the Company's 50% interest in the joint venture, Bangor- Pacific. Bangor-Pacific financed the cost of the redevelopment through the issuance in a privately placed transaction of $40 million of fixed rate term notes and a commitment for up to $5 million of floating rate notes. The notes are secured by a mortgage on the project and a security interest in a 50-year purchased power contract, and the revenues expected thereunder, between the Company and Bangor-Pacific. In late July 1999, in connection with the generation asset sale, the Company sold PHC to PP&L and received $10 million in proceeds. The sale resulted in a gain of approximately $5.2 million, of which $4.7 million was deferred as part of the deferred asset sale gain (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 (recorded as Other Income in the Consolidated Statements of Income for the year ending December 31, 1999). 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. The Company's purchased power expense, net of revenues from the resale of power to another utility, under this contract was approximately $15.1 million in 2001, is projected to be approximately $16 million in 2002, $20 million in 2003, and to increase over the remainder of the contract up to $28 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 2001, 2000 and 1999 the Company realized $3.5 million, $3.5 million and $2.9 million, respectively, in savings associated with its share of PERC net revenues. The Company expects to realize approximately $3.6 million annually in such savings through the term of the PERC contract. 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 is used to serve a portion of the standard offer service customer load. The Company's purchased power expense under this contract was approximately $21 million in 2001, and is estimated to be approximately $39.4 million in 2002, $24.1 million in 2003 and $3.5 million in 2004. See Note 11 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 $4.4 million in revenues from the resale of power under this contract in 2001. 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 will commence March 1, 2002, and will continue for a period of three years. The revenues to be realized under this contract, as well as the final two months in 2002 of the Chapter 307 sales related contract discussed above, are estimated to be approximately $36.9 million in 2002, $25.6 million in 2003, $11 million 2004 and $2 million in 2005. Rate Recovery - In connection with the Company's stranded cost rate proceeding with the MPUC, Maine Yankee decommissioning and other closure costs, obligations associated with Hydro-Quebec, the cost of energy and capacity associated with the power purchase contracts and revenues associated with the sales agreements discussed in this note are being recovered from customers as stranded costs. 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 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. The cost of the buyback was financed entirely by new debt instruments, thereby significantly increasing the Company's indebtedness (see Note 5). 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 is making additional quarterly payments, starting in October 1998, of $250,000 for four years totaling $4 million. These amounts are recorded as regulatory assets when the payments are 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, 2001, the Company has deferred, as a regulatory asset, approximately $27.6 million in costs associated with the PERC contract restructuring. Effective with the implementation of new rates on March 1, 2000, the Company began recovering the full amount of deferred PERC restructuring costs, including an estimate of the future value of warrants to be exercised and the additional $250,000 quarterly payments discussed above, amounting to an annual amortization of $1.6 million per year. The Company had been involved in 2001 and early 2002 in a regulatory proceeding at the MPUC to reset stranded cost electric rates starting March 1, 2002. Effective with the new electric rates set by the MPUC, the annual amortization expense associated with the recovery of the PERC restructuring costs was adjusted to $1.7 million annually. 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. NOTE 9. FAIR VALUE OF FINANCIAL INSTRUMENTS The following represents the estimated fair value at December 31, 2001 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 $884,617 approximates fair value. Funds held by trustees, associated with the BERI capital reserve fund and miscellaneous special deposits-Money market funds and U.S. Treasury Bills: the carrying amount of $2,189,638 approximates fair value. The fair values of other financial instruments at December 31, 2001 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 $22,409 First Mortgage Bonds 85,000 98,876 FAME Revenue Notes 71,500 75,909 Medium Term Notes-LIBO rate plus 1.125% 5,460 5,460 Municipal Review Committee Note Payable 13,234 12,147 Short-term debt 8,000 8,000 NOTE 10. UNAUDITED QUARTERLY FINANCIAL DATA Unaudited quarterly financial data pertaining to the results of operations are shown below (Dollars in thousands except for per share amounts): Quarter Ended ------------------------------------------- Mar. 31 June 30 Sept. 30 Dec. 31 ------------------------------------------- 2001 ------ Electric Operating Revenue $ 56,204 $ 54,003 $ 55,570 $ 51,803 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 $ .6 $ (.04) $ 41 $ .16 ======== ========= ======= ======== 2000 ------ Electric Operating Revenue $ 50,121 $ 48,563 $ 58,641 $ 55,012 Operating Income 8,307 4,652 6,535 6,930 Net Income 3,937 1,339 3,940 1,885 Basic Earnings Per Share of Common Stock $ .53 $ .17 $ .53 $ .25 ========= ========= ======= ======== 1999 ------ Electric Operating Revenue $ 50,222 $ 47,299 $ 51,452 $ 49,022 Operating Income 9,886 8,502 9,331 8,439 Net Income 4,212 3,452 5,037 5,580 Basic Earnings Per Share of Common Stock $ .53 $ .43 $ .65 $ .74 ========= ========== ========= ======= NOTE 11. INDUSTRY RESTRUCTURING AND RATE REGULATION INDUSTRY RESTRUCTURING - In connection with the state of Maine's electric industry restructuring law, effective March 1, 2000, consumers of electricity had the right to purchase generation services directly from competitive electricity suppliers. In February 2000, and in connection with the implementation of the restructuring law, the Company received a final rate order from the MPUC setting its transmission and distribution and stranded cost rates effective March 1, 2000. The Company's total annual revenue requirement as set in the rate proceedings, including $40 million associated with stranded cost recovery, amounted to $103.2 million. The stranded cost recovery includes the decommissioning and other plant closure expenses for Maine Yankee. There were no write-offs of previously deferred costs based on the final rate order. In Maine, stranded costs are treated in the same manner as most other costs and may be included in calculations for prospective rate changes. Absent any rate proceedings, however, in 2003 and every three years thereafter until the stranded costs are recovered, the MPUC shall review and reevaluate the stranded cost recovery. Customers reducing or eliminating their consumption of electricity by switching to self- generation, conversion to alternative fuels or utilizing demand-side management measures cannot be assessed exit or entry fees. The restructuring law also provided for a standard-offer service being available for all customers who did not choose to purchase energy from a competitive supplier starting March 1, 2000. As a result of the bids from competitive energy suppliers to provide energy under the standard- offer service being higher than anticipated in both 2000 and 2001, and as ordered by the MPUC, the Company assumed the responsibility of being the standard-offer service provider starting March 1, 2000 for the period ending February 28, 2002. 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 has been 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 have exceeded the costs of providing the standard offer service, and consequently, the Company has recorded a regulatory liability of approximately $5.7 million, including carrying costs, as of December 31, 2001 (which is included in Other regulatory liabilities on the Consolidated Balance Sheets). 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. 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. 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 2001 and 2000 has been modified to reflect the separate presentation of standard- offer service revenues and purchased power expenses. CURRENT RATE FILINGS - On October 12, 2001, the Company filed a proposal with the MPUC for an alternative rate plan (ARP) that would govern its rates for distribution service over a four year period. Such a filing was required by the MPUC as a condition of its approval of the Company's acquisition by Emera. In addition to distribution service rates, the Company's ARP proposal included proposed incentives to improve the efficiency and the service quality of power delivery services to Bangor Hydro's customers. The Company's proposal included an initial increase in distribution rates of approximately $3.4 million, with additional annual adjustments during the term of the ARP at a rate below that of inflation. However, as a result of a scheduled reduction in standard offer service, the combined impact of rate changes for most customers would be a reduction of approximately 10% (or about $8 per month for a typical residential customer) during 2002. There is no legal deadline for the MPUC to complete such a proceeding. On October 18, 2001, the Company filed a notice of its intent to file a request for a general increase in distribution rates of approximately $6.4 million. Under Maine law, utilities are required to provide a minimum of sixty days notice of their intent to file such a request. This filing was made as an alternative to the Company's ARP filing, although it does not preclude simultaneous or subsequent implementation of an ARP. Once filed, the MPUC must process such a request within nine months. In November 2001, the MPUC Hearing Examiner administering the ARP proceeding suspended that proceeding pending the Company's filing of a request for a general increase in distribution rates. On January 11, 2002, the MPUC requested comments on a Draft Order that would initiate a management investigation of the Company, as permitted by Maine law, as part of its investigation of the Company's anticipated request for a general increase in distribution rates. On January 17, 2002, in response to this Draft Order, the Company offered to defer filing its request for a general increase in distribution rates and asked the MPUC to defer initiating the management investigation to permit the Company and interested parties a three month period to pursue a settlement of the ARP proceeding with the expectation that such a settlement would also terminate the proposed request for a general increase in rates and the management investigation. At a deliberative session held on January 22, 2002, the MPUC deferred issuing an order initiating a management investigation for 90 days to allow the parties to pursue a settlement of these related rate matters. Management cannot predict the outcome of the regulatory proceedings associated with the Company's rate proposals with the MPUC. 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 will begin returning this amount to customers starting March 1, 2002 in connection with a change in its stranded cost rates. 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. The regulatory asset is included as a component of Other Regulatory Assets in the Consolidated Balance Sheets at December 31, 2001 and 2000. REGULATORY ASSETS AND MEETING THE REQUIREMENTS OF SFAS 71 - The Company is subject to the provisions of Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS 71). SFAS 71 allows the establishment of regulatory assets for costs accumulated for certain items other than the usual and customary capital assets, and allows the deferral of the income statement impact of those costs if they are expected to be recovered in future rates. As of December 31, 2001, the Company has regulatory assets, net of regulatory liabilities, of approximately $246 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 12. CONSTRUCTION OF FACILITIES FOR CASCO BAY ENERGY The Company entered into an agreement with Casco Bay whereby the Company agreed to construct various transmission facilities required to allow a generating facility being constructed in Veazie, Maine to interconnect with the Company's electrical system and deliver its output to the New England Power Pool Transmission Facility (PTF) grid. Under this agreement, Casco Bay agreed to advance funds necessary to pay for such construction. Pursuant to a FERC order approving an amendment to the NEPOOL Agreement, approximately 50% of the construction funds advanced 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. At the end of 2001, the Company had recorded approximately $4 million for PTF facilities and a corresponding Long-term Payable of $3.7 million. These amounts are included on the Consolidated Balance Sheets as components of Electric Plant in Service and Other Long-term Liabilities, respectively. NOTE 13. 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, 2001 represents a liability of approximately $74.0 million. 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. INTEREST RATE SWAP - As discussed in Note 5, in connection with the $24.8 million in BERI medium term notes, BERI entered into an interest rate swap arrangement with a major financial institution to provide interest rate protection through the maturity date of the term loan. The interest rate swap fixed the LIBO interest rate on the medium term notes at 5.72%. BERI will be reimbursed for incremental interest expense incurred in excess of the 5.72% and incurs additional expense for incremental interest expense below 5.72%. Market risk is the potential loss arising from adverse changes in interest rates. The fair value of the interest rate swap at December 31, 2001 is ($79,862) and represents the estimated payment that would be paid to terminate the agreement. NOTE 14. 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, 2001, the liability recorded by the Company for its estimated environmental remediation costs amounted to approximately $435,000. The Company's actual future environmental remediation costs may be different as additional factors become known. 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, 2001, and for the year 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. The financial statements of Bangor Hydro- Electric Company and financial statement schedules for the years ended December 31, 2000 and 1999 were audited by other auditors whose report dated February 2, 2001 expressed an unqualified opinion on those statements and schedules. 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 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, 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 13 and Note 1, respectively, of the consolidated financial statements, in 2001 the Company changed its method of accounting for derivative financial instruments and for goodwill. February 1, 2002 /s/ Ernst & Young LLP --------------------- Ernst & Young LLP is a member of Ernst & Young International, Ltd. ITEM 7A QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK See Item 7, "Management's Discussion and Analysis of Results of Operations and Financial Condition -Contingencies and Disclosures About Market Risk", and Item 8, Note 13, "Derivative Financial Instruments" for a discussion of certain derivative financial instruments held by the Company. 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's report on the financial statements for 1999 and 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 1999 and 2000 fiscal years and during 2001 prior to the dismissal of PricewaterhouseCoopers, 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. For a full disclosure regarding this change in accountants, please refer to the Company's Report on Form 8-K dated for events occurring on November 21, 2001 which is incorporated herein by reference. PART III ITEM 10 DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT See Item 4 above, and see the information under "Election of Directors" in the Company's definitive proxy statement for the annual meeting of stockholders to be held on April 24, 2002, which information is incorporated herein by reference. ITEM 11 EXECUTIVE COMPENSATION See the information under "Executive Compensation" in the Company's definitive proxy statement for the annual meeting of stockholders to be held on April 24, 2002, which information is incorporated herein by reference. ITEM 12 SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT (a) Security Ownership of Certain Beneficial Owners See the Company's definitive proxy statement for the annual meeting of stockholders to be held on April 24, 2002, which information is incorporated herein by reference. (b) Security Ownership of Management See the Company's definitive proxy statement for the annual meeting of stockholders to be held on April 24, 2002, which information is incorporated herein by reference. (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 See the information under "Compensation Committee Interlocks and Insider Participation" in the Company's definitive proxy statement for the annual meeting of stockholders to be held on April 24, 2002, which information is incorporated herein by reference. PART IV ITEM 14 EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (a) Consolidated Financial Statements of the Company covered by the Report of the of Independent Auditors (See Item 8): Consolidated Statements of Income for the Years Ended December 31, 2001, 2000 and 1999 Consolidated Balance Sheets - December 31, 2001 and 2000 Consolidated Statements of Capitalization - December 31, 2001 and 2000 Consolidated Statements of Cash Flows for the Years Ended December 31, 2001, 2000 and 1999 Consolidated Statements of Common Stock Investment for the Years ended December 31, 2001, 2000 and 1999 Notes to Consolidated Financial Statements Report of Independent Accountants (b) Schedules Report of Independent Accountants Schedule VIII - Reserves for Doubtful Accounts All other schedules are omitted as the required information is inapplicable or the information is presented in the Company's consolidated financial statements or related notes. (c) Exhibits See Exhibit Index. (d) Reports on Form 8-K A current report on Form 8-K for the Fourth Quarter of 2001 was filed regarding the Company's Change in Accountants effective November 21, 2001. 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/ Carroll R. Lee ------------------------ By: Carroll R. Lee President and 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/ Elizabeth A. MacDonald -------------------------- Robert S. Briggs Elizabeth A. MacDonald Director Director /s/ David McD.Mann ------------------ Jane J. Bush David McD. Mann Director Chairman of the Board /s/ Christopher G. Huskilson /s/ Richard J. Smith ---------------------------- -------------------- Christopher G. Huskilson Richard J. Smith Vice Chairman, Director Director /s/ Norman A. Ledwin /s/ Ronald E. Smith -------------------- ------------------- Norman A. Ledwin Ronald E. Smith Director Director /s/ Carroll R. Lee /s/ Frederick S. Samp ------------------ --------------------- Carroll R. Lee Frederick S. Samp Director, President Vice President - Finance & Law and Chief Operating (Chief Financial Officer) Officer David R. Black -------------- David R. Black Controller (Chief Accounting Officer) Each of the above signatures is affixed as of February 28, 2002. SCHEDULE VIII RESERVE FOR DOUBTFUL ACCOUNTS -----------------------------

EXHIBIT INDEX EXHIBITS INCLUDED HEREWITH 3. Articles of Incorporation and By-Laws 3(a) Articles of Merger dated October 10, 2001 3(b) Articles of Amendment dated January 8, 2002, reducing the minimum number of directors from 9 to 3 3(c) By-Laws of the Company, Amended and Restated as of December 19, 2001 10. Material Contracts 10(a) Line Agreement dated as of June 29, 2001 Agreement By and Among the Company and Fleet National Bank 10(b) Promissory Note dated as of June 29, 2001 Agreement By and Among the Company and Fleet National Bank 10(a) 10(c) Promissory Note dated as of October 10, 2001 from the Company to the Municipal Review Committee, Inc. 10(d) Amendment No. 3 entered into as of 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(e) Amendment No. 2 dated as of December 31, 2001 to Promissory Note By and Among the Company and Fleet National Ban 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 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 of 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.

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