Annual Report (Form 10-K), fiscal year 1994





Item 3 LEGAL PROCEEDINGS
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, 1994, there were 7,705 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................ $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................ $19 $16 3/8 $.33 Second Quarter............... 17 13 .33 Third Quarter................ 13 1/2 11 1/4 .33 Fourth Quarter............... 12 1/4 9 3/8 .33
---- First Quarter (through March 20, 1995)... $12 7/8 $ 9 1/4 $.33
Bangor Hydro-Electric Company
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION
RECENT DEVELOPMENTS FOR THE COMPANY AND IN THE ELECTIC UTILITY INDUSTRY AND POTENTIAL EFFECTS ON FUTURE SALES, EARNINGS AND DIVIDEND POLICY
Changes in the Industry and in Regulation
Historically, the electric utility industry has been viewed as relatively stable for common equity investors, providing a consistent level of dividends with moderate growth and presenting a comparatively low risk to equity investments. This stability developed because of public policies that treated electric utilities as natural monopolies, requiring regulation of rates and service and the protection of defined service territories. The industry has been substantially free of competition while its profits have been limited by traditional rate of return regulation.
In recent years, several factors have worked together to increase competitive pressures on electric utilities in the United States and particularly in Maine. Prices charged by electric utilities have increased rapidly to cover the costs of implementing various public policy mandates including the purchase of power from high cost non-utility power producers, the subsidization of energy conservation and demand-side management ("DSM") measures, financial assistance for low income customers, environmental mitigation and improvement measures, and various other requirements. In addition, public and regulatory policies implemented in Maine in the 1970's and 1980's overtly discouraged the growth of electric sales, thereby tending to increase unit costs. As a consequence of these factors, electric rates in Maine have, on average, increased faster than the electric rates in New England, exclusive of Maine. In the past, Maine's rates were substantially lower, on average, than elsewhere in New England, but with the rate of increase experienced recently, the average rate in Maine is now just below the New England average. The Company's average rates are slightly higher than the Maine statewide average, and are about equal to the New England average.
On an industry-wide scale, high embedded costs for many utilities have combined with certain fundamental changes in the regulation of the electric utility industry and in the economics of power generation to threaten the ability of many traditional utilities to retain existing customers and to attract new load. The Energy Policy Act of 1992 requires that the owner of transmission facilities must, under certain specified conditions, transmit power for third parties to "wholesale customers" meaning other retail distribution utilities that are purchasing power for resale in their utility business. This access to the transmission system allows existing municipal and other distribution utilities that have traditionally purchased power from neighboring utilities to purchase power in the competitive generation markets. It also provides an incentive for the existing retail customers of a utility to seek to lower their electric rates by forming a municipal utility or utility district solely to qualify for the transmission access. Although the 1992 Act does not require transmission access for retail customers, individual states may authorize such access. California and other states are currently exploring the terms under which retail transmission access might be allowed.
In addition to relaxed access to transmission services, technological improvements and increasing competition in the generation of electricity have in recent years lowered the cost of generation. The cost of new generation facilities today is significantly lower than the cost of facilities built only a few years ago that are now embedded in the existing cost structure of electric utilities. In addition, the cost for a large retail customer to install its own generation facilities at the point of consumption has dropped to a level that can be competitive with the prices charged by electric utilities.
Finally, competition for the business of individual consumers and retail customers has increased as the price of electricity has risen and the availability of alternative methods of providing the services desired by customers has increased. This has lead to discussions of the concept of utilities having "core" and "non-core" customers, with the former being thought to have no real alternative to electricity for the particular service they need, and the latter considered as being "at risk" of loss depending on price.
Although these are industry-wide trends, their effect on individual utilities varies depending on the facts in each situation. In Maine, these competitive factors are relatively challenging for Maine's utilities and for the Company, given the high cost and restrictive usage factors described above.
In order to meet these competitive pressures and achieve profitability over the long term, the Company believes that it must control its costs and increase sales in order to minimize the rates it charges for electricity, and achieve greater revenue through increased sales. Although under traditional, "cost-plus", rate-of-return regulation the Company could reasonably expect to be allowed by the Maine Public Utilities Commission ("MPUC") to increase its retail rates in an effort to enhance its profitability, the Company believes that this approach, taken by itself, would risk further erosion in sales. While it is difficult to forecast the precise relationship among rates, energy sales and total revenues over the short term, the Company believes that significant rate increases at this time would have a negative long-term impact on the Company's competitive position and its long-term financial success. Accordingly, although the Company has not ruled out seeking modest rate relief from the MPUC in the future, it does not believe that the present challenge of relatively low earnings can be solved solely by rate increases.
Despite the challenges of meeting increasing competition, the Company believes that it can succeed in the long run because it has the experience and breadth of knowledge to meet the needs of its customers in the part of Maine it serves and because the marginal cost of providing electric service is relatively low. The Company expects that, if public and regulatory policies were adjusted to permit the active pursuit of greater sales, the price that could be charged in a competitive environment, while lower than many of the Company's current rates, would recover more than the marginal cost of providing the service. The Company believes that, at such lower prices, there is substantial potential for increased business. Moreover, the Company believes that a strategy of greater electrification would produce desirable environmental quality improvement, and the realization of this beneficial impact will tend to enhance the favorable outlook for increased sales. To the extent the Company is successful in expanding its market share with competitive rates, the increased revenue in excess of marginal cost will enhance earnings and offset the need for other rate increases.
Under traditional regulatory policies, the Company has had only limited authority to adjust its prices to meet the competition. Competitive price initiatives have been evaluated and approved by the MPUC on a case-by-case basis. For example, for several years the Company has been allowed to sell interruptible energy to two major customers at significantly reduced rates, thereby retaining load that otherwise would have been lost and providing an incentive to add new load.
More recently, the Company has been negotiating on an individual basis with customers that have demonstrated that, without rate relief, they will curtail their purchases from the Company. In early 1994, the MPUC authorized the Company to enter into a five-year contract (terminable by the customer with two years' notice) for the supply of power to one of the Company's largest firm industrial customers at reduced rates. The Company also has on file with the MPUC an approved tariff that establishes procedures on a limited basis for the negotiation and implementation of individual rate discounts necessary to retain or attract load. Several smaller rate contracts have been approved pursuant to that procedure. The impact of these efforts to date has been that sales have been retained that could have otherwise been lost and, to some extent, sales have increased to some customers. However, to date the sales increases resulting from these pricing strategies have not offset the revenue reduction that results from the lower prices. Moreover, the operation of the fuel cost adjustment mechanism and the mandated accounting for fuel expense and revenue has caused the benefits from these strategies to be more weighted in favor of the Company's customers than its shareholders.
Therefore, even though the Company has had some success in retaining customers with the limited pricing flexibility that had been afforded by the MPUC, the Company believed that more flexibility was necessary in order to more effectively meet the demands of competition in a timely manner. Procedural obstacles and the lack of clear standards for evaluating proposed rate reductions have hindered the Company's ability to react quickly and flexibly to competitive threats. Because of this need for greater flexibility, the Company proposed to the MPUC a new Alternative Marketing Plan (or "AMP") in July of 1994. The AMP proposal included a plan for allowing increased flexibility to offer reduced prices and develop related marketing programs, a commitment to attempt to cap electric rates at current levels for an extended period, the elimination of fuel cost accounting and the fuel adjustment clause, the elimination of seasonal rate differentials and an understanding about the method of amortizing the cost of any future buyout of high-cost purchased power contracts.
On February 14, 1995, the MPUC issued an order approving many aspects of the Company's AMP proposal. The plan, as approved, while imposing greater restrictions on pricing flexibility than the Company would have preferred, should permit greater opportunities for the Company to meet the challenges of competition over the long term. Specifically, the MPUC established the following guidelines for the reduction of rates with limited regulatory oversight:
1. For existing customer classes, the Company may offer reduced rates with a price floor at the Company's long-term marginal cost plus 10% as long as the rate structure of the class is maintained within specified limits. Rates that meet the criteria will take effect automatically after a 30-day notice period. If a proposed reduction does not meet the criteria, the MPUC may suspend its effectiveness but will make a decision within four months of the initial filing date.
2. The Company may develop rates for new targeted customer classes with a price floor that depends upon whether the new load is "temporary" (not expected to continue for an extended period and sensitive to rate changes that occur after the initial discount) or "permanent" (expected to continue indefinitely regardless of later rate adjustments). For temporary load, the floor is short-term marginal cost plus 1.5 cents/KWH or, under certain circumstances, short-term marginal cost plus 10%. For permanent load, the floor is long-term marginal cost plus 10%. Rates that meet the criteria will take effect automatically after a 30-day notice period.
3. The Company may negotiate special rate contracts with individual customers, the criteria for which depend upon the length of the contract and whether the load is temporary or permanent.
a. For short-term contracts (up to three years) to supply temporary load, the floor is short-term marginal cost plus 1.5 cents/KWH. For short-term contracts to supply permanent load, the floor is long-term marginal cost plus 10%. Short-term contracts that meet all criteria will take effect automatically after a 30-day notice period.
b. For contracts with terms of three to five years, the floor is long-term marginal cost plus 10%. For contracts with terms of five to ten years, the floor is long-term marginal cost plus 25%. Contracts that meet all criteria will take effect automatically after a 30-day notice period.
c. Contracts with terms over ten years may not be approved automatically, but the MPUC will review any such proposal within four months of filing.
4. Any rate reduction that results in permanent load will also be subjected to certain cost tests, the results of which must be presented by the Company at the time of filing. If the proposal fails any of the tests, the Commission may suspend its effectiveness and the MPUC will review it within four months of filing.
5. The Company may eliminate seasonal rate differentials (requiring higher charges during winter months than during the remainder of the year) for certain classes of customers.
6. The total amount of price reductions (the "revenue delta") offered by the Company under the AMP will be capped at 10% of the Company's revenues. If the revenue delta approaches the cap, the Company would have to request authority from the MPUC to offer further discounts.
As proposed by the Company in its AMP proposal, effective January 1, 1995 the MPUC also ordered the elimination of the Fuel Cost Adjustment ("FCA"), a rate mechanism under which the Company has historically been permitted to adjust retroactively for changes in the cost of fuel for generation and in certain purchased power costs. The Company proposed the change because, under traditional regulation, the operation of the FCA has imposed the burden of rate discounting on utility shareholders while the benefits have been enjoyed by other utility customers. The Company believed, therefore, that a business strategy dependent on pricing flexibility would be effective only if the FCA were eliminated. However, the FCA has allowed the Company to respond quickly to changes in fuel and purchased power costs (both increases and decreases) and has reduced the volatility of earnings. Its elimination may result in increased or decreased earnings solely from changes in costs over which the Company has limited control.
As of January 1, 1995, the Company's collections under the FCA had exceeded its costs by approximately $3.03 million. With the elimination of the FCA, the MPUC recognized that there would no longer be a mechanism for the return of that sum to customers. The MPUC allowed the Company to retain that overcollection and ordered that the amount be amortized over a period of three years. That retention and amortization will have a short-term positive impact on the Company's earnings.
Also as requested by the Company, the MPUC established the recovery and accounting procedures to be followed in the event the Company negotiates a buyout of one or more of its contracts for the purchase of power from high-cost non-utility independent power producers. In the event of a buyout, the Company may amortize for accounting purposes the costs over the shorter of the remaining contract life, not considering extension options, or ten years. With the elimination of the FCA, reduced fuel cost benefits of any buyout will inure to the benefit of the Company and may be used to recover the amortization of the buyout cost. The Company believes that the fuel and energy cost savings achieved by such a buyout, previously subject to the FCA, would exceed any costs of such a buyout, including carrying costs on the unamortized balance.
Finally, the MPUC acknowledged with approval the Company's commitment to attempt to cap existing electric rates at current levels for an extended period and expressed a desire to formalize the details of such a commitment by the end of the summer of 1995.
Buyback of Purchased Power Contracts
The Company has reached an agreement in principle to buy back two contracts for the purchase of power from operators of biomass-fueled generating plants located in West Enfield and Jonesboro, Maine. Both power vendors are high-cost non-utility independent power producers with whom the Company was required to contract in the 1980's. The power contracts, identical in their terms and conditions, provide for the purchase of the entire generation output of each of the facilities. Each plant has a rated capacity of 24.5 megawatts. Power purchases began in 1986 and are scheduled under the contracts to continue for a period of approximately 30 years from the date of the initial purchases.
The power contracts provide for the purchase of power at prices consisting of the sum of a fixed component and a variable component. The Company has the option of requesting that the plants curtail or interrupt production, in which event payment is limited to the fixed component to the extent of curtailment or interruption. Because of the availability of less expensive power from other sources at prices less than the variable component of the contract rates, the Company has not taken delivery of significant amounts of electricity under these contracts in recent years and has limited its payments to the fixed component.
The buyback agreement calls for a cash payment by the Company of $83 million ($41.5 million per plant) and for the Company to assume responsibility for the remaining debt on the plants in a manner that relieves the owners of any further obligations on such debt. The balance of the outstanding debt is expected to be about $79 million in total at the time of the closing. If the lenders are unwilling to permit the assumption by the Company of such debt on terms acceptable to the Company and the owners, the Company would be required to increase the cash portion of the buyback by an amount sufficient to discharge the owners' debt in order for the buyback to be accomplished. In addition, the Company will be responsible for costs of preparing for a closing of the transaction and may incur significant costs in obtaining the necessary financing. The Company will be obliged to pay some portion of such costs whether or not a closing occurs.
Financing this transaction will be a significant challenge for the Company in view of the Company's relatively small size and its existing capital structure. The Company expects the financing to be accomplished through a combination of bank borrowings, the possibility of the assumption of the owners' debt, and the issuance of other debt securities. Such a financing would increase the Company's leverage substantially and could temporarily reduce the Company's ability to obtain external financing for other purposes, although the Company does not believe its external financing needs will be significant in the next several years.
The buyback agreement is contingent upon a number of conditions including negotiation of definitive documentation, the ability of the Company to obtain satisfactory financing arrangements, the securing of necessary governmental approvals (including approvals from the MPUC and the Federal Energy Regulatory Commission) and a satisfactory agreement between the Company and another utility to which the Company is currently reselling a portion of the electrical output from the plants. The anticipated closing date is June 1, 1995. After the closing, the Company will have no further obligation to purchase power from the plants and will not acquire any ownership interest in them.
Implications for Dividend Policy
As indicated in prior reports, the Company has recognized that the infusion of increased competition into the electric utility industry and the decreased reliance on traditional, rate-of-return regulation will likely cause changes in policies with respect to the payment of common stock dividends. The continuity of dividend payments that has been enjoyed in the past may be less certain, and dividend payment decisions are more likely to depend to a greater degree upon current profitability and the shorter-term prospects for growth in earnings.
During 1994, the Company maintained its common dividend payment even though it became apparent early on that the payout ratio would be high. This action was consistent with the Company's view that, to the extent possible, electric utilities in the transition to a more competitive business environment should attempt to maintain dividend levels and utilize future earnings growth to evolve to more conservative payout ratios. While the Company continues to believe that to be an appropriate policy, it also believes that factors have combined that could likely result in a reduction of the Company's common dividend in 1995.
As discussed above, the MPUC's decision to allow the Company more pricing flexibility acknowledged the Company's commitment to attempt to avoid general rate increases. The MPUC's support for the Company's efforts adds to the Company's resolve to avoid such rate increases for the near-term future. Taking this factor in conjunction with generally lower-than-expected growth in sales and revenues in 1994 and so far in 1995 and the fact that it will take some time for the newly-granted pricing flexibility to have an impact, the Company does not believe that its current prospects for earnings can support a common dividend at the same level as that paid in 1994.
Moreover, the financing of the contract buyback transaction discussed above may independently affect the Company's ability to maintain common dividends at the level paid in 1994. Although the Company believes the buyback transaction is in the best interests of the Company and its shareholders, and should enhance the Company's prospects for improved earnings sooner than if the transaction did not occur, the incurrence of the levels of additional debt necessary in order to accomplish the transaction could result in the imposition of conditions or covenants in the associated debt instruments that will be likely to restrict the Company's ability to pay common dividends at current levels while such debt is outstanding.
The Board of Directors has made no determination as to the timing or amount of any adjustment of the Company's common dividends.
CAPITAL REQUIREMENTS, CAPITAL RESOURCES AND LIQUIDITY
In order to meet future operational and service requirements, the Company has continuing needs for additional capital improvements. Over the last three years, capital expenditures have been $21.5 million in 1994, $33.6 million in 1993 and $24.3 million in 1992 (including overhead costs allocated to the capital program and an Allowance for Funds used During Construction ("AFDC") to recognize the costs of financing the program). In 1994, $2.0 million of the capital expenditures was related to the Company's power production facilities, $8.4 million was for its distribution system, and $6.4 million was for its transmission system with the remainder related to other general property and equipment, the cost of developing new information systems and costs associated with the licensing of new and the relicensing of existing hydroelectric projects. The 1992 and 1994 levels of capital expenditures are representative of the levels normally required to maintain the electrical system and meet other needs of the Company's customers. The 1993 expenditures included about $11.4 million for two major rehabilitation projects for the Company's hydroelectric system. The Company expects its capital expenditures to total about $55 million over the next three years, although it may be necessary to adjust the budget for capital expenditures on a year-to-year basis in view of the impact of the challenges described above upon the Company's ability to obtain financing.
In addition to requiring funds for capital improvements, the Company has from time to time required funds to finance "regulatory assets". Accounting rules applicable to regulated utilities allow the establishment of regulatory assets for costs accumulated for certain items other than the usual and customary capital assets, and allow the deferral of the income statement impact of those costs if they are expected to be recovered in future rates. As of December 31, 1994, the Company has regulatory assets of approximately $97.4 million. The Company believes that the cost of the proposed power contract buyback described above will also be recorded as a regulatory asset if the buyback transaction is consummated. The effects of competition could ultimately cause the operations of the Company, or a portion thereof, to cease meeting the criteria for application of the accounting rules for regulatory assets. If this were to occur, accounting standards of enterprises in general would apply and unamortized balances of regulatory assets would be charged to operations in the year in which those criteria were no longer applicable.
In addition to funds generated internally, the Company has met its capital needs through a combination of equity and debt securities and short-term credit facilities. In 1994 the Company raised approximately $14.1 million with the issuance and sale of 867,500 shares of common stock and approximately $1.3 million through the issue of 92,249 shares under the Dividend Reinvestment Plan. Also during 1994 the Company made $2.6 million in required and optional sinking fund payments on its 12.25% first mortgage bonds. External capital in 1993 and 1992 were provided by the issuance of 745,000 shares of common stock with proceeds of $14.8 million, the issuance of 109,710 common shares raising approximately $2.2 million under the Dividend Reinvestment Plan, and the issuance of three series of first mortgage bonds: a $15 million, 7.3% series maturing in 2003, a $20 million, 7.38% series maturing in 2002 and a $20 million, 8.98% series maturing in 2022. The bonds contain no provisions for sinking fund payments.
The Company's bank borrowings, which are provided through a $25 million revolving credit facility as well as $30 million in lines of credit, are discussed in more detail in Note 5 to the Financial Statements. These short-term credit arrangements are being used in part as interim financing for the Company's long-term capital needs. Effective May 26, 1994 the Company renegotiated its revolving credit agreement with the participating banks for a period of one year, with an option to renew for one additional year. The Company is presently engaged in discussions with its short-term lenders in connection with renewing the Company's short-term borrowing facilities and accommodating the proposed financing of the power contract buyback described earlier.
In 1995 the Company has $1.5 million in sinking fund payment requirements related to its 8.76% mandatory redeemable preferred stock. The Company's first mortgage bond indenture limits the issuance of first mortgage bonds to 75% of bondable property and requires earnings coverage of at least two-times pro forma annual first mortgage bond interest charges at the time the bonds are issued. Under these tests, at December 31, 1994, the Company could have issued approximately $53 million of additional first mortgage bonds at an assumed interest rate of 10%. The Company has $10.9 million of first mortgage bond sinking fund requirements and maturities in the period 1995-1999. The issuance of authorized but unissued common and preferred stock is not subject to any issuance tests contained in any of the Company's governing documents or agreements.
RESULTS OF OPERATIONS
Earnings per common share were $.84, $.63 and $1.60, and the earned return on average common equity was 5.5%, 4.0% and 10.6% for the years ended 1994, 1993 and 1992, respectively. In both 1994 and 1993, reported earnings reflected significant one-time charges. The Company charged approximately $2.8 million ($.24 per common share after taxes) to operations in the first quarter of 1994 as the cost of an early retirement program that is now providing savings in the form of reduced labor costs. In 1993 the Company established a reserve for the full amount of licensing costs spent through 1993 on the Basin Mills and Veazie hydroelectric projects. This reserve, which amounted to $8.7 million ($5.6 million after taxes), resulted in a $.95 reduction in earnings per common share after taxes for the year ended December 31, 1993.
The Company's total revenues and consequently its earnings are influenced to a large extent by the regulation of retail rates by the MPUC. Under Maine law, the Company has historically collected revenue from its customers separately through "base rates" and through a "fuel cost adjustment" (the "FCA" see the discussion above of the Company's Alternative Marketing Plan approved by the MPUC). Base rates are established from time to time in order to permit the Company an opportunity to recover its costs of providing electric service that are not included in the FCA, and to recover the investment, and earn a reasonable return thereon, in plant and equipment to provide that service. The FCA has also included the cost of the contracts with the non-utility independent power producers. The FCA was a positive or negative adjustment that was reconciled after the fact to reflect changes in the cost of fuel for generation and certain costs of purchased power. With the AMP order issued by the MPUC on February 14, 1995, the FCA was eliminated effective January 1, 1995.
On February 17, 1994, the MPUC issued an order allowing the Company, effective March 1, 1994, to increase its base rates by $11.1 million. This represented a 15.9% increase in base rates and an increase in average overall rates of 7.9%. More than half of the rate increase was designed to allow recovery of the costs associated with the buyout of the Beaver Wood purchased power contract, and it was offset to a large extent by a reduction in the fuel cost adjustment attributable directly to the buyout. The MPUC order provided an authorized return on common equity of 10.6%. However, the Company failed to earn that authorized return in 1994 primarily because the MPUC order was based upon an overly optimistic projection of energy sales, because the Company made certain pricing concessions to its customers as discussed above, and because of the one-time charge to reflect the cost of the early retirement program.
In conjunction with the FCA, the Company's regulators authorized the Company to use a deferred fuel accounting methodology under which fuel revenue essentially matched fuel expense. With the elimination of the FCA effective January 1, 1995, deferred fuel accounting has been eliminated and the Company has maintained its rates at existing levels. This change will require the Company to record, as expense, actual fuel costs incurred. The deferred fuel balance at December 31, 1994 appears on the balance sheet as a liability of $3.03 million. Based on the order from the MPUC, that liability will be amortized over a three-year period beginning January 1, 1995 as a reduction in fuel expense and will be a benefit to earnings.
The Company has experienced steadily increasing purchased power expenses from 1992 through 1994, due primarily to greater capacity and transmission costs associated with the Maine Yankee nuclear plant.
Other major increases in 1994 expenses included a $1.4 million increase in medical costs (including the full amount of expense for postretirement benefits in accordance with Financial Accounting Standards Board Statement No. 106 "Employers' Accounting for Postretirement Benefits Other Than Pensions" which was implemented on January 1, 1993 and included in rates beginning March 1, 1994) and $745,000 in amortization of certain deferred costs for which recovery was allowed in the most recent base rate order.
In 1993, O&M labor costs increased by $1.1 million over 1992 primarily because of an average wage increase of 3.5% effective January 1, 1993 and a higher allocation of labor costs to O&M activities than in 1992. Non-labor expense increased by $1.3 million, with major contributing factors including higher pension expenses, increased tree trimming activities, and accounting, legal and consulting expenses.
The Company's expenses over the period 1992-1994 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 base rates. Although there are a number of such authorized amortizations, the major ones are the allowable recovery of the Company's loss from its investment in the Seabrook nuclear power units (which it sold in 1986) and the costs associated with the 1993 termination of a purchased power contract with the Beaver Wood plant in Chester, Maine. The seven-year amortization of the Company's recoverable loss from its investment in the Seabrook Unit No. 2 nuclear plant was completed in 1992 and no longer affects income. In 1992 that amortization amounted to $968,000. The Company's recoverable loss from its investment in Seabrook Unit 1 is being amortized at a rate of $1.7 million per year beginning in 1986 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 contract termination at a rate of $3.9 million annually over a nine-year period.
AFDC decreased in 1994 relative to 1993 primarily because the Company ceased accruing carrying costs associated with the Beaver Wood purchased power contract termination when recovery was authorized by the MPUC on March 1, 1994, ceased accruing AFDC on costs related to the Basin Mills project, and experienced lower levels of construction activity. The 1993 AFDC was higher than 1992 principally because of the accruals for the Beaver Wood termination.
CONTINGENCIES
The Company has received notice from the Maine Department of Environmental Protection that it is investigating the cleanup of several sites in Maine that were used in the past for the disposal of hazardous substances and that the Company, as a generator of some of the hazardous substances that were disposed of on those sites, may be liable for certain cleanup costs. With respect to at least one of those sites, the Company is aware that the United States Environmental Protection Agency is considering designation under the Comprehensive Environmental Response, Compensation, and Liability Act in order to pursue potentially responsible parties. The Company was only one of a number of waste generators at each of the sites under investigation, and it is too early in the process to speculate on the extent of the Company's potential liability.
NEW ACCOUNTING STANDARDS
Effective January 1, 1994 the Company adopted Financial Accounting Standards Board Statement No. 112, "Employers' Accounting for Postemployment Benefits" ("FAS 112"). The effect of FAS 112 on the Company's results of operations and financial position was not material.
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.
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 includes 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, 1994, 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.
As of January 1, 1995, the Company's collections under the Fuel Cost Adjustment ("FCA") had exceeded its costs by approximately $3.03 million. With the elimination of the FCA, the MPUC recognized that there would no longer be a mechanism for the return of that sum to customers. The MPUC allowed the Company to retain that overcollection and ordered that the amount be amortized over a period of three years.
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 2.2% in 1994 and 2.1% in 1993 and 1992.
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 were 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, 1990) 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, advertising and research and development expenses are not significant. No royalty expenses were incurred.
Maintenance expense was $6.2 million in 1994, $6.5 million in 1993 and $5.6 million in 1992.
Equity Reserve for Licensed Hydro Projects-The Federal Energy Regulatory Commission ("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, 1994.
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. 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 9.2% in 1994, 10.0% for 1993 and 10.6% in 1992.
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.
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 liabilities. In accordance with FAS 109, the Company recorded net additional deferred income tax liabilities of approximately $23.7 million as of December 31, 1994 and $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 ($32.9 million and $32.5 million as of December 31, 1994 and 1993, 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 ($7.8 million and $8.1 million as of December 31, 1994 and 1993, respectively) and the establishment of deferred tax assets on unamortized investment tax credits ($1.4 million and $1.3 million as of December 31, 1994 and 1993, respectively). These latter amounts have been recorded as deferred regulatory liabilities at December 31, 1994 and 1993. 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 for the year ended December 31, 1994 and 1993 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, 1994 and 1993:
1994 1993 ----------- ----------- Deferred income tax liabilities: Excess book over tax basis of electric plant in service $42,117,768 $43,023,222 Costs to terminate purchased power contract 13,643,442 4,553,166 Deferred FERC licensing costs 3,158,378 3,431,075 Deferred fuel, purchased power and interest costs - 1,616,491 Deferred demand-side management program costs 16,677 1,055,030 Prepaid pension costs 593,290 1,028,179 Investment in jointly-owned companies 787,908 790,881 Other 1,534,435 2,434,532 ----------- ----------- $61,851,898 $57,932,576 ----------- -----------
Deferred income tax assets: Deferred taxes provided on alternative minimum tax $(4,463,203) $(3,175,718) Provision for Basin Mills investment (3,141,395) (3,137,895) Deferred state income tax benefit - (1,561,137) Unamortized investment tax credit (1,387,251) (1,286,156) Deferred fuel, purchased power and interest costs (1,365,750) - Reserve for bad debts (649,675) (797,696) Other (760,886) (973,195) ------------- ------------- $(11,768,160) $(10,931,797) ------------- -------------
Total other accumulated deferred income taxes $50,083,738 $ 47,000,779 ============= ============
The individual components of federal and state income taxes reflected in the Consolidated Statements of Income for 1994, 1993 and 1992 are stated in the table below:
Year Ended December 31, -------------------------------------- 1994 1993 1992 -------------------------------------- Current: Federal $ 1,287,485 - $6,274,554 State - - 2,739,089
-------------------------------------- $ 1,287,485 - $9,013,643 --------------------------------------
Deferred - Short-Term: Federal $ (797,919) $ 114,674 $4,330,124 State (296,436) 68,216 213,745 -------------------------------------- $(1,094,355) $ 182,890 4,543,869 --------------------------------------
Deferred - Long-Term: Federal - Other $ 3,003,171 $ 2,512,026 $(5,741,329) State - Other 753,782 (21,507) (1,806,238) Federal - Seabrook (339,620) (341,917) (653,060) State - Seabrook (72,127) (72,730) (139,336) -------------------------------------- $ 3,345,206 $ 2,075,872 $(8,339,963) -------------------------------------- Investment Tax Credits, Net $ 143,695 $ (178,176) $ 672,798 -------------------------------------- Total Provision $ 3,682,031 $ 2,080,586 $ 5,890,347 Allocated to Other Income (68,433) 2,682,359 (288,575) -------------------------------------- Charged to Operating Expense $ 3,613,598 $ 4,762,945 $ 5,601,772 ======================================
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.
1994 1993 1992 ----------- ----------- ---------- Amount % Amount % Amount % ------------------------------------
(Dollars in Thousands) ----------------------------------- Federal income tax provision at statutory rate $3,786 34% $2,522 34% $5,489 34% Less (Plus) temporary reductions in tax expense resulting from statutory exclusions from taxable income: Dividend received deduction related to earnings of associated companies 131 1 133 2 142 1 Equity component of AFDC 427 4 496 6 306 2 Amortization of equity component of AFDC on recoverable Seabrook investment (155) (1) (155) (2) (187) (2) Other 8 - (24) - 4 - ------ --- ------ ---- ----- ---- Federal income tax provision before effect of temporary differences $3,375 30% $2,072 28% $5,224 33% 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) (1) (146) (2) (193) (2) Book depreciation greater than tax depreciation on assets acquired before 1971 (292) (3) (292) (4) (293) (2) State income tax liability deducted for federal income tax purposes 131 1 116 2 467 4 Reversal of excess deferred income taxes 35 - 34 - 221 2 Other 350 3 253 4 139 1 ------- --- ------ --- ------ --- Federal income tax provision 3,297 30% $2,107 28% $4,883 30% ======= === ====== ==== ====== ===
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.
1994 1993 1992 ------------------------------------- Costs to terminate purchased power contract $7,206,794 $4,553,166 $ - Provision for Basin Mills - (3,137,895) - Seabrook Nuclear Project (411,747) (414,647) (792,396) Tax depreciation in excess of book depreciation 2,766,236 852,187 3,787,047 Deferred fuel and purchased power costs (2,834,587) 163,665 (8,443,906) State taxes provided for rate- making purposes but not paid 241,714 (124,217) 146,702 Deferred taxes provided on the AMT (1,287,485) - 268,254 Deferred interest costs 25,644 59,214 (209,149) Costs of removal 255,093 84,203 227,649 Deferred demand-side management costs (423,174) 97,672 284,297 FERC licensing costs (1,813,648) 277,574 835,487 Other (1,473,989) (152,160) 99,921 ------------ ----------- ----------- Total deferred income tax expense (benefit) $2,250,851 $2,258,762 $(3,796,094) ============ =========== ============
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 $4.5 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, 1994, the Company had, for income tax purposes, alternative minimum tax credits of approximately $4.5 million for the reduction of future tax liabilities. At December 31, 1994, the Company had, for income tax reporting purposes, approximately $3.2 million of net operating loss carryforwards that expire in 2008. In 1994 the Company utilized $15.6 million of tax net operating loss carryforwards and $322,000 of investment tax credits to reduce the alternative minimum tax liability for 1994.
Note 3 - Common and Preferred Stock
Common Stock-In June of 1994 the shareholders approved a proposal to increase the number of shares the Company is authorized to issue from 7,500,000 to 10,000,000 of which 7,185,143 were outstanding at December 31, 1994. 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-In June of 1994 the shareholders approved a proposal to increase the number of shares the Company is authorized to issue from 400,000 to 600,000 shares of which there are 197,340 shares outstanding. The remaining 402,660 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-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 Company 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, were to be considered a return of capital, the Company became 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, 1994 aggregate $10,914,264 as follows:
SINKING FUNDS CURRENT REQUIREMENTS MATURITIES TOTAL ------------- ------------- -------------
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 1999 1,675,205 - 1,675,205
------------ ------------- ------------- $8,414,264 $2,500,000 $10,914,264 ============ ============= =============
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, 1995 but may be extended to May 26, 1996 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 amended Credit Agreement, based on certificate of deposit loan rates, Eurodollar loan rates or the agent bank's reference rate. 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. A commitment fee based on the entire $25 million and ranging from 1/5 to 5/8 of 1% per annum, depending on the Company's long-term senior secured debt rating, is required.
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 to 3/8 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:
1994 1993 1992 ----------- ----------- ----------- Total credit available at end of period $55,000,000 $55,000,000 $55,000,000 Unused credit at end of period $28,000,000 $19,000,000 $40,000,000 Borrowings outstanding at end of period $27,000,000 $36,000,000 $15,000,000 Effective interest rate (exclusive of fees) on borrowings out- standing at end of period 6.0% 3.5% 4.3% Average daily outstanding bor- rowings for the period $26,035,616 $22,754,205 $22,448,087 Weighted daily average annual interest rate 4.6% 3.7% 4.5% Highest level of borrowings outstanding at any month- end during the period $38,000,000 $36,000,000 $31,000,000 =========== =========== ===========
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.
Note 6 - Postretirement and Other Postemployment Benefits
Postretirement 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 tables below detail the components of pension income for 1994, 1993 and 1992, the funded status of the plans, the amounts recognized in the Company's Financial Statements and the major assumptions used to determine these amounts. Employer contributions to the plans amounted to $1,174,019 in 1994. In 1994 and 1992 the Company implemented early retirement programs which resulted in additional pension expense of $1,608,267 and $786,000, respectively.
The plan's assets are composed of fixed income securities, equity securities and cash equivalents.
Total pension income included the following components:
1994 1993 1992 ----------- ----------- -----------
Service cost - benefits earned during the period $ 1,060,134 $ 1,085,419 $ 1,037,419 Interest cost on projected benefit obligation 2,310,455 2,244,706 1,996,491 Actual return on plan assets 377,447 (4,633,435) (2,366,341) Total of amortized obligations and the net gain (loss) deferred $(3,865,833) $ 1,291,310 $(1,015,783) ------------- ------------ ------------ Total pension (income) $ (117,797) $ (12,000) $ (348,214) ============= ============ ============
1994 1993 1992 ------------- ------------ -----------
Significant assumptions used were - Discount rate 8.25% 7.0% 8.0% Rate of increase in future compensation levels 5.0% 5.0% 6.0% Expected long-term rate of return on plan assets 9.0% 9.0% 9.0%
The following table sets forth the plans' funded status at December 31, 1994 and 1993:
1994 1993 ------------- ------------ Actuarial present value of accumulated benefit obligation Vested $ 21,668,455 $ 22,730,655 Non-vested 2,091,333 2,669,955 ------------- ------------ Total $ 23,759,788 $ 25,400,610 ------------- ------------ Projected benefit obligation $(31,179,979) $(32,484,893) Plan assets at fair value 36,397,435 37,810,748 ------------- ------------ Excess of plan assets over projected benefit obligation $ 5,217,456 $ 5,325,855 Items not yet recognized in earnings - Net (asset) at transition (5,984,125) (6,916,450) Prior service cost 5,653,162 4,597,483 Unrecognized net gain from past experience and changes in assumptions (2,804,366) (608,390) ------------- ------------- Net pension asset recognized $ 2,082,127 $ 2,398,498 ============= =============
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 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 required 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 in 1993 issued a final accounting rule in connection with FAS 106 which adopted this pronouncement for ratemaking purposes and provided the Company with the accounting and regulatory framework required to defer the excess of the net periodic postretirement benefit cost recognized under FAS 106 over the pay-as-you-go amount in 1993 through February 28, 1994, and to include such excess as a regulatory asset pending inclusion in the new base rates, effective March 1, 1994. This regulatory asset, which amounted to $705,283 at February 28, 1994, is being recovered, beginning March 1, 1994, over a ten-year period. The Company, also in accordance with the final accounting ruling, is amortizing the unrecognized transition obligation of $10,023,200 over a 20-year period. In 1994 the Company implemented an early retirement program which resulted in $750,000 of expense related to additional medical and life insurance benefits provided to the early retirees.
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, which commenced in July 1994, amounted to $755,000 in 1994.
The actuarially determined net periodic postretirement benefit cost for 1994 and 1993 and the major assumptions used to determine these amounts are shown below: 1994 1993 ---------- -----------
Service cost of benefits earned $379,400 $ 359,600 Interest cost on accumulated post- retirement benefit obligation 724,000 683,200 Actual return on plan assets (7,800) - Amortization of unrecognized transition obligation 501,200 501,200 Other deferrals, net (1,800) - Early retirement plan benefits 750,000 - ----------- ----------- Net periodic postretirement benefit cost $2,345,000 $1,544,000 =========== ===========
1994 1993 ----------- ----------- Significant assumptions used were - Discount rate 8.25% 7.0% Health care cost trend rate, employees less than age 65- Near-term 9.0% 12.4% Long-term 4.5% 6.0% Health care cost trend rate, employees greater than age 65- Near-term 7.0% 9.7% Long-term 4.5% 5.8% Rate of return on plan assets 2.0% N/A
The following table sets forth the benefit plan's funded status at December 31, 1994 and 1993:
1994 1993 ---------- --------- Accumulated postretirement benefit obligation: Retirees $7,746,800 $ 5,640,000 Fully eligible active plan participants 446,400 773,000 Other active participants 3,020,900 4,196,000 ---------- ----------- $11,214,100 $10,609,000 Fair value of plan assets (409,500) -
Unrecognized net transition obligation (9,020,800) (9,522,000) Unrecognized gain (loss) 566,423 (77,900) ------------ ------------ Accrued postretirement benefit cost (included in Other Reserves) $2,350,223 $ 1,009,100 ============ ============
If the health care cost trend rate was increased one percent, the accumulated postretirement benefit obligation as of January 1, 1994 would have increased by 11.7%. The effect of such change on the aggregate of service and interest cost for 1994 would be an increase of 13.3%.
Postemployment Benefits-Effective January 1, 1994 the Company adopted Financial Accounting Standards Board Statement No. 112 "Employers' Accounting for Postemployment Benefits" (FAS 112). The effect of FAS 112 on the Company's results of operations and financial position was not material.
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. Estimated costs of decommissioning the Maine Yankee plant assuming dismantlement and removal is $317 million (in 1993 dollars) of which the Company's share is approximately $22.2 million.
The estimated cost of decommissioning is subject to change due to evolving technology and the possibility of new legal requirements. Accumulated decommissioning funds at December 31, 1994 were $108.7 million of which the Company's share was approximately $7.6 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. Several New England utilities, including the Company and MEPCO's other stockholders (two other Maine utilities), 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 below.
MAINE YANKEE (Dollars in Thousands) ------------------------------------ 1994 1993 1992 -------- --------- --------- OPERATIONS: As reported by investee - Operating Revenue $173,857 $193,102 $187,259 ------------------------------------ Depreciation $30,823 $ 25,458 $ 24,462 Interest and Preferred Dividends 14,583 14,407 14,092 Other expenses, net 121,437 145,861 140,311 ------------------------------------ Operating expenses $166,843 $185,726 $178,865 ------------------------------------ Earnings Applicable to Common Stock $ 7,014 $ 7,376 $ 8,394 ==================================== Amounts Reported by the Company - Purchased power costs $ 11,771 $ 11,265 $ 10,830 Equity in net income (480) (542) (592) ------------------------------------ Net purchased power expense $ 11,291 $ 10,723 $ 10,238 ====================================
FINANCIAL POSITION: As reported by investee - Plant in service $401,092 $396,133 $ 384,664 Accumulated depreciation (192,293) (175,996) (163,887) Other assets 341,111 314,680 300,416 ------------------------------------ Total assets $549,910 $534,817 $ 521,193 Less - Preferred stock 19,200 19,800 20,400 Long-term debt 118,666 115,333 110,390 Other liabilities and deferred credits 344,550 332,030 322,900 ------------------------------------ Net assets $ 67,494 $ 67,654 $ 67,503 ==================================== Company's reported equity - Equity in net assets $ 4,725 $ 4,736 $ 4,725 Adjust Company's estimate to actual 29 20 11 ------------------------------------ Equity in net assets as reported $ 4,754 $ 4,756 $ 4,736 ====================================
MEPCO (Dollars in Thousands) ----------------------------------- 1994 1993 1992 -------- -------- --------
OPERATIONS: As reported by investee - Operating Revenue $ 24,746 $ 12,809 $ 11,608 ----------------------------------- Depreciation $ 1,383 $ 1,395 $ 1,250 Interest and Preferred Dividends 106 124 186 Other expenses, net 23,152 11,185 10,067 ----------------------------------- Operating expenses $ 24,641 $ 12,704 $ 11,503 ----------------------------------- 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 $ 23,099 $ 23,123 $ 22,915 Accumulated depreciation (20,463) (19,174) (17,891) Other assets 3,927 2,414 1,815 ---------------------------------- Total assets $ 6,563 $ 6,363 $ 6,839
Less - Preferred stock - - - Long-term debt 1,730 2,590 3,450 Other liabilities and deferred credits 3,955 2,895 2,511 ---------------------------------- Net assets $ 878 $ 878 $ 878 ================================== Company's reported equity - Equity in net assets $ 125 $ 125 $ 125 Adjust Company's estimate to actual - - - ---------------------------------- Equity in net assets as reported $ 125 $ 125 $ 125 ==================================
Wyman 4-The Company owns 8.33% (50 MW) of the oil-fired 600 MW Wyman Unit No. 4 in Yarmouth, Maine. The Company's proportionate share of the direct expenses of this unit is included in the corresponding operating expenses in the Statements of Income. Included in the Company's utility plant are the following amounts with respect to this unit:
1994 1993 1992 ------------ ------------ ------------
Electric plant in service $16,771,430 $16,767,909 $16,760,816 Accumulated depreciation (7,996,737) (7,539,591) (7,025,278) ------------ ------------ ------------ $ 8,774,693 $ 9,228,318 $ 9,735,538 ============ ============ =============
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 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 a static var compensator ("SVC"), which is electrical equipment that supports the Phase 2 transmission line. A wholly-owned subsidiary of Central Maine Power Company owns the other 50% interest in Chester. Chester has financed the acquisition and construction of the SVC through the issuance of $33 million in principal amount of 10.48% senior notes due 2020, and up to $3.25 million principal amount of additional notes due 2020 (collectively, the "SVC Notes"). The holders of the SVC Notes are without recourse against the partners or their parent companies and may only look to Chester and to the collateral for payment.
The New England utilities which participate in Phase 2 have agreed under a FERC-approved contract to bear the cost of Chester, on a cost of service basis, which includes a return on and of all capital costs.
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 hydroelectric 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 had been recorded as of December 31, 1993. Effective with the implementation of new base rates on March 1, 1994, the Company began recovering over a nine-year period the deferred balance, net of the additional $6 million anticipated from Beaver Wood. In July 1994 Beaver Wood made its second $1 million payment.
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 has entered into an agreement with the owners of these facilities to buy out these contracts for approximately $163 million. See Note 14 to the Financial Statements. 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 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.
Basin Mills and Veazie Projects-As a result of increased uncertainty about the recoverability of amounts invested through 1993 in licensing activities for proposed additional hydroelectric facilities, the Company established a reserve against those investments in the amount of $8.7 million as of December 31, 1993. Further, the Company has charged to non-operating expenses all amounts related to these licensing activities in 1994. The projects for which the reserve was 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.
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 of the unamortized balances. As of December 31, 1992, the Company's investment in Seabrook Unit 2 was fully amortized.
Note 9 - Contingencies
Environmental Matters-The Company has received notice from the Maine Department of Environmental Protection that it is investigating the cleanup of several sites in Maine that were used in the past for the disposal of hazardous substances and that the Company, as a generator of some of the hazardous substances that were disposed of on those sites, may be liable for certain cleanup costs. With respect to at least one of those sites, the Company is aware that the United States Environmental Protection Agency is considering designation under the Comprehensive Environmental Response, Compensation, and Liability Act in order to pursue potentially responsible parties. The Company was only one of a number of waste generators at each of the sites under investigation, and it is too early in the process to speculate on the extent of the Company's potential liability.
Note 10. Unaudited Quarterly Financial Data
Unaudited quarterly financial data pertaining to the results of operations are shown below: Quarter Ended --------- --------- --------- -------- Mar. 31 June 30 Sept. 30 Dec.31 --------- --------- --------- -------- (Dollars in thousands except per share amounts)
---- Electric Operating Revenue $46,375 $39,664 $42,575 $45,484 Operating Income 3,037 4,550 5,589 4,157 Net Income 1,095 2,008 3,073 1,282 Earnings Per Share of Common Stock $ .11 $ .22 $ .37 $ .12 ======= ======= ======= =======
---- Electric Operating Revenue $49,679 $40,548 $43,476 $44,269 Operating Income 4,779 4,486 4,396 3,168 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 ======= ======= ======= =======
* Includes the provision for Basin Mills of $5.6 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, 1994 of each class of financial instruments for which it is practical to estimate the value:
Cash and cash equivalents:
The carrying amount of $1,956,159 approximates fair value.
The fair values of mandatory redeemable cumulative preferred stock, first mortgage bonds and pollution control revenue bonds at December 31, 1994 based upon similar issues of comparable companies are as follows:
In Thousands ------------------- Carrying Fair Amount Value -------------------
Mandatory redeemable cumulative preferred stock $ 15,240 $ 15,857 First Mortgage Bonds 113,628 116,678 Pollution Control Revenue Bonds 4,200 4,200 ===================
Note 12 - Significant Non-Cash Investing and Financing Activity
In connection with the termination of the purchased power agreement in 1993 with the Beaver Wood Joint Venture, the Company issued $14.3 million of 12.25% First Mortgage Bonds in substitution for Beaver Wood's previously outstanding secured notes which is not reflected in the Statements of Cash Flows.
Note 13 - Regulatory Assets
Accounting rules applicable to regulated utilities allow the establishment of regulatory assets for costs accumulated for certain items other than the usual and customary capital assets, and allow the deferral of the income statement impact of those costs if they are expected to be recovered in future rates. As of December 31, 1994, the Company has regulatory assets of approximately $97.4 million. The effects of competition could ultimately cause the operations of the Company, or a portion thereof, to cease meeting the criteria for application of the accounting rules for regulatory assets. If this were to occur, accounting standards of enterprises in general would apply and unamortized balances of regulatory assets would be charged to operations in the year in which those criteria were no longer applicable.
Note 14 - Alternative Marketing Plan
On February 14, 1995, the MPUC issued an order approving many aspects of the Company's Alternative Marketing Plan ("AMP") proposal. The AMP proposal included a plan for allowing increased flexibility to offer reduced prices and develop related marketing programs, a commitment to attempt to cap electric rates at current levels for an extended period, the elimination of fuel cost accounting and the fuel adjustment clause, the elimination of seasonal rate differentials and an understanding about the method of amortizing the cost of any future buyout of high-cost purchased power contracts.
Note 15 - Buyback of Purchased Power Contracts
The Company has reached an agreement in principle to buy back two contracts for the purchase of power from operators of biomass-fueled generating plants located in West Enfield and Jonesboro, Maine. Both power vendors are high-cost non-utility independent power producers with whom the Company was required to contract in the 1980's. The power contracts, identical in their terms and conditions, provide for the purchase of the entire generation output of each of the facilities. Each plant has a rated capacity of 24.5 MW. Power purchases began in 1986 and are scheduled under the contracts to continue for a period of approximately 30 years from the date of the initial purchases.
The buyback agreement calls for a cash payment by the Company of $83 million ($41.5 million per plant) and for the Company to assume responsibility for the remaining debt on the plants in a manner that relieves the owners of any further obligations on such debt. The balance of the outstanding debt is expected to be about $79 million in total at the time of the closing. If the lenders are unwilling to permit the assumption by the Company of such debt on terms acceptable to the Company and the owners, the Company would be required to increase the cash portion of the buyback by an amount sufficient to discharge the owners' debt in order for the buyback to be accomplished. In addition, the Company will be responsible for costs of preparing for a closing of the transaction and may incur significant costs in obtaining the necessary financing. The Company will be obliged to pay some portion of such costs whether or not a closing occurs. Financing this transaction will be a significant challenge for the Company in view of the Company's relatively small size and its existing capital structure. The Company expects the financing to be accomplished through a combination of bank borrowings, the possibility of the assumption of the owners' debt, and the issuance of other debt securities.
With the elimination of the FCA, reduced fuel cost benefits of any buyout will inure to the benefit of the Company and may be used to recover the amortization of the buyout cost. The Company believes that the fuel and energy cost savings achieved by such a buyout, previously subject to the FCA, would exceed any costs of such a buyout, including carrying costs on the unamortized balance. Bangor Hydro-Electric Company
Notes To Consolidated Financials Statements
16. Subsequent Event - Maine Yankee
Steam Generator Tube Cracking - The Maine Yankee unit, like other pressurized water reactors, has been experiencing degradation of its steam generator tubes, principally in the form of circumferential cracking, which, until early 1995, was believed to be limited to a relatively small number of steam generator tubes. In the past the detection of defects has resulted in the plugging of those tubes to prevent their subsequent use. During the refueling and maintenance shutdown that commenced in early February of 1995, Maine Yankee has detected increased degradation of the plant's steam generator tubes, in excess of the number expected, and is currently evaluating several courses of action to address the matter. This detection of a significantly larger number of degraded tubes is likely to adversely affect the operation of the plant and may result in substantial cost to the Company. The Company cannot now predict what course of action will be chosen or to what extent the operation of the plant will be affected. The Company believes, however, that Maine Yankee will not resume generation as originally scheduled in April, 1995 and that an extended outage lasting at least several months is likely.
In connection with the approval by the MPUC of the Company's alternative marketing plan, effective January 1, 1995, the separate fuel cost adjustment rates were eliminated. The fuel cost adjustment was a rate mechanism under which the Company was permitted to adjust retroactively for changes in the cost of fuel for generation and in certain purchased power costs. Accordingly, with the fuel cost adjustment mechanism in place, the cost of power purchased from another source to replace that which had been expected from Maine Yankee would have had no impact on earnings.
The Company estimates that, under current conditions in the bulk power market, its power costs will be increased by $700,000 to $900,000 per month during the Maine Yankee outage, which will increase pressure on the Company's earnings. In addition, the Company would be responsible for its pro rata share of any costs associated with repairing or mitigating the impact of the degraded tubes. The Company believes that it is too early to provide reliable estimates of such costs but that they could be substantial.
REPORT OF INDEPENDENT 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, 1994 and 1993, and the related consolidated statements of income, retained earnings, and cash flows for each of the three years in the period ended December 31, 1994. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits 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, 1994 and 1993, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 1994, 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.
/s/ Coopers & Lybrand L.L.P.
Coopers & Lybrand L.L.P.
Boston, Massachusetts March 2, 1995, except as to the information presented in Note 16 for which the date is March 29, 1995.
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 17, 1995, 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 17, 1995, 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 17, 1995, 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 17, 1995, which information is incorporated herein by reference.
(c) Changes in Control
Not applicable.
ITEM 13 CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS ------- ----------------------------------------------
See the information under "Compensation Committee Interlocks and Insider Participation" in the Company's definitive proxy statement for the annual meeting of stockholders to be held on May 17, 1995, 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, 1994, 1993 and 1992
Consolidated Balance Sheets - December 31, 1994 and
Consolidated Statements of Retained Earnings for the Years ended December 31, 1994, 1993 and 1992
Consolidated Statements of Capitalization - December 31, 1994 and 1993
Consolidated Statements of Cash Flows for the Years Ended December 31, 1994, 1993 and 1992
Notes to Consolidated Financial Statements
Report of Independent Accountants
(b) Schedules
Report of Independent Accountants
Schedule VIII - Reserves for Doubtful Accounts and Insurance
All other schedules are omitted as the required information is inapplicable or the information is presented in the Company's consolidated financial statements or related notes.
(c) Exhibits
See Exhibit Index, page
(d) Reports on Form 8-K
No Current Reports on Form 8-K were filed during the Fourth Quarter of 1994.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Bangor Hydro-Electric Company
/s/ Robert S. Briggs --------------------- By: Robert S. Briggs President and Chairman of the Board
Pursuant to the requirements of the Securities and Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
/s/ Robert S. Briggs /s/ Helen Sloane Dudman --------------------------- -------------------------- Robert S. Briggs Helen Sloane Dudman President and Director Chairman of the Board
/s/ William C. Bullock, Jr. /s/ G. Clifton Eames --------------------------- -------------------------- William C. Bullock, Jr. G. Clifton Eames Director Director
/s/ Robert H. Foster --------------------------- -------------------------- Jane J. Bush Robert H. Foster Director Director
/s/ Carroll R. Lee --------------------------- -------------------------- David M. Carlisle Carroll R. Lee Director Director, Vice President- Operations
/s/ Alton E. Cianchette /s/ Robert C. Weiser --------------------------- -------------------------- Alton E. Cianchette Robert C. Weiser Director Chief Financial Officer
/s/ David R. Black --------------------- David R. Black Controller (Chief Accounting Officer)
Each of the above signatures is affixed as of March 20, 1995.
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 in Item 8