ITEM 3 LEGAL PROCEEDINGS - ------ ----------------- See "Financial Difficulties of Significant Customer" above and Note 9 to the Company's Financial Statements, which are incorporated herein by reference, for a discussion of bankruptcy proceedings relating to a large customer of the Company.
See Note 9 to the Company's Financial Statements for a discussion of potential liabilities under the Comprehensive Environmental Response, Compensation, and Liability Act.
ITEM 4
ITEM 4 SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS - ------ --------------------------------------------------- Not applicable.
PART II - ------- ITEM 5
ITEM 5 MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS - ------ ---------------------------------------------------
As of December 31, 1993, there were 7,511 holders of record of the Company's common stock.
The Company's common stock is traded on the New York Stock Exchange ("NYSE") under the symbol "BGR".
The following table sets forth the high and low prices for the Common Stock as reported by the NYSE. The prices shown do not include commissions. Dividends are declared quarterly.
DIVIDENDS DECLARED FISCAL PERIOD HIGH LOW PER SHARE - ------------- ------ ------- --------- - ---- First Quarter................ $18 1/8 $17 1/4 $.33 Second Quarter............... 18 1/4 17 1/4 .33 Third Quarter................ 19 7/8 17 3/4 .33 Fourth Quarter............... 20 1/4 18 1/4 .33
- ---- First Quarter................ $24 1/8 $17 7/8 $.33 Second Quarter............... 23 5/8 19 5/8 .33 Third Quarter................ 23 1/8 20 7/8 .33 Fourth Quarter............... 21 3/8 18 1/8 .33
- ---- First Quarter (through March 21, 1994)... $19 $16 3/4 $.33
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
BASIS OF CONSOLIDATION The Consolidated Financial Statements of Bangor Hydro-Electric Company (the "Company") include its wholly owned subsidiaries, Penobscot Hydro Co., Inc. ("PHC"), and Bangor Var Co., Inc. ("BVC"). The operations of PHC consist solely of a 50% interest in Bangor-Pacific Hydro Associates ("BPHA"), the owner and operator of the redeveloped West Enfield hydroelectric station. PHC accounts for its investment in BPHA under the equity method. BVC was incorporated in 1990 to own the Company's 50% interest in a partnership which owns certain facilities used in the Hydro-Quebec Phase II transmission project in which the Company is a participant. BVC accounts for its investment in the partnership under the equity method. All significant intercompany balances and transactions have been eliminated. The accounts of the Company are maintained in accordance with the Uniform System of Accounts prescribed by the regulatory bodies having jurisdiction.
EQUITY METHOD OF ACCOUNTING The Company accounts for its investments in the common stock of Maine Yankee Atomic Power Company ("Maine Yankee") and Maine Electric Power Company, Inc. ("MEPCO") under the equity method of accounting, and records its proportionate share of the net earnings of these companies (substantially all of these earnings are paid out in dividends) as a reduction of purchased power capacity costs. See Note 7 for additional information with respect to these investments.
ELECTRIC OPERATING REVENUE Electric Operating Revenue consists primarily of amounts charged for electricity delivered to customers during the period. The Company records unbilled revenue, based on estimates of electric service rendered and not billed at the end of an accounting period, in order to match revenue with related costs. The Federal Energy Regulatory Commission ("FERC") requires utilities to reclassify to operating revenue sales transactions related to power pool and interconnection agreements and resales of purchased power previously netted within fuel and purchased power expense. The reclassification increased total operating fuel revenue by $15.3 million in 1993, $13.8 million in 1992 and $15.7 million in 1991, while increasing fuel and purchased power expense by the same amounts.
DEFERRED FUEL AND PURCHASED POWER CAPACITY ACCOUNTING The Company utilizes deferred fuel accounting. Under this accounting method, retail fuel costs are expensed when recovered through rates and recognized as revenue. Retail fuel costs not yet expensed are classified on the Consolidated Balance Sheets ("Balance Sheets") as deferred fuel costs. The fuel cost adjustment rate in- cludes a factor calculated to reimburse the Company or its customers, as appropriate, for the carrying cost of funds used to finance under- or over-collected fuel costs, respectively.
Under the Maine Public Utilities Commission ("MPUC") fuel cost adjustment regulations effective through December 31, 1993, the Company is allowed to recover its fuel costs on a current basis. The fuel charge is based on the Company's projected cost of fuel for a twelve-month period. Under- or over-collections resulting from differences between estimated and actual fuel costs for a period are included in the computation of the estimated fuel costs of the succeeding fuel adjustment period. Commencing January 1, 1988, in accordance with an agreement approved by the MPUC, the Company began to phase-in increased fuel costs (primarily the cost of power purchased from small power producers see Note 7). The fuel rates are being designed so that all fuel costs incurred during that period will be billed in 1994.
Prior to 1992, the MPUC allowed the Company to defer for future collection from, or payback to, customers the difference between actual purchased power costs incurred and those costs billed. As with fuel, the deferred purchased power capacity amounts were, for these years, considered when setting the fuel cost adjustment rate for the forthcoming year. The portion of purchased power capacity costs which is included in fuel revenue is classified as purchased power capacity expense in the Statements of Income. Effective November 15, 1992, the collection of the remaining balance of deferred purchased power costs is being recorded on the Statements of Income as fuel expense. The base rates, which became effective on January 1, 1992, excluded all purchased power capacity costs from this deferral process.
DEPRECIATION OF ELECTRIC PLANT AND MAINTENANCE POLICY Depreciation of electric plant is provided using the straight-line method at rates designed to allocate the original cost of the properties over their estimated service lives. The composite depreciation rate, expressed as a percentage of average depreciable plant in service, and considering the amortization of the over-accrued depreciation which is discussed below, was approximately 2.1% in 1993, 1992 and 1991.
A study conducted in 1989 by an independent firm determined that, as a group, the actual lives of the Company's property, plant and equipment are longer than the lives represented by the depreciation rates that the Company had been using to compute its depreciation expense for accounting purposes. In addition, the study also determined that the reserve for depreciation was over-accumulated. The agreement on base rates which became effective on October 1, 1990, contained a provision to amortize the remaining balance of the over-accumulated reserve for depreciation account ($11.4 million at October 1) over a six-year period and adopted the longer depreciable lives as determined by the aforementioned study.
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 reserve for depreciation.
Depreciation, local property taxes and other taxes not based on income, which were charged to operating expenses, are stated separately in the Statements of Income. Rents and advertising costs are not significant. No royalty or research and development expenses were incurred.
Maintenance expense was $6.5 million in 1993, $5.6 million in 1992 and $6.4 million in 1991.
EQUITY RESERVE FOR LICENSED HYDRO PROJECTS The FERC requires that a reserve be maintained equal to one-half of the earnings in excess of a prescribed rate of return on the Company's investment in licensed hydro property, beginning with the twenty-first year of the project operation under license. The required reserve for licensed hydro projects is classified in retained earnings and has a balance of $584,942 at December 31, 1993.
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 and is capitalized 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. In addition, carrying costs on certain regulatory assets are also capitalized and included in AFDC in the Statements of Income. The average AFDC (and carrying cost) rates computed by the Company were 10.0% in 1993, 10.6% for 1991 and 11.1% 1991.
CASH AND CASH EQUIVALENTS The Company considers all highly liquid debt instruments purchased with an original maturity of three months or less to be temporary cash investments.
RECLASSIFICATIONS Prior year amounts have been reclassified to conform with the presentation used in the 1993 Consolidated Financial Statements.
SIGNIFICANT CUSTOMER The Company has one industrial customer, LCP Chemicals ("LCP"), that accounted for 4.8%, 4.9% and 5.4% of total revenue (excluding AR 14 reclassifications) in 1993, 1992 and 1991, respectively. In 1988, with approval of the MPUC, the Company entered into an agreement with this customer by which its base rates for services were reduced and a "revenue-sharing" plan was instituted. Under the revenue-sharing plan, the amounts billed to this customer were adjusted up or down to reflect changes in the customer's per unit product price and electricity costs. The revenue-sharing rate continued for part of 1992 when it was replaced by a new rate that had a higher contribution to base revenue. In June 1993, LCP returned to the revenue-sharing rate. The Company recorded, as other income, approximately $513,000 in 1993, 206,000 in 1992, and $1.8 million in 1991 pursuant to the revenue-sharing rate.
NOTE 2. INCOME TAXES
The Company adopted Financial Accounting Standard Board Statement No. 109 "Accounting for Income Taxes" ("FAS 109") effective January 1, 1993. FAS 109 required a change in the accounting for income taxes from the deferred method to an asset and liability approach, which requires the recognition of deferred tax liabilities and assets for the future tax effects of temporary differences between the tax basis and carrying amounts of assets and liabilites. In accordance with FAS 109, the Company recorded net additional deferred income tax liabilities of approximately $23.1 million as of December 31, 1993. These additional deferred income tax liabilities have resulted from the accrual of deferred taxes on temporary differences on which deferred taxes had not been previously accrued ($32.5 million), offset by the effect of the 1987 change to lower income tax rates (reduced by the 1% increase in the federal income tax rate in 1993) that will be refunded to customers over time ($8.1 million) and the establishment of deferred tax assets on unamortized investment tax credits ($1.3 million). These latter amounts have been recorded as deferred regulatory liabilities at December 31, 1993. The accrual of the additional amount of deferred tax liabilities has been offset by a regulatory asset which represents the customers' future payment of these income taxes when the taxes are, in fact, expensed. As a result of this accounting, the consolidated statement of income for the year ended December 31, 1993 is 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, 1993:
Deferred income tax liabilities:
Excess book over tax basis of electric plant in service $43,023,222 Costs to terminate purchased power contract 4,553,166 Deferred FERC licensing costs 3,431,075 Deferred fuel, purchased power and interest costs 1,616,491 Deferred demand-side management program costs 1,055,030 Prepaid pension costs 1,028,179 Investment in jointly-owned companies 790,881 Other 2,434,532 									 						 ----------- 						 $57,932,576 						 ----------- Deferred income tax assets:
Deferred taxes provided on alternative minimum tax ($3,175,718) Provision for Basin Mills investment (3,137,895) Deferred state income tax benefit (1,561,137) Unamortized investment tax credit (1,286,156) Reserve for bad debts (797,696) Other (973,195) 						 ------------- 						 ($10,931,797) 						 ------------- Total other accumulated deferred income taxes $ 47,000,779 					 =============
The individual components of federal and state income taxes reflected in the Consolidated Statements of Income for 1993, 1992 and 1991 are as stated in the table below.
				 Year Ended December 31, 			 ---------------------------------------- 				 1993 1992 1991 			 ---------------------------------------- Current: Federal $ - $6,274,554 $1,064,754 State - 2,739,089 485,586 			 ----------------------------------------- 			 $ - $9,013,643 $1,550,340 			 -----------------------------------------
Deferred - Short-Term: Federal $ 114,674 $4,330,124 (1,803,480) State 68,216 213,745 (93,018) 			 ------------------------------------------ 			 $ 182,890 $4,543,869 (1,896,498) 			 ------------------------------------------
Deferred - Long-Term: Federal - Other $ 2,512,026 $(5,741,329) $4,360,251 State - Other (21,507) (1,806,238) 418,052 Federal - Seabrook (341,917) (653,060) (705,036) State - Seabrook (72,730) (139,336) (150,297) 			 ----------------------------------------- 			 $2,075,872 $(8,339,963) $3,922,970 			 ----------------------------------------- Investment Tax Credits, Net $ (178,176) $ 672,798 $ 214,345 			 ----------------------------------------- Total Provision $2,080,586 $ 5,890,347 $3,791,157 Allocated to Other Income 2,682,359 (288,575) (940,793) 			 ----------------------------------------- Charged to Operating Expense $4,762,945 $ 5,601,772 $2,850,364 			 =========================================
The table below reconciles an income tax provision, calculated by multiplying income before federal income taxes (as reported on the Statements of Income) by the statutory federal income tax rate to the federal income tax expense reported on the Statements of Income. The difference is represented by the temporary differences for which deferred taxes are not provided.
	 				 1993 1992 1991 					 ---- ---- ---- 					Amount % Amount % Amount % 				 ------------------------------------------- 						(Dollars in Thousands) Federal income tax provisions at statutory rate $2,522 34% $5,489 34% $4,077 34% Less (Plus) temporary reductions in tax expense resulting from statutory exclusions from taxable income: Dividend received deduction related to earnings of associated companies 133 2 142 1 179 2 Equity component of AFDC 496 6 306 2 277 2 Amortization of equity component of AFDC on recoverable Seabrook investment (155) (2) (187) (2) (191) (2) Other (24) - 4 - (34) - 					------ ---- ------ ---- ------ ----
Federal income tax provision before effect of temporary differences $2,072 28% $5,224 33% $3,846 32% Less (Plus) timing differences that are flowed through for ratemaking and accounting purposes: Amortization of debt component of AFDC and capitalized overheads on recoverable Seabrook investment (146) (2)% (193) (2)% (196) (2)% Book depreciation greater than tax depreciation on assets acquired before 1971 (292) (4) (293) (2) - - State income tax liability deducted for federal income tax purposes 116 2 467 4 351 3 Reversal of excess deferred income taxes 34 - 221 2 284 3 Life insurance flow-through in prior years - - - - 178 2 Other 253 4 139 1 98 1 				 ------- ---- ------ ---- ------ --- Federal income tax provision $2,107 28% $4,883 30% $3,131 25% 				 ======= ==== ====== ==== ====== ===
The differences between the federal and state income tax expense reported on the Consolidated Statements of Income, and the federal and state income tax liability as reflected on the Company's tax returns, are caused by temporary differences on which deferred taxes are provided and recovered through rates. The table below shows the components of deferred tax expense as reported in the Statements of Income.
				 1993 1992 1991 				 ----------- ----------- ------------
Costs to terminate purchased power contract $4,553,166 $ - $ - Provision for Basin Mills (3,137,895) - - Seabrook Nuclear Project (414,647) (792,396) (855,333) Tax depreciation in excess of book depreciation 852,187 3,787,047 5,958,182 Deferred fuel and purchased power costs 163,665 (8,443,906) (2,843,764) State taxes provided for rate- making purposes but not paid (124,217) 146,702 (932,197) Deferred taxes provided on the AMT - 268,254 (551,503) Deferred interest costs 59,214 (209,149) (52,476) Costs of removal 84,203 227,649 204,179 Deferred demand-side management costs 97,672 284,297 198,677 FERC licensing costs 277,574 835,487 912,903 Other (152,160) 99,921 (12,196) 				 ----------- ------------ ----------- Total deferred income tax expense (benefit) $2,258,762 $(3,796,094) $2,026,472 				 =========== ============ ===========
Under the federal income tax laws, the Company received investment tax credits on qualified property additions through 1986. Investment tax credits utilized were deferred and are being amortized over the life of the related property. Investment tax credits available of about $4.8 million ($2.5 million of which is attributable to PHC and $900,000 to BVC) have not been utilized or recorded and, subject to review by the Internal Revenue Service ("IRS"), may be used prior to their expiration, which occurs between 1996 and 2005.
At December 31, 1993, the Company had, for income tax purposes, alternative minimum tax credits ("AMT") of approximately $3.2 million for the reduction of future tax liabilities. At December 31, 1993, the Company had, for income tax reporting purposes, approximately $21 million of net operating loss carryforwards that expire in 2008.
NOTE 3. COMMON AND PREFERRED STOCK
COMMON STOCK In June of 1993 the Company issued and sold for cash 745,000 common shares (for proceeds of $14.8 million). The proceeds were utilized to finance construction expenditures, reduce short-term debt, and fund a portion of the buyout of the power purchase agreement with the Beaver Wood Joint Venture, which is more fully described in Note 7. The Company issued and sold for cash 920,000 common shares (for proceeds of approximately $13.1 million) in June of 1991. The proceeds were used to reduce outstanding short-term debt. Prior to 1992, stockholders had been able to invest their dividends and optional cash payments in common stock of the Company acquired by an independent agent in the open market through the Company's Dividend Reinvestment and Common Stock Purchase Plan ("the Plan"). In 1992 the Company amended the Plan to enable it to issue original shares in return for the reinvested dividends and optional cash payments. The common stock has general voting rights of one vote per twelve shares owned.
PREFERRED STOCK Authorized preferred stock consists of 400,000 shares, par value $100 per share, of which there are 197,340 shares outstanding. The remaining 202,660 authorized but unissued shares (plus additional shares equal in number to such presently outstanding shares as may be retired) may be issued with such preferences, restrictions or qualifications as the Board of Directors may determine. Any new shares so issued will be required to be issued with per share voting rights no greater than that of the common stock. The callable preferred stock may be called in whole or in part upon any dividend date by appropriate resolution of the Board of Directors. Except for the holders of the 8.76% issue, which does not carry general voting rights, the currently outstanding preferred stock has general voting rights of one vote per share. With regard to payment of dividends or assets available in the event of liquidation, preferred stock ranks prior to common stock.
REDEEMABLE PREFERRED SHARES Call premiums on preferred stock redeemed in 1986 and 1987 were deferred and were being amortized to earnings over a ten-year period. In compliance with an audit by FERC, the remaining balance of these deferred call premiums ($449,700 at December 31, 1990) were charged directly to retained earnings in 1991.
On December 27, 1989, the Company issued to an institutional investor $15 million of non-voting preferred stock carrying a dividend rate of 8.76%. These shares have a maturity of fifteen years with a mandatory sinking fund of $1.5 million per year starting in 1995. The agreement to issue this series of preferred stock contains a provision whereby, if the Copany pays a dividend that is considered a return of capital for federal income tax purposes, the Company is required to make a payment to the stockholder in order to restore the stockholder's after-tax yield to the level it would have been had the dividend not been considered a return of capital. Since 100% of the dividends paid in 1990 and 1993, pending any review by the IRS, are to be considered a return of capital, the Company has become obligated to pay this stockholder approximately $969,000 at the time the stock is either sold or redeemed. This obligation is being recognized over the remaining life of the issue through a direct charge to retained earnings of $72,862 per year.
NOTE 4. LONG-TERM DEBT
Under the provisions of the first mortgage bond indenture, substantially all of the Company's plant and property has been mortgaged to secure the Company's first mortgage bonds. Sinking fund requirements and current maturities of the first mortgage bonds for the five years subsequent to December 31, 1993 aggregate $10,536,507 as follows:
		 Sinking Fund Current 		 Requirements Maturities Total
1994 $1,297,448 $ - $ 1,297,448 1995 1,461,253 - 1,461,253 1996 1,645,737 - 1,645,737 1997 1,853,515 - 1,853,515 1998 1,778,554 2,500,000 4,278,554 		 ----------- ----------- ----------- 		 $8,036,507 $2,500,000 $10,536,507 		 =========== =========== ===========
In 1993 the Company issued $15 million of 7.3% first mortgage bonds to an institutional investor for a period of 10 years. Also in 1993, in connection with the termination of the purchased power contract (which is discussed in Note 7), the Company issued $14.3 million of 12.25% mortgage bonds to the holders of Beaver Wood's debt in substitution for the Beaver Wood's pre- viously outstanding 12.25% secured notes. In September 1993 the Company redeemed the 8.25%, 8.6%, and 9.25% series of first mortgage bonds. The redemptions of these issues resulted in call premiums of $29,563, and $31,011, respectively.
The Company completed two first mortgage bond financings during 1992. The first was issued in April for $20 million at an interest rate of 8.98% for a period of 20 years. The second was issued in October for $20 million at an interest rate of 7.38% for a period of 10 years. In 1992, the Company redeemed the 10.5%, 10.25% and the 17.35% series of first mortgage bonds. The redemption of these issues resulted in call premiums of $88,200, $170,765 and $88,000, respectively.
The call premiums in 1993 and 1992 were deferred and have been included in the Company's current base rate filing on which a final decision was reached in February 1994. The Company is allowed to amortize these costs over a ten-year period with the unamortized balance included in the rate base.
NOTE 5. SHORT-TERM BORROWINGS
The Company has an unsecured revolving credit agreement ("Credit Agreement") with a group of four banks providing for loans of up to $25 million. The Credit Agreement expires on May 26, 1994 but may be extended through May 26, 1995 with unanimous consent of the participating banks. The Credit Agreement has a term loan arrangement whereby the loan balance at the date of termination can be paid in equal quarterly installments over a two-year period. The Company may borrow at rates, as defined within the Credit Agreement, based on certificate of deposit loan rates, Eurodollar loan rates or the agent bank's reference rate.
A commitment fee of 1/4 of 1% per annum is required on the amount not borrowed under any of these borrowing options. A fourth borrowing option under the Credit Agreement is in the form of "bid loans" whereby the Company can borrow at "money market" rates independently set by each of the four banks participating in the Credit Agreement. This form of borrowing does not reduce the commitment fee but does reduce the credit available under the Credit Agreement. The Credit Agreement allows the Company to incur an additional $30 million in unsecured debt outside of the agreement. The Company maintains lines of credit with banks which it utilizes when the borrowing costs under the lines of credit are more favorable than those under the Credit Agreement. Certain of these lines of credit have commitment fees ranging from 1/8 of 1% to 1/4 of 1% of the line while others have no commitment fees.
Certain information related to total short-term borrowings under the Credit Agreement and the lines of credit is as follows:
				 1993 1992 1991 - ---------------------------------------------------------------------------- Total credit available at end of period $55,000,000 $55,000,000 $42,000,000 Unused credit at end of period $19,000,000 $40,000,000 $13,500,000 Borrowings outstanding at end of period $36,000,000 $15,000,000 $28,500,000 Effective interest rate (exclusive of fees) on borrowings out- standing at end of period 3.7% 4.4% 5.4% Average daily outstanding bor- rowings for the period $22,754,205 $22,448,087 $23,297,260 Weighted daily average annual interest rate 3.7% 4.5% 6.6% Highest level of borrowings outstanding at any month- end during the period $36,000,000 $31,000,000 $28,500,000
The average daily borrowings outstanding for the period represent the sum of daily borrowings outstanding, divided by the number of days in the period. The weighted daily average annual interest rate is determined by dividing the annual interest expense by the average daily borrowings outstanding for the period. Commitment and agent fees for the revolving credit agreement of $40,000, $68,000 and $27,000 were paid in 1993, 1992 and 1991, respectively, and are excluded from the calculation of the weighted daily average annual interest rate.
NOTE 6. PENSION AND OTHER POST-EMPLOYMENT BENEFITS
The Company has noncontributory pension plans covering substantially all of its employees. On July 17, 1987, the Company created separate union and nonunion plans from an original plan. Benefits under the plans are generally based on the employee's years of service and compensation during the years preceding retirement. The Company's general policy is to contribute to the funds the amounts deductible for federal income tax purposes.
The Company recorded pension income of $12,000, $348,214 and $263,700 for 1993, 1992 and 1991, respectively. The tables below and on the following page detail the components of pension income for 1993, 1992 and 1991, the funded status of the plans, the amounts recognized in the Company's Financial Statements and the major assumptions used to determine these amounts.
The plan's assets are composed of fixed income securities, equity securities and cash equivalents.
Total pension income included the following components:
				 1993 1992 1991 - ----------------------------------------------------------------------------- Service cost - benefits earned during the period $ 1,085,419 $ 1,037,419 $ 982,180 Interest cost on projected benefit obligation 2,244,706 1,996,491 1,605,246 Actual return on plan assets (4,633,435) (2,366,341) (6,595,692) Total of amortized obligations and the net gain (loss) deferred $ 1,291,310 $(1,015,783) $ 3,744,566 				 ------------ ------------ ------------ Total pension (income) $ (12,000) $ (348,214) $ (263,700) 				 ============ ============ ============
Significant assumptions used were - Discount rate 7.0% 8.0% 8.0% Rate of increase in future compensation levels 5.0% 6.0% 6.0% Expected long-term rate of return on plan assets 9.0% 9.0% 8.0%
The following table sets forth the plans' funded status and amounts recognized in the Balance Sheets at December 31, 1993 and 1992:
						 1993 1992 						 ------------- ------------ Actuarial present value of accumulated benefit obligation Vested $ 22,730,655 $ 16,294,432 Non-vested 2,669,955 1,686,977 						 ------------- ------------ Total $ 25,400,610 $ 17,981,409 						 ------------- ------------ Projected benefit obligation $(32,484,893) $(28,182,601) Plan assets at fair value 37,810,748 35,081,512 						 ------------- ------------ Excess of plan assets over projected benefit obligation $ 5,325,855 $ 6,898,911 Items not yet recognized in earnings - Net (asset) at transition (6,916,450) (7,848,775) Prior service cost 4,597,483 4,206,141 Unrecognized net gain from past experience and changes in assumptions (608,390) (869,779) 						 ------------- ------------ Net pension asset recognized $ 2,398,498 2,386,498 						 ============= ============
In addition to pension benefits, the Company provides certain health care and life insurance benefits to its retired employees. Substantially all of the Company's employees may become eligible for retiree benefits if they reach normal retirement age while working for the Company.
The Company has adopted Financial Accounting Standards Board Statement No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" ("FAS 106") as of January 1, 1993. This standard requires the accrual of postretirement benefits, including medical and life insurance coverage, during the years an employee provides services to the Company. Prior to 1993, the cost of health care benefits were expensed as benefits were paid.
The MPUC issued a final accounting rule in connection with FAS 106 which adopted this pronouncement for ratemaking purposes and provides the Company with the accounting and regulatory framework required to defer the excess ($604,529, which is net of capitalized amounts at December 31, 1993) of the net periodic postretirement benefit cost recognized under FAS 106 over the pay-as-you-go amount in 1993 and to record such excess as a regulatory asset pending inclusion in future rates, subject to the same level of review for prudence and reasonableness as are all other utility expenses. The Company, in accordance with the ruling and FAS 106, is amortizing the unrecognized transition obligation of $10,023,200 over a 20-year period. The Company will begin recovering the deferred FAS 106 costs with the implementation of new base rates on March 1, 1994 and amortize the deferred balance over a ten-year period.
In accordance with the provisions of FAS 106, the actuarially determined net periodic postretirement benefit cost for 1993 and the major assumptions used to determine these amounts are shown below.
Net periodic postretirement benefit cost for 1993 includes the following components:
Service cost of benefits earned $ 359,600 Interest cost on accumulated post- retirement benefit obligation 683,200 Amortization of unrecognized transition obligation over 20 years 501,200 						 ----------
Net periodic postretirement benefit cost $1,544,000 Expense on a pay-as-you-go basis (534,900) Amounts capitalized into construction work in progress (404,571) 						 ---------- Regulatory asset recorded at December 31, 1993 $ 604,529 						 ==========
The following table sets forth the benefit plan's unfunded status and amounts recognized in the Company's Balance Sheet at December 31, 1993:
Accumulated postretirement benefit obligation: Retirees $ 5,640,000 Fully eligible active plan participants 773,000 Other active participants 4,196,000 								 ------------ 								 $10,609,000 Unrecognized net transition obligation (9,522,000) Unrecognized net loss 457,000 								 ------------ Accrued postretirement benefit cost 1,544,000 Less: Expense recognized on a pay-as-you-go basis 534,900 								 ------------ Net liability recorded at December 31, 1993 (included in Other Reserves) $ 1,009,100 								 ===========
For measuring the expected postretirement benefit obligation, a 12.4% annual rate of increase in the per capita claims cost ("trend rate") for participants who have not reached the age of 65 was assumed for 1992. This rate was assumed to decrease annually to 6% in 2050 and remain at that level thereafter. For those participants who are 65 or older, the trend rate was assumed to be 8.3% in 1992, 9.7% in 1993 and then decrease until 2050 when it is assumed to be 5.8%.
If the health care cost trend rate was increased one percent, the accumulated postretirement benefit obligation as of January 1, 1993 would have increased by 11%. The effect of such change on the aggregate of service and interest cost for 1993 would be an increase of 12%.
The weighted average discount rate used in determining the accumulated postretirement benefit obligation was 7% at December 31, 1993.
In November 1992, the FASB issued Statement of Financial Accounting Standards No. 112, "Employers' Accounting for Postemployment Benefits" ("FAS 112"). The Company is required to adopt this standard no later than January 1, 1994. FAS 112 applies to postemployment benefits provided to former or inactive employees, their beneficiaries, and covered dependents after employment but before retirement. FAS 112 will change the current methods of accounting for postemployment benefits from recognizing costs as benefits are paid, to accruing the expected costs of providing these benefits if certain conditions are met. Management is currently evaluating the financial impact of this accounting standard. However, the effect of FAS 112 on the Company's results of operations and financial position is not expected to be significant.
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 operates a nuclear power plant in Wiscasset, Maine. Under purchased power arrangements, the Company is entitled to purchase an amount approximately equal to its ownership share of the output of Maine Yankee, an entitlement of approximately 62 MW. The Company is obligated to pay its pro rata share of Maine Yankee's operating expenses, fuel costs, capital costs and decommissioning costs.
MEPCO The Company owns 14.2% of the common stock of MEPCO. MEPCO owns and operates electric transmission facilities from Wiscasset, Maine to the Maine-New Brunswick border. Several New England utilities, including the Company and MEPCO's other stockholders (two other Maine utiities), are parties to a transmission support agreement pursuant to which such utilities have agreed to pay MEPCO's costs, based on their relative system peaks, if MEPCO's revenues from transmission services are not sufficient to meet its expenses.
Information relating to the operations and financial position of Maine Yankee and MEPCO appears at the bottom of page 40.
WYMAN 4 The Company owns 8.33% (50 MW) of the oil-fired 600 MW Wyman No. 4 unit. The Company's proportionate share of the direct expenses of this unit is included in the corresponding operating expenses in the Statements of Income. Included in the Company's utility plant are the following amounts with respect to this unit:
				 1993 1992 1991 				 ----------- ----------- ----------- Electric plant in service $16,767,909 $16,760,816 $16,642,989 Accumulated depreciation (7,539,591) (7,025,278) (6,512,562) 				 ----------- ----------- ----------- 				 $ 9,228,318 $ 9,735,538 $10,130,427 				 =========== =========== ===========
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.
				 MAINE YANKEE 			 (Dollars in Thousands) 	 -------------------------------------------------------- 					 1993 1992 1991 					 ---- ---- ----
OPERATIONS: As reported by investee - Operating Revenue $193,102 $187,259 $166,471 					---------------------------- Depreciation $ 25,458 $ 24,462 $ 23,729 Interest and Preferred Dividends 14,407 14,092 16,015 Other expenses, net 145,861 140,311 118,358 					---------------------------- Operating expenses $185,726 $178,865 $158,102 					---------------------------- Earnings Applicable to Common Stock $ 7,376 $ 8,394 $ 8,369 					============================ Amounts Reported by the Company - Purchased power costs $ 11,265 $10,830 $ 9,416 Equity in net income (542) (592) (581) 					---------------------------- Net purchased power expense $ 10,723 $10,238 $ 8,835 					============================
FINANCIAL POSITION: As reported by investee - Plant in service $396,133 $384,664 $368,952 Accumulated depreciation (175,996) (163,887) (149,625) Other assets 314,680 300,416 267,554 					---------------------------- 	Total assets $534,817 $521,193 $486,881 Less - Preferred stock 19,800 21,000 6,600 Long-term debt 115,333 110,390 124,633 Other liabilities and deferred credits 332,030 322,900 287,734 				 	---------------------------- 	Net assets $ 67,654 $ 67,503 $ 67,914 				============================ Company's reported equity - Equity in net assets $ 4,736 $ 4,725 $ 4,754 Adjust Company's estimate to actual 20 11 (16) 				---------------------------- Equity in net assets as reported $ 4,756 $ 4,736 $ 4,738 					============================
				 MEPCO 			 (Dollars in Thousands) 	 -------------------------------------------------------- 					 1993 1992 1991 					 ---- ---- ----
OPERATIONS: As reported by investee - Operating Revenue $ 12,809 $ 11,608 $ 14,918 					 ---------------------------- Depreciation $ 1,395 1,250 1,231 Interest and Preferred Dividends 124 186 336 Other expenses, net 11,185 10,067 13,246 					 ---------------------------- Operating expenses $ 12,704 $ 11,503 $ 14,813 					 ---------------------------- Earnings Applicable to Common Stock $ 105 $ 105 $ 105 					============================= Amounts Reported by the Company - Purchased power costs $ - $ - $ - Equity in net income (15) (15) (15) 				 ---------------------------- Net purchased power expense $ (15) (15) (15) 					=============================
FINANCIAL POSITION: As reported by investee - Plant in service $ 23,123 $ 22,915 $ 22,775 Accumulated depreciation (19,174) (17,891) (16,841) Other assets 2,414 1,815 4,281 					----------------------------- 	Total assets $ 6,363 6,839 10,215 Less - Preferred stock - - - Long-term debt 2,590 3,450 4,310 Other liabilities and deferred credits 2,895 2,511 5,026 				 	----------------------------- 	Net assets $ 878 $ 878 $ 879 					============================= Company's reported equity - Equity in net assets $ 125 $ 125 $ 125 Adjust Company's estimate to actual - - - 					----------------------------- Equity in net assets $ 125 $ 125 $ 125 as reported =============================
In 1990, the Company formed Bangor Var Co., Inc. whose sole function is to be a 50% general partner in the Chester SVC Partnership ("Chester"), a partnership which owns the static var compensator ("SVC"), which is electrical equipment that supports the Phase 2 transmission line. A wholly-owned subsidiary of Central Maine Power Company owns the other 50% interest in Chester. Chester has financed the acquisition and construction of the SVC through the issuance of $33 million in principal amount of 10.48% senior notes due 2020, and up to $3.25 million principal amount of additional notes due 2020 (collectively, the "SVC Notes"). The holders of the SVC Notes are without recourse against the partners or their parent companies and may only look to Chester and to the collateral for payment.
The New England utilities which participate in Phase 2 have agreed under a FERC-approved contract to bear the cost of Chester, on a cost of service basis, which includes a return on and of all capital costs.
SMALL POWER PRODUCTION FACILITIES As of the beginning of 1993, the Company had contracts with ten independent, non-utility power producers known as "small power production facilities." The West Enfield Project, described below, is one such facility. There are five other relatively small hydroelectic facilities. The remainder are larger (15-25 MW) facilities, three fueled by biomass (primarily wood chips) and one by municipal solid waste. The cost of power from the small power production facilities is more than the Company would incur if it were not obligated under these contracts, and, in the case of the biomass and solid waste plants, 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. In the Company's 1987 rate proceeding, the MPUC investigated the events surrounding the contract negotiations but reached no conclusion about the Company's prudence in entering into these contracts. The fuel cost adjustment approved by the MPUC effective November 1, 1993 includes projected costs for small power production facilities.
In order to lower the overall cost of power to its customers, the Company negotiated an agreement to cancel its long-term purchased power agreement with one of the biomass plants, the Beaver Wood Joint Venture ("Beaver Wood"), in June 1993. In connection with the cancellation the Company paid Beaver Wood $24 million in cash and issued a new series of 12.25% First Mortgage Bonds due July 15, 2001 to the holders of Beaver Wood's debt in the amount of $14.3 million in substitution for Beaver Wood's previously outstanding 12.25% Secured Notes. Also, in connection with the cancellation agreement, a reconstituted Beaver Wood partnership paid the Company $1 million at the time of settling the transaction and has agreed to pay the Company $1 million annually for the next six years in return for retaining the ownership and the option of operating the plant. The payments are secured by a mortgage on the property of the Beaver Wood facility. The Company believes this contract buyout transaction will result in significant savings to its customers compared to the continuation of payments under the purchased power contract.
In May 1993 the Company received an accounting order from the MPUC related to the purchased power contract buyout. The order stipulated that the Company may seek recovery of the costs associated with the buyout in a future base rate case, and could also record carrying costs on the deferred balance. Consequently, a regulatory asset of $40.3 million has been recorded as of December 31, 1993. Effective with the implementation of new base rates on March 1, 1994, the Company will begin recovering over a nine-year period the deferred balance, net of the $6 million anticipated from Beaver Wood.
The agreements with the other two biomass plants, located in the Company's service territory in West Enfield and Jonesboro, are also long-term (30-year) contracts. The West Enfield and Jonesboro facilities, plants of 24.5 MW each constructed by the same developer, commenced operation in November 1987. The Company has contracted to resell a portion of the capacity from these two projects to another utility. The cost to the Company of these contracts (net of revenues from the foregoing resale) is approximately $26 million annually. The Company also has a 30-year contract with the municipal solid waste facility, a 20 MW waste-to-energy plant in the Company's service territory in Orrington, completed in 1988. The Company has also contracted to resell a portion of the capacity for fifteen years from this facility to the other utility referred to earlier. The cost to the Company of the power delivered by this facility (net of revenues from the foregoing resale) is projected to be $14 million annally.
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 (the "West Enfield Project") for the purpose of operating the facility once it was completed. Commercial operation of the redeveloped project began in April 1988. A wholly-owned corporate subsidiary, Penobscot Hydro Co., Inc. ("PHC") was formed to own the Company's 50% interest in the joint venture, Bangor-Pacific Hydro Associates ("Bangor Pacific").
Bangor-Pacific financed the $45 million estimated cost of the redevelopment through the issuance in a privately placed transaction of $40 million of fixed rate term notes and a commitment for up to $5 million of floating rate notes. The notes are secured by a mortgage on the project and a security interest in a 50-year purchased power contract, and the revenues expected thereunder, between the Company and Bangor-Pacific. Except as described below, the holders of the notes issued by Bangor-Pacific are without recourse to the joint venture partners or their parent companies.
In the event Bangor-Pacific fails to pay when due amounts payable pursuant to the loan agreement, each partner has agreed to make capital contributions to Bangor-Pacific in an amount equal to 50% of such amounts due and payable, but not exceeding an amount equal to distributions from Bangor-Pacific received by such partner in the preceding twelve-month period. The Company is obliged to provide funds necessary to support the foregoing limited financial commitment to the project undertaken by PHC as the partner.
Under the purchased power contract, if the project operates as anticipated, payments by the Company to Bangor-Pacific are estimated to be about $7.5 million annually (without consideration of any distributions by the joint venture to the partners). It is possible that the Company would be required to make payments under the contract regardless of whether any power is delivered, in an amount of approximately $4 million per year. However, the Company has the right to terminate the contract if the failure to deliver power continues for a period of 12 consecutive months.
The fuel cost adjustment approved by the MPUC effective November 1, 1993, includes projected costs for power delivered to the Company by Bangor Pacific.
BASIN MILLS AND VEAZIE PROJECTS As a result of increased uncertainty (discussed below) about the recoverability of amounts invested through 1993 in licensing activities for proposed additional hydroelectric facilities, the Company established a reserve against those investments in the amount of $8.7 million as of December 31, 1993. Further, the Company plans to expense all future amounts related to these licensing activities. The projects for which the reserve has been established are a proposed 38 megawatt generating facility located at the so-called Basin Mills site on the Penobscot River at Orono and Bradley, Maine and an 8 megawatt addition to the Company's existing dam and power station on the Penobscot River in Veazie and Eddington, Maine. The projects would require a total investment of $140 million. The Company has been pursuing the permitting of these facilities since the early 1980's.
In November 1993 the Maine Board of Environmental Protection ("BEP") approved the projects under State environmental laws and issued the water quality certificate required by the Federal Clean Water Act. The BEP's order is subject to a number of conditions, some of which could prove to be costly if the projects are developed. The BEP's decision is being appealed by the projects' opponents, and the Company cannot predict the outcome of these proceedings.
If the projects continue, further significant licensing activities can be expected at the FERC, the U.S. Army Corps of Engineers, the MPUC, the BEP and possibly other agencies. The Company cannot predict the outcome of the licensing and permitting activities that are required in order for these projects to be constructed.
In addition to the Company's inability to predict the outcome of the requisite licensing activities, other uncertainties have arisen as a result of changes that have developed and are continuing to develop in the electric utility industry. In general, these changes are occurring as a result of the infusion of competition into the industry. As a consequence, even if these projects continue to be the least-cost alternatives for power supply, the increasing concern about the impact of competition raises uncertainty about the timely recovery of the investment required to construct the projects. Accordingly, although the projects are not being abandoned and licensing activities are continuing, there is now less certainty that they will be constructed or that the costs for the completed projects could be recovered.
The Company also believes that the recoverability of the costs incurred to date is subject to increasing uncertainty. Under Maine law and regulation, the MPUC can authorize the recovery of prudently incurred utility investment in abandoned or cancelled projects. However, under current MPUC policy, recovery of plant investment cannot begin until either it becomes operational or it is abandoned or cancelled. Since neither of these events has occurred and since the Company cannot predict when either of them might occur, it is impossible to forecast when a final regulatory decision on the recoverability of these costs might be made. Moreover, given the concerns about competitiveness described above, at the time when recovery of those costs might be requested, the Company would likely take into consideration the impact of the inclusion of those costs in its rates, and could conclude that it would not be in the Company's best interests to pursue cost recovery.
NOTE 8. RECOVERY OF SEABROOK INVESTMENT AND SALE OF SEABROOK INTEREST
The Company was a participant in he 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 of the unamortized balances. As of December 31, 1992, the Company's investment in Seabrook Unit 2 was fully amortized.
NOTE 9. CONTINGENCIES
BANKRUPTCY OF LARGEST CUSTOMER LCP filed for protection under Chapter 11 of the bankruptcy law in July 1991. At the time of the bankruptcy filing, LCP owed $719,642 for electric service, for which the Company has a general, unsecured claim. In addition, LCP is seeking to recover from the Company certain payments for electric service made prior to the filing as preference payments under the bankruptcy law. Since the filing, pursuant to arrangements approved by the Bankruptcy Court, LCP must pay for service weekly in arrears and the Company may curtail deliveries of power three days after the presentation of a weekly bill. Furthermore, the Company has been permitted to collect a deposit to secure the value of approximately one week of service. As a result, the LCP account for service rendered after the date for bankruptcy filing is current.
ENVIRONMENTAL MATTERS The Company has received a notice of potential liability under the Comprehensive Environmental Response, Compensation, and Liability Act as a generator of hazardous substances that the United States Environmental Protection Agency alleges may have been disposed of at a waste disposal facility in Connecticut. The Company is only one of several hundreds of potentially responsible parties at the site.
The Company has received a notice from the Maine Department of Environmental Protection under similar Maine legislation relating to several facilities in Maine. The Company is not yet aware of the extent of potential clean-up necessary or the number of potentially responsible parties involved.
In management's opinion, the resolution of these matters are not expected to have a material adverse impact on the Company's financial condition.
NOTE 10. UNAUDITED QUARTERLY FINANCIAL DATA
Unaudited quarterly financial data pertaining to the results of operations are shown below:
						 Quarter Ended 		 		--------- --------- --------- -------- 	 			 March 31 June 30 Sept. 30 Dec.31 				--------- --------- --------- ------- 			 (Dollars in thousands except per share amounts)
	 ---- Electric Operating Revenue $46,679 $40,548 $43,476 $ 44,269 Operating Income 4,779 4,486 4,396 3,138 Net Income (Loss) 2,908 2,766 3,244 (3,582)* Earnings (Loss) Per Share of Common Stock $ .46 $ .42 $ .46 $(.64)* 				 ======= ======== ======== ========
	 ---- Electric Operating Revenue $48,013 $39,722 $41,877 $ 47,177 Operating Income 4,472 4,370 5,050 4,624 Net Income 2,555 2,224 2,885 2,591 Earnings Per Share of Common Stock $ .40 $ .34 $ .46 $ .40 				 ======== ======== ======== =========
	 ---- Electric Operating Revenue $44,142 $35,256 $37,966 $44,879 Operating Income 4,526 3,500 4,119 4,300 Net Income 2,275 1,462 2,068 2,394 Earnings Per Share of Common Stock $ .42 $ .23 $ .31 $ .37 				 ========= ======== ======== ========
* Includes the provision for Basin Mills of $5.7 million after-tax or $.95 per common share.
NOTE 11. FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair value at December 31, 1993 of each class of financial instruments for which it is practical to estimate the value:
Cash and cash equivalents:
The carrying amount of $2,387,156 approximates fair value.
The fair values of mandatory redeemable cumulative preferred stock, first mortgage bonds and pollution control revenue bonds at December 31, 1993 based upon similar issues of comparable companies are as follows:
							 In Thousands 						 ------------------- 						 Carrying Fair 							Amount Value 						 ------------------- Mandatory redeemable cumulative preferred stock $ 15,168 $ 16,022 First Mortgage Bonds 116,223 137,735 Pollution Control Revenue Bonds 4,200 4,200 						 ===================
REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS
To the Stockholders and Directors of Bangor Hydro-Electric Company:
We have audited the accompanying consolidated balance sheets and statements of capitalization of Bangor Hydro-Electric Company and subsidiaries (the "Company") as of December 31, 1993 and 1992, and the related consolidated statements of income, retained earnings, and cash flows for each of the three years in the period ended December 31, 1993. These financial statements are the responsibility of the Company s management. Our responsiblity is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the 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 audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of the Company as of December 31, 1993 and 1992, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 1993, in conformity with generally accepted accounting principles.
As discussed in Note 2 to the consolidated financial statements, in 1993 the Company changed its method of accounting for income taxes.
						 Coopers & Lybrand Portland, Maine February 17, 1994
ITEM 9 CHANGES IN AND DISAGREEMENTS WITH AUDIT FIRMS ON FINANCIAL DISCLOSURE - ------ ------------------------------------------------
There have been no changes in or disagreements with audit firms on financial disclosure.
PART III - --------
ITEM 10 DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT - ------- -------------------------------------------------- See Part I above, and see the information under "Election of Directors" in the Company's definitive proxy statement for the annual meeting of stockholders to be held on May 18, 1994, which information is incorporated herein by reference.
ITEM 11 EXECUTIVE COMPENSATION - ------- ---------------------- See the information under "Executive Compensation" in the Company's definitive proxy statement for the annual meeting of stockholders to be held on May 18, 1994, which information is incorporated herein by reference.
ITEM 12 SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT - ------- ----------------------------------------------- (a) Security Ownership of Certain Beneficial Owners
See the Company's definitive proxy statement for the annual meeting of stockholders to be held on May 18, 1994, which information is incorporated herein by reference.
(b) Security Ownership of Management
See the Company's definitive proxy statement for the annual meeting of stockholders to be held on May 18, 1994, which information is incorporated herein by reference.
(c) Changes in Control
Not applicable.
ITEM 13 CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS - ------- ---------------------------------------------- See the information under "Election of Directors" in the Company's definitive proxy statement for the annual meeting of stockholders to be held on May 18, 1994, which information is incorporated herein by reference.
PART IV - -------
ITEM 14 EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K - ------- ----------------------------------------------------
(a) Consolidated Financial Statements of the Company (See Item 8)
Consolidated Statements of Income for the Years Ended December 31, 1993, 1992 and 1991
Consolidated Balance Sheets - December 31, 1993 and
Consolidated Statements of Retained Earnings for the Years ended December 31, 1993, 1992 and 1991
Consolidated Statements of Capitalization - December 31, 1993 and 1992
Consolidated Statements of Cash Flows for the Years Ended December 31, 1993, 1992 and 1991
Notes to Consolidated Financial Statements
Report of Independent Accountants
(b) Schedules
Report of Independent Accountants
Schedule V - Property, Plant and Equipment and and Construction in Progress
Schedule VI - Accumulated Depreciation and Amortization of Property, Plant and Equipment
Schedule VIII - Reserves for Doubtful Accounts and Insurance
All other schedules are omitted as the required information is inapplicable or the information is presented in the Company's consolidated financial statements or related notes.
(c) Exhibits
See Exhibit Index, page
(d) Reports on Form 8-K
A Current Report on Form 8-K dated December 15, 1993 was filed in the fourth quarter of 1993, regarding the establishment of a reserve against investments in certain hydroelectric facilities.
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.
Robert S. Briggs ------------------------- Robert S. Briggs President and Chairman of the Board (Chief Executive 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.
Robert S. Briggs Helen Sloane Dudman - ------------------------ ------------------------ Robert S. Briggs Helen Sloane Dudman President and Director Chairman of the Board
G. Clifton Eames - ------------------------ ------------------------ William C. Bullock, Jr. G. Clifton Eames Director Director
Jane J. Bush Robert H. Foster - ------------------------ ------------------------ Jane J. Bush Robert H. Foster Director Director
David M. Carlisle Carroll R. Lee - ------------------------ ------------------------ David M. Carlisle Carroll R. Lee Director Director, Vice President- Operations
John P. O'Sullivan - ------------------------ ------------------------ Alton E. Cianchette John P. O'Sullivan Director Director, Vice President- Finance & Administration (Chief Financial Officer)
David R. Black ----------------------- David R. Black Controller (Chief Accounting Officer)
Each of the above signatures is affixed as of March 23, 1994.
REPORT OF INDEPENDENT ACCOUNTANTS
To the Stockholders and Board of Directors Bangor Hydro-Electric Company:
Our report on the financial statements of Bangor Hydro-Electric Company is included Item 8