Item 1. BUSINESS.
Introduction
General. Central Maine Power Company (the "Company") is an investor-owned Maine public utility incorporated in 1905. The Company is primarily engaged in the business of generating, purchasing, transmitting, distributing and selling electric energy for the benefit of retail customers in southern and central Maine and wholesale customers, principally other utilities. The Company is also diversifying into new lines of business, largely through its subsidiaries. See "Competition - Expansion of Lines of Business", below. Its principal executive offices are located at 83 Edison Drive, Augusta, Maine 04336, where its general telephone number is (207) 623-3521.
The Company is the largest electric utility in Maine, serving approximately 521,000 customers in its 11,000 square-mile service area in southern and central Maine and having $967 million in consolidated electric operating revenues in 1996 (reflecting consolidation of financial statements with a majority-owned subsidiary, Maine Electric Power Company, Inc. ("MEPCO")). The Company's service area contains the bulk of Maine's industrial and commercial centers, including Portland (the state's largest city), South Portland, Westbrook, Lewiston, Auburn, Rumford, Bath, Biddeford, Saco, Sanford, Kittery, Augusta (the state's capital), Waterville, Fairfield, Skowhegan and Rockland, and approximately 943,000 people, representing about 77 percent of the total population of the state. The Company's industrial and commercial customers include major producers of pulp and paper products, producers of chemicals, plastics, electronic components, processed food, and footwear, and shipbuilders. Large pulp-and-paper industry customers account for approximately 62 percent of the Company's industrial sales and approximately 25 percent of total service-area sales.
Nuclear Plant Outages. In 1996 the Company incurred substantially higher costs associated with its investments in nuclear generating units, particularly the 879-megawatt unit owned and operated by Maine Yankee Atomic Power Company ("Maine Yankee") in Wiscasset, Maine, (the "Maine Yankee Plant" or the "Plant") and expects even higher costs in 1997 to have a significant effect on the Company's financial results for 1997. For a complete discussion of the regulatory and operational problems causing such higher Maine Yankee costs, see "Maine Yankee Atomic Power Company," below, and Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations."
1996 Results. The Company generated net earnings of $60.2 million in 1996, compared to net earnings of $38.0 million in 1995. The earnings applicable to common stock was $50.8 million, or $1.57 per share in 1996, compared to earnings applicable to common stock of $27.8 million, or $0.86 per share, in 1995.
Electric operating revenues increased by $51.0 million, or 5.6 percent, to $967 million in 1996. Total service-area sales increased by 2.9 percent in 1996, with residential sales increasing by 1.0 percent, commercial sales increasing by 0.5 percent, industrial sales increasing by 4.0 percent, and the small wholesale and lighting category increasing by 58.9 percent. The primary factors in the service-area kilowatt-hour sales increase were residential customers' taking advantage of the Company's water heating program, increased sales in the pulp and paper industry, and the addition of a wholesale customer. The decreases in 1995 and 1994 were attributed to low economic growth, the loss of a major industrial customer in September 1994, energy management, and loss of sales due to conversions from electricity to alternative fuels for such purposes as space and water heating.
In order to compete effectively in an increasingly competitive electric utility industry, the Company is pursuing a strategy based on stabilizing its price of electricity, in real terms, through the rest of the decade. To accomplish that goal, the Company in 1996 continued its efforts to control costs, which became a much greater challenge because of the nuclear plant outages, reduce its costs of non-utility purchased power, and expand its lines of business. Significant progress was made in stabilizing rates with the adoption effective January 1, 1995, of the Alternative Rate Plan (the "ARP"), which contains inflation-based price caps, additional pricing flexibility, and efficiency incentives. In addition, as a result of the ARP the Company was able to enter into five-year reduced-price contracts over the last two years with a number of its largest customers designed to ensure that those customers would remain on the Company's system over the five-year period. The Company has used the pricing flexibility provision in the ARP to provide new rates to approximately 19,000 customers, representing approximately 40 percent of annual kilowatt-hour sales and 27 percent of service-area revenues.
The Company is actively supporting electric industry restructuring efforts now under consideration by the Maine Legislature. This is part of a national trend to change the electric industry over time into a more competitive industry. A primary goal of this effort is to provide customers with greater choices in the terms, conditions and suppliers of their electric power needs. While many aspects of the transition are uncertain, the transition to direct retail competition could have substantial impacts on the value of utility assets and on the ability of electric utilities to recover their costs through rates. Without effective action by legislators and regulators, utilities could find their above-market costs to be "stranded," or unrecoverable, in the new competitive setting. The Company has substantial exposure to cost stranding relative to its size. See "Competition" and "Restructuring and Strandable Costs," below, for more information on this subject.
Maine Yankee, the ARP, restructuring, strandable costs, and other significant developments are discussed in succeeding sections of this report. In some cases more complete information is included in Management's Discussion and Analysis of Financial Condition and Results of Operations, which appears in Item 7 of this report, or in the Notes to Consolidated Financial Statements for the year ended December 31, 1996, which appear in Item 8 of this report. In those cases Item 7 and 8 should be read in conjunction with the sections below for a full discussion of the subjects covered in that manner.
The following topics are discussed under the general heading of Business. Where applicable, the discussions make reference to the various other Items of this report. In addition, for further discussion of information required to be furnished in response to this Item, see Items 7 and 8.
Topic Page
Regulation and Rates 3 Competition 4 Restructuring and Strandable Costs 5 Non-utility Generation 5 Maine Yankee Atomic Power Company 6 Financing and Related Considerations 7 Environmental Matters Water Quality Control 9 Air Quality Control 9 Hazardous Waste Regulations 9 Electromagnetic Fields 10 Capital Expenditures 10 Employee Information 10
Regulation and Rates
General. The Company is subject to the regulatory authority of the Maine Public Utilities Commission (the "MPUC" or the "PUC") as to retail rates, accounting, service standards, territory served, the issuance of securities maturing more than one year after the date of issuance, certification of generation and transmission projects and various other matters. The Company is also subject to the jurisdiction of the Federal Energy Regulatory Commission ("FERC") under Parts I, II and III of the Federal Power Act for some phases of its business, including licensing of its hydroelectric stations, accounting, rates relating to wholesale sales and to interstate transmission and sales of energy and certain other matters. Other activities of the Company from time to time are subject to the jurisdiction of various other state and federal regulatory agencies.
The Maine Yankee Plant and the other nuclear facilities in which the Company has an interest are subject to extensive regulation by the federal Nuclear Regulatory Commission ("NRC"). The NRC is empowered to authorize the siting, construction and operation of nuclear reactors after consideration of public health, safety, environmental and antitrust matters. Under its continuing jurisdiction, the NRC may, after appropriate proceedings, require modification of units for which construction permits or operating licenses have already been issued, or impose new conditions on such permits or licenses, and may require that the operation of a unit cease or that the level of operation of a unit be temporarily or permanently reduced.
The United States Environmental Protection Agency ("EPA") administers programs which affect the Company's thermal and hydroelectric generating facilities as well as the nuclear facilities in which it has an interest. The EPA has broad authority in administering these programs, including the ability to require installation of pollution-control and mitigation devices. The Company is also subject to regulation by various state, local and other federal authorities with regard to environmental matters and land use. For further discussion of environmental considerations as they affect the Company, see "Environmental Matters", below.
Under the Federal Power Act, the Company's hydroelectric projects (including storage reservoirs) on navigable waters of the United States are required to be licensed by the FERC. The Company is a licensee, either by itself or in some cases with other parties, for 26 FERC-licensed projects, some of which include more than one generating unit. Thirteen licenses expired in 1993, one expires in 1997, and fourteen after 2000. The Company has filed all applications for relicensing the projects whose licenses were scheduled to expire in 1993 and has been authorized to continue to operate those projects pending action on relicensing by the FERC. Of the thirteen projects with licenses which expired in 1993, ten are operating under annual licenses, one project is operating under a new license issued in 1993, one license was allowed to expire, and one project was sold. New licenses may contain conditions that reduce operating flexibility and require substantial additional investment by the Company.
The United States has the right upon or after expiration of a license to take over and thereafter maintain and operate a project upon payment to the licensee of the lesser of its "net investment" or the fair value of the property taken, and any severance damages, less certain amounts earned by the licensee in excess of specified rates of return. If the United States does not exercise its statutory right, the FERC is authorized to issue a new license to the original licensee, or to a new licensee upon payment to the original licensee of the amount the United States would have been obligated to pay had it taken over the project. The United States has not asserted such a right with respect to any of the Company's licensed projects.
Rate Regulation. Effective January 1, 1995, rate regulation for the Company underwent a fundamental change with the implementation of the ARP, which replaced traditional regulation. Instead of rate changes based on the level of costs incurred and capital investments, the ARP provides for one annual adjustment of an inflation-based cap on each of the Company's rates, with no separate reconciliation and recovery of fuel and purchased-power costs. Under the ARP, the MPUC is continuing to regulate the Company's operations and prices, provide for continued recovery of deferred costs, and specify a range for its rate of return. The MPUC confirmed in its order approving the ARP that the ARP is intended to comply with the provisions of Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation." See Note 3 of Consolidated Financial Statements for more information on the ARP.
Competition
General. In 1992 the United States Congress enacted the Energy Policy Act of 1992 (the "Policy Act"). The Policy Act was designed to encourage competition among electric utility companies, improve energy resource planning by utility companies, and encourage the development of alternative fuels and sources of energy. The Policy Act provides for, among other things, enhanced access to electric transmission to promote competition for wholesale purchasers and sellers. The Policy Act has combined with regulatory development to create new areas of competition for the Company, resulting in more options for its wholesale and retail customers. Even though the Company's customers are at present generally unable to seek direct service from another utility, some can curtail usage, switch fuels, install their own generation, cancel plans to expand their operations, or even leave the Company's service territory. In response to those threats, the Company has initiated several programs, including the implementation of special rates to maintain or increase employment at specific large customers' plants and incremental-energy rates to avoid losing specific groups of customers to other energy sources. In addition, the Company has redesigned some rates to encourage off-peak usage and discourage switching to alternative fuels. See Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations," and Notes 3 and 4 to Consolidated Financial Statements for more information.
Expansion of Lines of Business. The Company is also preparing for competition by expanding its business opportunities through subsidiaries that capitalize on core competencies. One such subsidiary, MaineCom Services ("MaineCom") is developing opportunities in expanding markets by arranging fiber-optic data service for bulk carriers, offering support for cable-TV or "super-cellular" personal-communication vendors, and providing other telecommunications services. The Company invested $10.7 million in MaineCom during 1996 to develop an interchange network from Portland, Maine, to various points in New Hampshire, Massachusetts and Connecticut. In addition, the Company has subsidiaries or divisions that provide energy-efficiency services, utility consulting (domestic and international) and research, engineering and environmental services, management of rivers and recreational facilities, locating of underground utility facilities and infrared photography, real estate brokerage and management, modular housing, and credit and collection services. All subsidiaries utilize skills of former Company employees and compete for business with other companies.
In July 1996, the Company and Maine Electric Power Company, Inc. (MEPCO), a 78 percent-owned subsidiary of the Company, entered into option agreements with Maritimes and Northeast Pipeline, L.L.C. (M&N) in which the Company and MEPCO agreed to provide exclusive options to M&N to acquire property interests in certain transmission line rights of way to sections of M&N's proposed natural gas pipeline from the United States-Canada border at Woodland, Maine, to Dracut, Massachusetts. In November 1996, while the parties were still engaged in negotiating the terms of the proposed long-term arrangement, the options expired by their terms. Subsequent to the expiration the parties have met to discuss a long-term arrangement for use of the Company's and MEPCO's rights of way for the proposed pipeline, but the Company cannot predict whether final agreement on such an arrangement will be reached.
Restructuring and Strandable Costs
The enactment by Congress of the Policy Act accelerated planning by electric utilities, including the Company, for a transition to a more competitive industry. The functional areas in which competition will take place, the regulatory changes that will be implemented, and the resulting structure of both the industry and the Company are still uncertain, but regulatory, and in some states, legislative steps have already been taken toward competition in generation and non-discriminatory transmission access. A departure from traditional regulation could have substantial impacts on the value of utility assets and on the ability of electric utilities to recover their costs through rates. In the absence of full recovery, utilities would find their above-market costs to be "stranded," or unrecoverable, in the new competitive setting. The Company is pursuing efforts to mitigate its exposure to stranded costs through securitization of regulatory assets. For further discussion of this issue, see Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations."
Non-utility Generation
After enactment of the federal Public Utility Regulatory Policies Act of 1978 ("PURPA") and companion legislation in Maine, the Company became an industry leader in developing supplies of energy from non-utility generators ("NUGs"), including cogeneration plants and small power producers. These sources supplied 3.8 billion kilowatt-hours of electricity to the Company in 1996, representing 32 percent of total generation, a decrease from 37 percent in 1995 when Maine Yankee was out of service for most of the year. The Company's contracts with non-utility generators, however, which were entered into pursuant to the mandates of PURPA and vigorous state implementation of its policies, have contributed the largest part of the Company's increased costs and the resulting rate increases in recent years prior to implementation of the ARP in 1995, and constitute the largest part of the Company's strandable costs.
PURPA provided substantial economic incentives to NUGs by allowing cogenerators and small power producers to sell their entire electrical output to an electric utility at the utility's avoided-cost rate, which has often been substantially higher than market rates, while purchasing their own electric energy requirements at the utility's established rate for that customer class. Thus the Company in a number of cases has been required to pay a higher price for energy purchased from a NUG than the NUG, which in some cases is a large customer of the Company, has paid the Company for the NUG's energy requirements. In addition, with the recent surplus of relatively low-cost power in the New England market, prices paid by the Company under NUG contracts have often been well above current wholesale market prices.
The Company's NUG contracts generally have had terms of five to 30 years, and expiration dates ranging from 1997 to 2021. They require the Company to purchase the energy at specified prices per kilowatt-hour. As of December 31, 1996, facilities having 573 megawatts of capacity covered by these contracts were in service. The costs of purchases under all of these contracts amounted to $313.4 million in 1996, $314.4 million in 1995, and $373.5 million in 1994.
Because of the upward price pressure resulting in large part from costs associated with its NUG contracts, the Company has taken steps to reduce those costs. In recent years the Company has reached agreement with a number of NUGs to buy out their contracts or to give the Company options to restructure their contracts through lump-sum or periodic payments. The Company restructured 40 contracts representing 316 megawatts of capacity that the Company believes should result in approximately $301 million in fuel savings over the next five years.
Pursuant to one NUG contract buy-out, Aroostook Valley Electric Company ("AVEC"), a wholly-owned subsidiary of the Company, acquired a 33-megawatt wood-fired generating plant in Fort Fairfield, in northern Maine. AVEC reduced the operating costs of the plant and, after competitive bidding, was awarded a 12.5-megawatt contract to supply the Town of Houlton municipal electric utility, which is outside the Company's retail service territory, at wholesale for ten years starting January 1, 1996.
In accordance with prior MPUC policy and the ARP, $113 million of buyout or restructuring costs since January 1992 has been included in Deferred Charges and Other Assets on the Company's balance sheet and will be amortized over their respective fuel savings periods. The Company will continue to seek opportunities to reduce its NUG costs, but cannot predict what level of additional savings it will be able to achieve. In October 1997 a contract with a major NUG supplier will expire, which should result in annual savings of approximately $25 million for the Company.
Maine Yankee Atomic Power Company
The Company owns a 38 percent stock interest in Maine Yankee, which owns and operates the Maine Yankee Plant and is entitled under a cost-based power contract to an approximately equal percentage of the Plant's output. The Plant has been in commercial operation since 1972 and, through 1994, generally produced power at a cost among the lowest in the country for nuclear plants.
The Maine Yankee Plant was shut down for eleven months in 1995 for repairs to its steam generator tubes. The Plant returned to service in January 1996 at 90 percent of its operating capacity. On December 6, 1996, the plant was shut down for inspection and repairs, and is expected to remain out of service at least until August 1997. During this time, Maine Yankee must replace 92 fuel assemblies, conduct an intensive inspection of its steam generators, resolve cable-separation issues and other regulatory issues, as well as any additional issues that are discovered during the outage, and obtain the approval of the NRC to restart the plant. In addition, Maine Yankee will make use of the outage to inspect the Plant's steam generators, commencing approximately April 1, 1997, for deterioration beyond that which was repaired during the extended 1995 outage. Degradation of steam generators of the age and design of those in use in the Plant has been identified at other plants. If major repairs to, or replacement of, the steam generators were found to be necessary for continued operation of the Plant, Maine Yankee would review the economics of continued operation before incurring the substantial capital expenditures that would be required.
On January 29, 1997, the NRC announced that it had placed the Plant on its "watch list" in "Category 2", which includes plants that display "weaknesses that warrant increased NRC attention", but which are not severe enough to warrant a shut-down order. Plants in category 2 remain in that category "until the licensee demonstrates a period of improved performance." The Plant is one of fourteen nuclear units on the watch list announced that day by the NRC, which regulates over 100 civilian nuclear power plants in the United States.
On February 13, 1997, Maine Yankee and Entergy Nuclear, Inc. (Entergy), which is a subsidiary of Entergy Corporation, a Louisiana-based utility holding company and leading nuclear plant operator, entered into a contract under which Entergy is providing management services to Maine Yankee. At the same time, officials from Entergy assumed management positions, including President, at Maine Yankee.
The Company will incur significantly higher costs in 1997 for its share of inspection, repairs and refueling costs at Maine Yankee and will also need to purchase replacement power while the Plant is out of service. While the amount of higher costs is uncertain, Maine Yankee has indicated that it expects it operations and maintenance costs to increase by up to approximately $45 million in 1997, before refueling costs. The Company's share of such costs based on its power entitlement of approximately 38 percent would be up to approximately $17 million. In addition, the Company estimates its share of the refueling costs will amount to approximately $15 million, of which $10.4 million has been accrued as of December 31, 1996. The Company has been incurring incremental replacement-power costs of approximately $1 million per week while the plant has been out of service and expects such costs to continue at approximately the same rate until the plant returns to service.
The impact of these higher nuclear related costs on the Company will be a major obstacle to achieving satisfactory results in 1997, despite prudent control of other operating costs, and is likely to trigger the low earnings bandwidth provision of the ARP. Under the ARP, actual earnings for 1997 outside a bandwidth of 350 basis points, above or below a 10.68 percent rate of return allowance, triggers the profit sharing mechanism. A return below the low end of the range provides for additional revenue through rates equal to one-half of the difference between the actual earned rate of return and the 7.18 percent (10.68 - 3.50) low end of the bandwidth. While the Company believes that the profit sharing mechanism is likely to be triggered in 1997, it cannot predict the amount, if any, of additional revenues that may ultimately result.
Higher nuclear-related costs are affecting other stockholders of Maine Yankee in varying degrees. Bangor Hydro-Electric Company, a Maine-based 7-percent stockholder, has cited its "deteriorating" financial condition and on March 19, 1997, eliminated its common-stock dividend for the quarter. Maine Public Service Company, a 5-percent stockholder, cited problems in satisfying financial covenants in loan documents and reduced its common-stock dividend substantially in early March 1997. Northeast Utilities (20-percent stock ownership through three subsidiaries), which is also adversely affected by the substantial additional costs associated with the three shut-down Millstone nuclear units and the permanently shut-down Connecticut Yankee unit, as well as an unfavorable utility deregulation plan in New Hampshire currently under appeal, announced on March 24, 1997, that its management was planning to recommend a suspension of its second-quarter common-stock dividend to its board of trustees. A default by a Maine Yankee stockholder in making payments under its power contract or capital funds agreement could have a material adverse effect on Maine Yankee, depending on the magnitude of the default, and would constitute a default under Maine Yankee's bond indenture and its two major credit agreements unless cured within applicable grace periods by the defaulting stockholder or other stockholders. The Company cannot predict, however, what effect, if any, the financial difficulties being experienced by some Maine Yankee stockholders will have on Maine Yankee or the Company.
For a detailed discussion of the current Maine Yankee regulatory and operational issues, see Item 7 - "Management's Discussion and Analysis of Financial Condition and Results of Operations" - "Maine Yankee Regulatory Issues."
Financing and Related Considerations
1996 Financing Activity. During 1996 the Company issued $10 million of notes under its $150-million Medium-Term Note program at variable interest rates and an average life of five years. Notes in the amount of $34 million matured during the year, reducing the total of outstanding Medium-Term Notes at the end of 1996 to $68 million from $92 million at the end of 1995.
The Company's Articles of Incorporation limit the amount of unsecured indebtedness the Company may incur without the consent of the holders of the Company's preferred stock to 20 percent of the Company's total capitalization. At the end of 1996, 20 percent of such capitalization amounted to $219 million. In 1989 holders of the Company's preferred stock consented to the issuance of unsecured Medium-Term Notes in an aggregate principal amount of up to $150 million outstanding at any one time, so such notes up to that amount are not included in the 20-percent limitation. The Company is proceeding with plans to seek the consent of the holders of its preferred stock to an additional $350 million of Medium-Term Notes, to $500 million outstanding at any one time, at its annual meeting of stockholders on May 15, 1997, in order to increase its financing flexibility in anticipation of industry restructuring and increased competition. The Company cannot predict whether such consent will be obtained.
On October 23, 1996, the Company entered into a $125-million revolving credit facility with several banks, with The First National Bank of Boston and The Bank of New York as agents for the lenders, and terminated its 1986 and 1994 bank facilities. The new facility consists of two tranches, one a 364-day revolving-credit arrangement that matures on October 22, 1997, and the other a three-year revolving-credit arrangement that matures on October 23, 1999. At December 31, 1996, the Company had $7.5 million in outstanding loans under the new facility.
Securities Ratings. On September 25, 1996, Duff & Phelps Credit Rating Co. ("D&P") placed the ratings of the Company's debt and preferred stock on "Rating Watch--Down." D&P stated that its action was due to uncertainty surrounding the Nuclear Regulatory Commission's investigations into the Maine Yankee, Connecticut Yankee and Millstone Unit No. 3 nuclear facilities, in which the Company has ownership interests." The rating agency recognized "positive strides" taken by the Company over the past few years in dealing with several challenges, but found that the Company's "troubled nuclear facilities situation casts a shadow on the Company's prospects for financial strengthening." On December 18, 1996, Moody's Investors Service ("Moody's") placed the Company's credit ratings under review for possible downgrade, due largely to the effect of its Maine Yankee-related costs. The current ratings assigned the Company's securities by the three major securities-rating agencies, Standard & Poor's Corp. ("S&P"), Moody's Investors Service and Duff & Phelps Credit Rating Co., are shown below:
Mortgage Unsecured Commercial Preferred Bonds Notes Paper Stock
S&P BB+ BB B B+ Moody's Baa2 Baa3 P2 Baa3 D&P BBB- BB+ D3 BB
Environmental Matters
In connection with the operation and construction of its facilities, various federal, state and local authorities regulate the Company regarding air and water quality, hazardous wastes, land use, and other environmental considerations.
Such regulation sometimes requires review, certification or issuance of permits by various regulatory authorities. In addition, implementation of measures to achieve environmental standards may hinder the ability of the Company to conduct day-to-day operations, or prevent or substantially increase the cost of construction of generating plants, and may require substantial investment in new equipment at existing generating plants. Although no substantial investment is presently necessary, the Company is unable to predict whether such investment may be required in the future.
Water Quality Control. The federal Clean Water Act provides that every "point source" discharger of pollutants into navigable waters must obtain a National Pollutant Discharge Elimination System ("NPDES") permit specifying the allowable quantity and characteristics of its effluent. Maine law contains similar permit requirements and authorizes the state to impose more stringent requirements. The Company holds all permits required for its plants by the Clean Water Act, but such permits may be reopened at any time to reflect more stringent requirements promulgated by the EPA or the Maine Department of Environmental Protection ("DEP"). Compliance with NPDES and state requirements has necessitated substantial expenditures and may require further substantial expenditures in the future.
Air Quality Control. Under the federal Clean Air Act, as amended, the EPA has promulgated national ambient air quality standards for certain air pollutants, including sulfur oxides, particulate matter and nitrogen oxides. The EPA has approved a Maine implementation plan prepared by the DEP for the achievement and maintenance of these standards. The Company believes that it is in substantial compliance with the requirements of the Maine plan. The Clean Air Act also imposes stringent emission standards on new and modified sources of air pollutants. Maintaining compliance with more stringent standards, if they should be adopted, could require substantial expenditures by the Company. Although 1990 amendments to the Clean Air Act require, among other things, an aggregate reduction of sulfur dioxide emissions by United States electric utilities by the year 2000, the Company believes that the amendments will not have a material adverse effect on the Company's operations.
In addition, state regulations restrict the sulfur content and other characteristics of the fuel oil burned at the Company's William F. Wyman Station in Yarmouth, Maine. The Company believes that it will continue to be able to obtain a sufficient supply of oil with the required specifications, subject to unforeseen events and the factors influencing the availability of oil discussed under Item 2, Properties, "Fuel Supply", below.
Hazardous Waste Regulations. Under the federal Resource Conservation and Recovery Act of 1976, as amended ("RCRA"), the generation, transportation, treatment, storage and disposal of hazardous wastes are subject to EPA regulations. Maine has adopted state regulations that parallel RCRA regulations, but in some cases are more stringent. The notifications and applications required by the present regulations have been made. The procedures by which the Company handles, stores, treats, and disposes of hazardous waste products have been revised, where necessary, to comply with these regulations and with more stringent requirements on hazardous waste handling imposed by amendments to RCRA enacted in 1984.
For a discussion of a continuing matter in which the Company has been named a potentially responsible party by the EPA with respect to the disposal of certain toxic substances, see Item 3, Legal Proceedings, under the caption "PCB Disposal", below.
Electromagnetic Fields. Public concern has arisen in recent years as to whether electromagnetic fields associated with electric transmission and distribution facilities and appliances and wiring in buildings ("EMF") contribute to certain public health problems. This concern has resulted in some areas in opposition to existing or proposed utility facilities, requests for new legislative and regulatory standards, and litigation. On the basis of the scientific studies to date, the Company believes that no persuasive evidence exists that would prove a causal relationship or justify substantial capital outlays to mitigate the perceived risks. Although the Company has suffered no material effect as a result of this concern, the Company since 1988 has been compiling and disseminating through a regular periodic publication information on all related studies and published materials as a central clearing house for such information, as well as providing such information to its customers. The Company intends to continue to monitor all significant developments in this field.
Capital Expenditures. The Company estimates that its capital expenditures for environmental purposes for the five years from 1992 through 1996 totaled approximately $21.3 million. The Company cannot presently predict the amount of such expenditures in the future, as such estimates are subject to change in accordance with changes in applicable environmental regulations.
Employee Information
A local union affiliated with the International Brotherhood of Electrical Workers (AFL-CIO) represents operating and maintenance employees in each of the Company's operating divisions, and certain office and clerical employees. At December 31, 1996, the Company had 1,655 full-time employees, of whom approximately 44 percent were represented by the union. At the end of 1990 the Company had 2,322 full-time employees. The reduction in the number of full-time employees from 1991 through 1996 was due largely to the implementation of an early-retirement program and other efficiency measures in 1991 and 1992, further staff reductions in the first quarter of 1994 in connection with the Company's restructuring and cost-reduction program and another early-retirement program in mid-1995.
In April 1995 the Company and the union agreed to a three-year labor contract extension that provided for an annual wage increase of 2 percent on May 1, 1995, 2 percent on May 1, 1996, and a reopening of wage negotiations for the year commencing May 1, 1997. The wage negotiations are scheduled to start in early April 1997.
Item 2.
Item 2. PROPERTIES.
Existing Facilities
The electric properties of the Company form a single integrated system which is connected at 345 kilovolts and 115 kilovolts with the lines of Public Service Company of New Hampshire at the southerly end and at 115 kilovolts with Bangor Hydro-Electric Company at the northerly end of the Company's system. The Company's system is also connected with the system of The New Brunswick Power Corporation and with Bangor Hydro-Electric Company, in each case through the 345-kilovolt interconnection constructed by MEPCO, a 78 percent-owned subsidiary of the Company. At December 31, 1996, the Company had approximately 2,293 circuit-miles of overhead transmission lines, 19,254 pole-miles of overhead distribution lines and 1,330 miles of underground and submarine cable. The maximum one-hour firm system net peak load experienced by the Company during the winter of 1996 was approximately 1,301 megawatts on January 3, 1996. At the time of the peak, the Company's net capability was 1,893 megawatts.
The Company operates 30 hydroelectric generating stations, of which 29 are owned by the Company, with an estimated net capability of 369 megawatts, and it purchases an additional 74 megawatts of non-utility hydroelectric generation in Maine. The Company also operates one oil-fired steam-electric generating station, William F. Wyman Station in Yarmouth, Maine. The Company's share of William F. Wyman Station has an estimated net capability of 593 megawatts. The oil-fired station is located on tidewater, permitting waterborne delivery of fuel. The Company also has internal combustion generating facilities with an estimated aggregate net capability of 38 megawatts.
The Company has ownership interests in five nuclear generating plants in New England. The largest is a 38-percent interest in the Maine Yankee plant in Wiscasset, Maine. In addition, the Company owns a 9.5 percent interest in Yankee Atomic Electric Company ("Yankee Atomic"), discussed below, which has permanently shut down its plant located in Rowe, Massachusetts, a 6 percent interest in Connecticut Yankee Atomic Power Company ("Connecticut Yankee"), discussed below, which has permanently shut down its plant in Haddam, Connecticut, and a 4 percent interest in Vermont Yankee Nuclear Power Corporation ("Vermont Yankee"), which owns an operating plant in Vernon, Vermont (collectively, with Maine Yankee, the "Yankee Companies"). In addition, pursuant to a joint ownership agreement, the Company has a 2.5 percent direct ownership interest in the Millstone 3 nuclear unit ("Millstone 3") in Waterford, Connecticut, which has been off-line for regulatory reasons since March 31, 1996.
In December 1996, the Board of Directors of Connecticut Yankee Atomic Power Company voted to permanently shut down the Connecticut Yankee plant for economic reasons, and to decommission the plant. An economic analysis conducted by Connecticut Yankee estimated that the early closing of the plant would save over $100 million (net present value) over its remaining license life to the year 2007, compared with the costs of continued operation. The Company's 6-percent equity interest totaled approximately $6.4 million at December 31, 1996. The plant did not operate after July 22, 1996. The Company estimates its share of the cost of Connecticut Yankee's continued compliance with regulatory requirements, recovery of its plant investments, decommissioning and closing the plant to be approximately $45.8 million and has recorded a regulatory asset and a liability on the consolidated balance sheet. The Company is currently recovering through rates an amount adequate to recover these expenses.
In 1993 the FERC approved a settlement agreement regarding the decommissioning plan, recovery of plant investment, and all issues with respect to the prudence of the decision to discontinue operation of the Yankee Atomic plant. The Company estimates its remaining share of the cost of Yankee Atomic's continued compliance with regulatory requirements, recovery of its plant investments, decommissioning and closing the plant, to be approximately $16.5 million. This estimate, which is subject to ongoing review and revision, has been recorded by the Company as a regulatory asset and a liability on the Company's balance sheet. As part of the MPUC's decision in the Company's 1993 base-rate case, the Company's current share of costs related to the deactivation of Yankee Atomic is being recovered through rates.
The Company's share of the capacity of the three operating nuclear generating plants, as of December 31, 1996, amounted to the following:
Maine Yankee 329 MW Vermont Yankee 19 MW Millstone 3 29 MW
The Company is obligated to pay its proportionate share of the operating expenses, including depreciation and a return on invested capital, of each of the Yankee Companies referred to above for periods expiring at various dates to 2012. Pursuant to the joint ownership agreement for Millstone 3, the Company is similarly obligated to pay its proportionate share of the operating costs of Millstone 3. The Company is also required to pay its share of the estimated decommissioning costs of each of the Yankee Companies and Millstone 3. The estimated decommissioning costs are paid as a cost of energy in the amounts allowed in rates by the FERC.
MEPCO owns and operates a 345-kilovolt transmission interconnection, completed in 1971, extending from the Company's substation at Wiscasset to the Canadian border where it connects with a line of The New Brunswick Power Corporation ("NB Power") under an interconnection agreement. MEPCO transmits power between NB Power and various New England utilities under separate agreements.
NEPOOL, of which the Company is a member, contracted in connection with its Hydro-Quebec projects to purchase power from Hydro-Quebec. The contracts entitle the Company to 85.9 megawatts of capacity credit in the winter and 127.25 megawatts of capacity credit during the summer. The Company also entered into facilities-support agreements for its share of the related transmission facilities, with its share of the support responsibility and of associated benefits being approximately 7 percent of the totals. The Company is making facilities-support payments on approximately $28.8 million, its share of the construction cost for the transmission facilities incurred through December 31, 1996.
Maine Yankee Decommissioning. Effective in 1988 Maine Yankee began collecting $9.1 million annually for decommissioning the Maine Yankee plant, based on a FERC-approved funding level of $167 million. In 1994, Maine Yankee, pursuant to FERC authorization, increased its annual collection to $14.9 million and reduced its return on common equity to 10.65 percent, for a total increase in rates of approximately $3.4 million. The increase in decommissioning collection was based on the estimated cost of decommissioning the Maine Yankee Plant, assuming dismantlement and removal, of $317 million (in 1993 dollars) based on a 1993 external engineering study. The estimated cost of decommissioning nuclear plants is subject to change due to the evolving technology of decommissioning and the possibility of new legal requirements. The market value of Maine Yankee's accumulated decommissioning funds was $163.5 million (including actual interest earned) as of December 31, 1996.
Maine Yankee Low-Level Waste Disposal. The federal Low-Level Radioactive Waste Policy Amendments Act (the "Waste Act"), enacted in 1986, required operating disposal facilities to accept low-level nuclear waste from other states until December 31, 1992. Maine did not satisfy its milestone obligation under the Waste Act requiring submission of a site license application by the end of 1991, and therefore became subject to surcharges on its waste and did not have access to regulated disposal facilities after the end of 1992. Maine Yankee then began storing all low-level waste generated at an on-site storage facility. On July 1, 1995, however, the State of South Carolina restored access to its facility and Maine Yankee began to ship low-level waste to the South Carolina facility for disposal.
The states of Maine, Texas and Vermont have been pursuing the implementation of a compact for the disposal of low-level waste at a site in Texas. The ratification bill for the compact is before Congress for consideration at its 1997 session. The compact provides for Texas to take Maine's low-level waste over a 30-year period for disposal at a planned facility in west Texas. In return, Maine would be required to pay $25 million, assessed to the Company by the State of Maine, payable in two equal installments, the first after ratification by Congress and the second upon commencement of operation of the Texas facility. In addition, Maine Yankee would be assessed a total of $2.5 million for the benefit of the Texas county in which the facility would be located and would also be responsible for its pro-rata share of the Texas governing commission's operating expenses. The Maine Low-Level Radioactive Waste Authority suspended its search for a suitable disposal site in Maine and, as of June 30, 1994, ceased operations.
In the event the required ratification by Congress is not obtained, subject to continued NRC approval, Maine Yankee has said it will ship low-level waste offsite for disposal in South Carolina or other available sites as long as such sites are available, reserving its capacity to store approximately ten to twelve years' production of low-level waste at its facility at the Plant site. Subject to obtaining necessary regulatory approval, Maine Yankee could also build a second facility on the Plant site. Maine Yankee believes it is probable that it will have adequate storage capacity for such low-level waste available on-site, if needed, through the current licensed operating life of the Plant.
The Company cannot predict whether the final required ratification of the Texas compact or other regulatory approvals required for on-site storage will be obtained, but Maine Yankee has stated that it intends to utilize its on-site storage facility as well as dispose of low-level waste at the South Carolina site or other available sites in the interim and continue to cooperate with the State of Maine in pursuing all appropriate options.
Nuclear Insurance. The Price-Anderson Act is a federal statute providing, among other things, a limit on the maximum liability for damages resulting from a nuclear incident. Coverage for the liability is provided for by existing private insurance and retrospective assessments for costs in excess of those covered by insurance, up to $79.3 million for each reactor owned, with a maximum assessment of $10 million per reactor in any year. Based on the Company's stock ownership in four nuclear generating facilities and its 2.5 percent direct ownership interest in the Millstone 3 nuclear unit, the Company's retrospective premium could be as high as $6 million in any year, for a cumulative total of $47.6 million, exclusive of the effect of inflation indexing and a 5-percent surcharge in the event that total public liability claims from a nuclear incident should exceed the funds available to pay such claims.
In addition to the insurance required by the Price-Anderson Act, the nuclear generating facilities mentioned above carry additional nuclear property-damage insurance. This additional insurance is provided from commercial sources and from the nuclear electric utility industry's insurance company through a combination of current premiums and retrospective premium adjustments. Based on current premiums and the Company's indirect and direct ownership in nuclear generating facilities, this adjustment could range up to approximately $7.7 million annually.
For a discussion of issues relating to Maine Yankee's spent nuclear fuel disposal, see "Fuel Supply" - "Nuclear", below.
Construction Program
The Company's plans for improvements and expansion of generating, transmission and distribution facilities and power-supply sources are under continuing review. Actual construction expenditures depend on the availability of capital and other resources, load forecasts, customer growth, and general business conditions. Recent economic and regulatory considerations have led the Company to hold its planned 1996 capital investment outlays, including deferred demand-side management expenditures, to minimum levels. During the five-year period ended December 31, 1996, the Company's construction and acquisition expenditures amounted to $264.8 million (including investment in jointly-owned projects and excluding MEPCO). The program is currently estimated at approximately $56 million for 1997 and $246 million for 1998 through 2001.
The following table sets forth the Company's estimated capital expenditures as discussed above:
1997 2001 Total Type of Facilities (Dollars in Millions)
Generating Projects $ 8 $ 33 $ 41 Transmission 3 14 17 Distribution 27 124 151 General facilities and Other 18 75 93
Total $56 246 $302
Demand-side Management
The Company's demand-side-management initiatives have included programs aimed at residential, commercial and industrial customers. Among the residential efforts have been programs that offer energy audits, low-cost insulation and weatherization packages, water heater wraps, energy-efficient light bulbs, and water heater cycling credits. Among the commercial and industrial efforts have been programs that offer rebates for efficient lighting systems and motors, energy-management loans, grants to customers who make efficiency improvements, and shared savings arrangements with customers who undertake qualifying conservation and load management programs.
Actual demand-side management expenditures depend on such factors as availability of capital and other resources, load forecasts, customer growth, and general business conditions. Because of budget constraints, the Company is seeking to concentrate its efforts where the need and cost-effectiveness are the greatest, while continuing to honor contractual commitments.
NEPOOL
The Company is a member of the New England Power Pool (NEPOOL), which is open to all investor-owned, municipal and cooperative electric utilities in New England under a 1971 agreement that provides for coordinated planning and operation of approximately 99 percent of the electric power production, purchases and transmission in New England. The NEPOOL Agreement imposes obligations concerning generating capacity reserve and the use of major transmission lines, and provides for central dispatch of the region's facilities.
On April 24, 1996, the Federal Energy Regulatory Commission (FERC) issued Order No. 888, which requires all public utilities that own, control or operate facilities used for transmitting electric energy in interstate commerce to file open access non-discriminatory transmission tariffs that offer both load-based, network and contract-based, point-to-point service, including ancillary service to eligible customers containing minimum terms and conditions of non-discriminatory service. This service must be comparable to the service they provide themselves at the wholesale level; in fact, these utilities must take wholesale transmission service they provide themselves under the filed tariffs. The order also permits public utilities and transmitting utilities the opportunity to recover legitimate, prudent and verifiable wholesale stranded costs associated with providing open access and certain other transmission services. It further requires public utilities to functionally separate transmission from generation marketing functions and communications. The intent of this order is to promote the transition of the electric utility industry to open competition. Order No. 888 also clarifies federal and state jurisdiction over transmission in interstate commerce and local distribution and provides for deference of certain issues to state recommendations.
On July 9, 1996, the Company and MEPCO submitted compliance filings to meet the new pro forma tariff non-price minimum terms and conditions of non-discriminatory transmission. Since July 9, 1996, the Company and MEPCO have been transmitting energy pursuant to their filed tariffs, subject to refund. FERC subsequently issued Order No. 888-A which generally reaffirms Order No. 888 and clarifies certain terms.
Also on April 24, 1996, FERC issued Order No. 889 which requires public utilities to functionally separate their wholesale power marketing and transmission operation functions and to obtain information about their transmission system for their own wholesale power transactions in the same way their competitors do through the Open Access Same-time Information System (OASIS). The rule also prescribed standards of conduct and protocols for obtaining the information. The standards of conduct are designed to prevent employees of a public utility engaged in marketing functions from obtaining preferential information. The Company participated in efforts to develop a regional OASIS, which was operational January 3, 1997. FERC subsequently approved a New England Power Pool-wide Open Access Tariff, subject to refund and issuance of further orders. The Company also participated in revising the New England Power Pool Agreement to comply with the new regulatory requirements. The revised agreement is pending FERC approval.
Fuel Supply
The Company's total kilowatt-hour production by energy source for each of the last two years and as estimated for 1997 (consistent with the actual mix for January 1997 with Maine Yankee off-line) is shown below. The 1997 estimate could change when, and if, Maine Yankee resumes operation.
Actual Estimated Source 1996 1995 1997
Nuclear 19% 7% 2% Hydro 17 15 17 Oil 16 21 29 Non-utility 32 37 38 Other purchases 16 20 14 100% 100% 100%
The 1997 estimated kilowatt-hour output from oil and purchased power may vary depending upon the relative costs of Company-generated power and power purchased through independent producers and other sources.
Oil. The Company's William F. Wyman Station in Yarmouth, Maine, and its internal combustion electric generating units are oil-fired. The Company's last contract for the supply of fuel oil requirements at market prices was allowed to expire in 1993. Since then the Company has been purchasing its fuel-oil requirements on the open market.
The average cost per barrel of fuel oil purchased by the Company during the five calendar years commencing with 1992 was $14.02, $13.12, $12.93, $16.16 and $18.18, respectively. A substantial portion of the fuel oil burned by the Company and the other member utilities of NEPOOL is imported. The availability and cost of oil to the Company, both under contract and in the open market, could be adversely affected by policies and events in oil-producing nations and other factors affecting world supplies and domestic governmental action.
Nuclear. As described above, the Company has interests in a number of nuclear generating units. The cycle of production and utilization of nuclear fuel for such units consists of (1) the mining and milling of uranium ore, (2) the conversion of the resulting concentrate to uranium hexafluoride, (3) the enrichment of the uranium hexafluoride, (4) the fabrication of fuel assemblies, (5) the utilization of the nuclear fuel, and (6) the disposal of spent fuel.
Maine Yankee has entered into a contract with the United States Department of Energy ("DOE") for disposal of its spent nuclear fuel, as required by the Nuclear Waste Policy Act of 1982, pursuant to which a fee of one dollar per megawatt-hour is currently assessed against net generation of electricity and paid to the DOE quarterly. Under this Act, the DOE was given the responsibility for disposal of spent nuclear fuel produced in private nuclear reactors. In addition, Maine Yankee is obligated to make a payment with respect to generation prior to April 7, 1983 (the date current DOE assessments began). Maine Yankee has elected under terms of this contract to make a single payment of this obligation prior to the first delivery of spent fuel to DOE, scheduled to begin no earlier than 1998. The payment will consist of $50.4 million (all of which Maine Yankee has previously collected from its customers, but for which a reserve was not funded), which is the approximate one-time fee charge, plus interest accrued at the 13-week Treasury Bill rate compounded on a quarterly basis from April 7, 1983, through the date of the actual payment. Current costs incurred by Maine Yankee under this contract are recoverable under the terms of its Power Contracts with its sponsoring utilities, including the Company. Maine Yankee has accrued and billed $63.8 million of interest cost for the period April 7, 1983, through December 31, 1996.
Maine Yankee has formed a trust to provide for payment of its long-term spent fuel obligation, and is funding the trust with deposits at least semiannually which began in 1985, with currently projected semiannual deposits of approximately $1.8 million through December 1997. Deposits are expected to total approximately $73.2 million, with the total liability, including interest due at the time of disposal, estimated to be approximately $126.5 million at January 31, 1998. Maine Yankee estimates that trust fund deposits plus estimated earnings will meet this total liability if funding continues without material changes.
Under the terms of a license amendment approved by the NRC in 1984, the present storage capacity of the spent fuel pool at the Maine Yankee Plant will be reached in 1999 and after 1996 the available capacity of the pool will not accommodate a full-core removal. After consideration of available technologies, Maine Yankee elected to provide additional capacity by replacing the fuel racks in the spent fuel pool at the Maine Yankee Plant for more compact storage and in March 1994 the NRC granted its authorization. Installation of the new racks began in 1996 and is expected to be completed during 1997. Maine Yankee believes that the replacement of the fuel racks will provide adequate storage capacity through the Maine Yankee Plant's licensed operating life. Maine Yankee has stated that it cannot predict with certainty whether or to what extent the storage capacity limitation at the plant will affect the operation of the plant or the future cost of disposal.
Federal legislation enacted in December 1987 directed the DOE to proceed with the studies necessary to develop and operate a permanent high-level waste (spent fuel) disposal site at Yucca Mountain, Nevada. The legislation also provided for the possible development of a Monitored Retrievable Storage ("MRS") facility and abandoned plans to identify and select a second permanent disposal site. An MRS facility would provide temporary storage for high-level waste prior to eventual permanent disposal. In late 1989 the DOE announced that the permanent disposal site is not expected to open before 2010, although originally scheduled to open in 1998. Additional delays due to political and technical problems are probable.
In 1994 several nuclear utilities sought a declaration from the United States Court of Appeals for the District of Columbia that existing federal legislation required the DOE to take responsibility for spent nuclear fuel in 1998. On July 23, 1996, the court held that the DOE is obligated "to start disposing of [spent nuclear fuel] no later than January 31, 1998," and in October 1996 the DOE said it would not appeal the decision. The Company cannot predict when or how the DOE will meet its responsibility.
The Company has been advised by the companies operating nuclear generating stations in which the Company has an interest that each of those companies has contracted for certain segments of the nuclear fuel production and utilization cycle through various dates. Contracts for other segments of the fuel cycle will be required in the future, but their availability, prices and terms cannot now be predicted. Those companies have also advised the Company that they are assessing options generally similar to those described above with respect to Maine Yankee in connection with disposal of spent nuclear fuel.
Item 3.
Item 3. LEGAL PROCEEDINGS.
PCB Disposal
The Company is a party in legal and administrative proceedings that arise in the normal course of business. In connection with one such proceeding, the Company has been named as a potentially responsible party and has been incurring costs to determine the best method of cleaning up an Augusta, Maine, site formerly owned by a salvage company and identified by the Environmental Protection Agency (EPA) as containing soil contaminated by polychlorinated biphenyls (PCBs) from equipment originally owned by the Company.
In July 1994, the EPA approved changes to the remedy it had previously selected, the principal change being to adjust the soil cleanup standard to 10 parts per million from the standard of one part per million established in the EPA's 1989 Record of Decision, on the part of the site where PCBs were found in their highest concentration. The EPA stated that the purpose of adjusting the standard of cleanup was to accommodate the selected technology's current inability to reduce PCBs and other chemical components on the site to the original standard.
In June 1995, after discussions between the Company and the EPA, design work on the selected remedy was suspended. On July 7, 1995, the Company formally requested that the EPA abandon that remedy for an already-designated alternative remedy that the Company believes could result in substantially lower costs. On October 10, 1995, the EPA approved the new remedy after determining that the old remedy was no longer feasible or cost-effective at the site. The new remedy involves transporting the contaminated soil to a secure off-site landfill.
The Company believes that its share of the remaining costs of the cleanup under the new method could total approximately $2.7 million to $4.2 million. This estimate is net of an agreed partial insurance recovery and the 1993 court-ordered contribution of 41 percent from Westinghouse Electric Corp., but does not reflect any possible contributions from other insurance carriers the Company has sued, or from any other parties. The Company has recorded an estimated liability of $2.7 million and an equal regulatory asset, reflecting an accounting order to defer such costs and the anticipated ratemaking recovery of such costs when ultimately paid. In addition, the Company has deferred as a regulatory asset $5.1 million of costs incurred through December 31, 1996.
The Company cannot predict with certainty the level and timing of the cleanup costs, the extent they will be covered by insurance, or the ratemaking treatment of such costs, but believes it should recover substantially all of such costs through insurance and rates. The Company also believes that the ultimate resolution of the legal and environmental proceedings in which it is currently involved will not have a material adverse effect on its financial condition.
Item 4
Item 4 SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
Not applicable.
Item 4.1 EXECUTIVE OFFICERS OF THE REGISTRANT.
The following are the present executive officers of the Company with all positions and offices held. There are no family relationships between any of them, nor are there any arrangements or understandings pursuant to which any were selected as officers.
Name, Age, and Year First Became Officer Office
David M. Jagger, 55, 1996 Chairman of the Board of Directors
Charles H. Abbott, 61, 1996 Vice Chairman of the Board of Directors
David T. Flanagan, 49, 1984 President and Chief Executive Officer, and Director
Arthur W. Adelberg, 45, 1985 Vice President, Law and Power Supply
Richard A. Crabtree, 50, 1978 Vice President, Retail Operations
David E. Marsh, 49, 1986 Vice President, Corporate Services, Treasurer and Chief Financial Officer
Curtis A. Mildner, 43, 1994 Vice President, Marketing
Gerald C. Poulin, 55, 1984 Vice President, Generation and Technical Support
Anne M. Pare, 43, 1996 Secretary and Clerk
Each of the executive officers has for the past five years been an officer or employee of the Company except Messrs. Jagger and Abbott, who have been non-employee directors since 1988, and Mr. Mildner. Mr. Mildner joined the Company as Vice President, Marketing, on February 7, 1994. Prior to his employment by the Company, he had been employed since 1987 by Hussey Seating Company of Berwick, Maine, as Vice President, Marketing, and in related capacities.
PART II
Item 5
Item 5 MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
The Company's common stock is traded on the New York Stock Exchange. As of December 31, 1996, there were 40,413 holders of record of the Company's common stock.
Price Range of and Dividends on Common Stock
Market Price Dividends High Low Declared First Quarter $16 1/4 $13 1/4 $0.225 Second Quarter 14 1/2 12 1/4 0.225 Third Quarter 13 7/8 11 5/8 0.225 Fourth Quarter 12 3/8 11 0.225
First Quarter $14 1/8 $10 3/4 $0.225 Second Quarter 12 5/8 10 1/4 0.225 Third Quarter 13 1/2 11 0.225 Fourth Quarter 15 1/8 13 0.225
Under the most restrictive terms of the indenture securing the Company's General and Refunding Mortgage Bonds and of the Company's Articles of Incorporation, no dividend may be paid on the common stock of the Company if such dividend would reduce retained earnings below $29.6 million. At December 31, 1996, the Company's retained earnings were $72.5 million, of which $42.9 million was not so restricted. Future dividend decisions will be subject to future earnings levels and the financial condition of the Company and will reflect the evaluation by the Company's Board of Directors of then existing circumstances.
Item 6.
Item 6. SELECTED FINANCIAL DATA.
The following table sets forth selected consolidated financial data of the Company for the five years ended December 31, 1992 through 1996. This information should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the consolidated financial statements and related notes thereto included in Items 7 and 8 hereof. The selected consolidated financial data for the years ended December 31, 1992 through 1996 are derived from the audited consolidated financial statements of the Company.
Selected Consolidated Financial Data
(Dollars in Thousands, Except Per Share Amounts)
Item 7.
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
Overview
In 1996, the Company experienced higher than normal costs associated with its investments in nuclear generating units, particularly the Maine Yankee nuclear plant, and incurred replacement-power costs due to unplanned nuclear-plant outages.
While the return to service of the Maine Yankee nuclear plant in mid-January 1996 ended an 11-month consecutive outage, the plant's operating capacity was limited to 90% of its maximum production capacity during periods of operation in 1996 and unscheduled outages reduced the availability of the plant to less than 10 months of operation. The additional costs incurred by the Company under its power contract with Maine Yankee were approximately $3.6 million. Replacement-power costs associated with the reduced level of output and limited availability of the plant amounted to approximately $13.5 million for a total of $17.1 million or an earnings reduction of $0.31 per share, after tax, during 1996.
The Company's 1996 financial results benefited by approximately $15.3 million, after tax, or $0.47 per share, as a result of non-recurring items related to a favorable resolution of federal income-tax issues with the Internal Revenue Service, a reduction in purchased power costs associated with an extended outage at a non-utility generator (NUG) under contracts to the Company, an energy-swap agreement with another utility that reduced purchased-power costs, and the affirmation of the rate recovery of a regulatory asset.
Earnings per share in 1996 were $1.57, after recognizing the higher nuclear-related costs and benefits of non-recurring events, compared to $0.86 per share in 1995. The 1995 earnings per share included the recognition of $0.70 per share in Maine Yankee-related repair and replacement-power costs.
The Maine Yankee nuclear plant was shut down on December 6, 1996, for inspection and repairs. Maine Yankee has notified the Company that, due to the need to replace 92 fuel assemblies, it will refuel the plant during the current outage. While the plant is out of service, Maine Yankee must, in addition to replacing the fuel assemblies, conduct an intensive inspection of its steam generators, resolve cable-separation and other regulatory issues, and obtain NRC approval to restart the plant. The Company believes the plant will be out of service at least until August 1997, but cannot predict when or whether all of the regulatory and operational issues will be satisfactorily resolved, or what effect the repairs and improvements to the plant will have on its operating economics.
The Company will incur significantly higher costs in 1997 for its share of inspection, repairs and refueling costs at Maine Yankee, and will also need to purchase replacement power while the plant is out of service. While the amount of higher costs is uncertain, Maine Yankee has indicated that it expects its operations-and-maintenance costs to increase by up to approximately $45 million in 1997, before refueling costs. The Company's share of such costs, based on its power entitlement of approximately 38%, would be up to approximately $17 million. In addition, the Company estimates its share of the refueling costs will amount to approximately $15 million; $10.4 million has been accrued as of December 31, 1996. The Company has been incurring incremental replacement-power costs of approximately $1 million per week while the plant has been out of service and expects such costs to continue at approximately the same rate until the plant returns to service.
The impact of these higher nuclear-related costs on the Company's 1997 financial results will be significant and is likely to trigger a low earnings bandwidth provision of the Alternative Rate Plan (ARP). Under the ARP, actual earnings for 1997 outside a bandwidth of 350 basis points, above or below the 10.68% rate of return allowance, triggers the profit sharing mechanism. A return below the low end of the range provides for additional revenue through rates equal to one-half of the difference between the actual earned rate of return and the 7.18% (10.68 - 3.50) low end of the bandwidth. While the Company believes the profit-sharing mechanism is likely to be triggered in 1997, it cannot predict the amount, if any, of additional revenues that may ultimately result.
The ARP was structured to permit reasonable assurance of continued recovery of the cost of services, including past deferrals, provide a higher degree of price stability and predictability, and reduce regulatory costs while providing financial incentives for improved efficiencies and protection against significant unforeseen events.
The Company declared dividends totaling $0.90 per share in 1996, unchanged from 1995 and 1994 levels. Dividend and capital structure policy will continue to be reviewed by management and the Board of Directors and will take into consideration such issues as sustainable long-term earnings, capital needs, business opportunities and business risk, the structure of the Company and the industry, and the overall need to assure that financial risk and business risk are aligned. In the near term, the Company anticipates significant downward pressure on its earnings capacity as a result of the higher cost and outages of the Maine Yankee and Millstone Unit No. 3 nuclear facilities. The capacity of the Company to attain earnings levels that support the current dividend are closely related to the performance and cost associated with the Company's Maine Yankee investment and power entitlement.
Sustained nuclear-unit outages combined with higher nuclear operating costs in 1997 will be a major obstacle to achieving satisfactory results in 1997 despite prudent control of other operating costs. On a prospective basis, a contract with a major NUG representing 62.5 MW of capacity expires on October 31, 1997. Net annual savings due to the contract expiration would be approximately $25 million, with 1997 savings amounting to approximately $4 million.
The Company continues to face the challenges of competition and industry restructuring, and must achieve and maintain financial performance and resources commensurate with both the provision of service demanded by customers and the obligation to achieve competitive returns on investor capital.
The Company is aggressively addressing the challenges of restructuring, the pressure from competitive energy sources, customers' desire for choices and enhanced service, and nuclear-plant outages in 1997. The following long-term financial objectives are key to sustainable future earnings and growth and will be a major focus of our 1997 activities:
1. Continue increasing the efficiency of operations: cost management under price-cap regulation must replace the cost-plus culture encouraged by traditional regulation.
2. Focus on volume of sales as a revenue builder.
3. Align financial policies to changing business needs and risks; competition tends to increase business risk, which impacts the desired level of fixed-charge obligations.
4. Expand areas of investment for growth; open competition in electric energy could significantly reduce traditional sales-growth opportunities.
5. Recover the substantial investments made and costs being incurred for existing service obligations; open competition could strand these costs, absent a transition mechanism for recovery.
Earnings and Dividends
For 1996, the Company generated net income of $60.2 million, compared to $38.0 million in 1995, and a net loss of $23.3 million in 1994. Earnings applicable to common stock were $50.8 million in 1996 or $1.57 per share, compared to $27.8 million or $0.86 per share in 1995. In 1994, the loss applicable to common stock was $33.8 million or $1.04 per share. The Company benefited from higher sales, cost management initiatives, surplus power sales and certain non-recurring events during the year as discussed below. In addition, net income in 1996 reflects replacement power costs for unscheduled nuclear unit outages of approximately $18.5 million. Increased nuclear operations, maintenance and study costs to comply with NRC safety actions amounted to approximately $4.3 million in 1996. See "Maine Yankee Regulatory Issues" and "Other Nuclear Issues" for more information.
Certain favorable one-time events took place in 1996. Due to a flood in the fall of 1996, a non-utility generator was temporarily forced out of service for an extended period. This enabled the Company to purchase replacement power at a lower cost for a savings of approximately $5.4 million. An energy-swap agreement signed in 1994 with Northeast Utilities allowed the Company to save approximately $6 million in purchased power costs. A settlement with the Internal Revenue Service on audits for the years 1988-1991 provided a decrease to income tax expense of approximately $4.8 million. The 1996 Maine Public Utilities Commission's (MPUC) Alternative Rate Plan (ARP) decision provided the Company recovery in rates for its workers' compensation regulatory asset of $6.4 million, which resulted in the reversal of a 1995 charge due to uncertainty about recovery in rates.
Net income in 1995 reflects $29 million of replacement purchased-power energy expense and $10 million for the Company's share of sleeving repair costs during the extended shutdown at Maine Yankee. These two items reduced earnings applicable to common stock by $22.9 million after income taxes, or $0.70 per share. The loss in 1994 reflects the write-off of approximately $100 million ($60 million after taxes) of deferred balances in accordance with the MPUC order in the ARP proceeding discussed fully below under the caption "Alternative Rate Plan" and Note 3 to Consolidated Financial Statements, "Regulatory Matters - Alternative Rate Plan." This write-off had the effect of reducing earnings per share by $1.85. Absent the write-off, earnings for 1994 would have been $0.81 per share.
Dividends declared per common share have remained at $0.90 on an annual basis for the three years ended December 31, 1996.
Revenues and Sales
Electric operating revenues increased by $51.0 million or 5.6% to $967.0 million in 1996, and by $11.1 million or 1.2% to $916.0 million in 1995. The components of the change in electric operating revenues are as follows:
(Dollars in millions) 1996 1995 Revenues from Company service-area kilowatt-hour sales $15.0 $ 4.5 Revenues from non-territorial sales 33.4 (9.2) Other Company operating revenues 3.0 8.7 Maine Electric Power Company, Inc. fuel cost recovery and other revenues (0.4) 7.1 Total Change in Electric Operating Revenues $51.0 $11.1
Refer to "Alternative Rate Plan" below, for a discussion of new rates and their impact on revenues.
The Company's service-area sales for the years 1996, 1995, and 1994 are shown in the following table:
(Kilowatt-hours in millions)
The primary factors in the service-area kilowatt-hour sales increase were residential customers' taking advantage of the Company's water-heating programs, increased sales in the pulp and paper industry, and the addition of a wholesale customer. The decreases in 1995 and 1994 were attributed to low economic growth, the loss of a major industrial customer in September 1994, energy management, and loss of sales due to conversions from electricity to alternative fuels for such purposes as space and water heating.
The average number of residential customers increased by 5,157 in 1996, 5,076 in 1995, and 4,679 in 1994, while average usage per residential customer declined slightly in 1996, 3.1% in 1995 and 1.9% in 1994.
The 1996 increase in commercial sales reflect increases in the retail and wholesale trade and service sectors. Combined, these sectors comprise approximately 68% of commercial sales. Sales to all others in the commercial sector were lower than 1995. Sales to Maine Yankee increased by 4 million kilowatt hours in 1996, and by 14.7 million kilowatt hours in 1995 due to the Plant's operating capacity limit of 90% and extended outages in both periods.
Industrial sales levels are significantly affected by sales to the pulp-and-paper industry, which accounts for approximately 62% of industrial sales and approximately 25% of total service-area sales. Sales to the pulp-and-paper sector increased by 3.7% in 1996 and decreased by 8.6% in 1995, and by 3.6% in 1994. The increase in 1996 reflects special arrangements the Company has made with several paper companies to back down some of their self-generation and buy electricity from the Company at a discounted rate. The 1995 and 1994 decreases reflect lower sales levels primarily due to the late-1994 loss of a major customer that had previously purchased approximately 280 million kilowatt-hours annually. Refer to "Alternative Rate Plan" and "Competition and Economic Development," below, and Note 4 to Consolidated Financial Statements, "Commitment's and Contingencies - Competition," for additional information regarding the loss of this customer and the Company's actions to preserve its remaining large-industrial-customer base and other customer groups. Sales to all other industrial customers as a group increased 4.5% in 1996, 2.7% in 1995, and 1.5% in 1994.
Revenues from non-territorial sales were significantly higher in 1996 due to sales to an out-of-state utility impacted by nuclear plant outages. In March 1995, a contract with a power broker expired, resulting in a decrease of $9.2 million in 1995 in non-territorial sales.
Alternative Rate Plan
In December 1994, the MPUC approved a stipulation, signed by most of the parties to the Company's ARP proceeding, which took effect January 1, 1995. This follow-up proceeding to the Company's 1993 base-rate case was ordered by the MPUC in an effort to develop a five-year plan containing price-cap, profit-sharing, and pricing-flexibility components. The price-cap mechanism provides for adjusting the Company's retail rates annually on July 1, commencing in 1995, at a percentage combining (1) a price index, (2) a productivity offset, (3) a sharing mechanism, and (4) flow-through items and mandated costs. The price cap applies to all of the Company's retail rates, and includes fuel-and-purchased-power costs that previously had been treated separately. The components of the July 1, 1995, price-cap increase of 2.43% are the inflation index of 2.92%, reduced by a productivity offset of 0.5%, and increased by 0.01% for flow-through items and mandated costs. The components of the July 1, 1996, price-cap increase of 1.26% consisted of an inflation index of 2.55% and earnings sharing and mandated cost items of 0.64%, reduced by a productivity offset of 1.0%, and sharing of contract restructuring and buyout savings of 0.93%. As originally stated in the MPUC's order approving the ARP, operation under the ARP continues to meet the criteria of Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS No. 71). As a result, the Company will continue to apply the provisions of SFAS No. 71 to its accounting transactions and to its financial statements.
In 1994, the Company agreed in the ARP negotiations to record charges of approximately $100 million ($60 million, net of tax) against 1994 earnings.
The Company believes the ARP provides the benefits of needed pricing flexibility to set prices between defined floor and ceiling levels in three service categories: (1) existing customer classes, (2) new customer classes for optional targeted services, and (3) special-rate contracts. The Company believes that the added flexibility will position it more favorably to meet the competition from other energy sources that has eroded segments of its customer base. Some price adjustments can be implemented upon 30-days' notice by the Company, while certain others are subject to expedited review by the MPUC. The Company has utilized this feature in providing new rates to approximately 19,000 customers representing approximately 40% of annual kilowatt-hour sales and 27% of service-area revenues. These reductions in rates were offered to customers after consideration of associated NUG cost reductions, savings from further NUG consolidations and other general cost reductions.
The ARP also contains provisions to protect the Company and ratepayers against unforeseen adverse results from its operation. These include review by the MPUC if the Company's actual return on equity falls outside a designated range, a mid-period review of the ARP by the MPUC in 1997 (including possible modification or termination), and a "final" review by the MPUC in 1999 to determine whether or with what changes the ARP should continue after 1999. The Company will submit its 1997 compliance filing and mid-period review filing in March 1997. The MPUC decision on the mid-period review is expected by September 30, 1997.
While the ARP provides the Company with an expanded opportunity to be rewarded for efficiency, it also presents the risk of reduced rates of return if costs rise unexpectedly, like those that have resulted from the recent outages at Maine Yankee, or if revenues from sales decline or are not adequate to fund costs. The Company believes the ARP continues to be a competitive advantage and does not plan to propose any significant change during the mid-period review.
For a detailed discussion of the ARP, refer to Note 3 to Consolidated Financial Statements,"Regulatory Matters - Alternative Rate Plan," and "Meeting the Requirements of SFAS 71."
Maine Yankee Regulatory Issues
The Company owns 38% of the common stock of Maine Yankee and is responsible for an approximately equal percentage of its costs. The 879-megawatt Maine Yankee nuclear generating plant in Wiscasset, Maine (the Plant), like others with pressurized water reactors, had been experiencing degradation of its steam generator tubes. Until early 1995, this was believed to be limited to a relatively small number of tubes. During a refueling shutdown in February 1995, new inspection methods used by Maine Yankee revealed that approximately 60% of the Plant's 17,000 steam generator tubes appeared to have defects.
Following a detailed analysis of safety, technical and financial considerations, Maine Yankee repaired the tubes by inserting and welding short reinforcing sleeves of an improved material in substantially all of the Plant's steam generator tubes. Repairs were completed in December 1995. The Company's approximately $10-million share of the repair costs adversely affected the Company's 1995 earnings by $0.18 per share, net of taxes, in spite of significant cost-reduction measures implemented by both the Company and Maine Yankee. In addition, the Company incurred incremental replacement-power costs during the outage totaling approximately $29 million, or $0.52 per share, net of taxes, for 1995.
Also in December 1995, the Nuclear Regulatory Commission's (NRC) Office of the Inspector General (OIG) and its Office of Investigations (OI) initiated separate investigations of certain anonymous "whistleblower" allegations of wrongdoing by Maine Yankee and Yankee Atomic Electric Company (Yankee Atomic) in 1988 and 1989 in connection with operating license amendments. On May 9, 1996, the OIG, which was responsible for investigating only the actions of the NRC staff and not those of Maine Yankee or Yankee Atomic, issued its report. The report found deficiencies in the NRC staff's review, documentation, and communications practices in connection with the license amendments, as well as "significant indications of possible licensee violations of NRC requirements and regulations." Any such violations by Maine Yankee are within the purview of the OI investigation, which, with related issues, is being reviewed by the United States Department of Justice. A separate internal investigation commissioned by the boards of directors of Maine Yankee and Yankee Atomic and conducted by an independent law firm noted several areas that could have been improved, including regulatory communications, definition of responsibilities between Maine Yankee and Yankee Atomic, and documentation and tracking of regulatory compliance, but found no wrongdoing by Maine Yankee or Yankee Atomic or any of their employees. Issues raised by the anonymous allegations caused the NRC to limit the Plant to an operating level of approximately 90% of its full thermal capacity, pending resolution of those issues. The Company cannot predict the results of the investigations by the OI and Department of Justice.
The December 1995 allegations caused the Plant's extended tube-sleeving outage to be further extended into January 1996, and the Plant returned to the 90% operating level on January 24. On June 7, 1996, the NRC formally notified Maine Yankee that it would conduct an "Independent Safety Assessment" (ISA) of the Plant as a "follow-on" to the OIG report and to provide an independent evaluation of the safety performance of Maine Yankee by a team of NRC personnel and contractors who were "independent of any recent or significant involvement with the licensing, regulation or inspection of Maine Yankee." The NRC conducted the ISA in the summer of 1996 and released its report on October 7, 1996.
The detailed ISA report identified both deficiencies and strengths in Maine Yankee's performance, and concluded that overall performance at Maine Yankee was "adequate" for operation of the Plant. The ISA team stressed that the deficiencies noted in the report stemmed from two closely related root causes, specifically, (1) that economic pressure to be a low-cost energy provider had limited available resources to address corrective actions and some improvements, and (2) that lack of a "questioning culture" had resulted in a failure to identify or promptly correct significant problems in areas perceived by Maine Yankee to be of low safety significance. In a letter to Maine Yankee accompanying the ISA report, NRC Chairman Shirley Ann Jackson noted that although overall performance at Maine Yankee was considered adequate for operation, a number of significant weaknesses and deficiencies identified in the report would result in NRC violations. The letter also directed Maine Yankee to provide to the NRC its plans for addressing the root causes of the deficiencies noted in the ISA and identified the NRC offices that would be responsible for overseeing corrective actions and taking any appropriate enforcement actions against Maine Yankee.
On December 10, 1996, Maine Yankee filed its formal response to the ISA report with the NRC. In the response, Maine Yankee indicated that it would spend substantial sums on improvements in several areas in 1997 to address the root causes and associated deficiencies noted in the report, and that the improvements would include physical and operating changes at the Plant, along with a 10% increase in staffing, primarily in the engineering and maintenance areas, and other changes. In a release accompanying the response, Maine Yankee stated that a "fundamental shift in corporate culture" would accompany the changes and that Maine Yankee would not seek to return the Plant to the 100% power level from its authorized 90% level until it had reviewed the margins on all the key safety systems at the Plant, which had been another matter of concern to the NRC.
The Plant operated substantially at the 90% capacity level until July 20, 1996, when it was taken off-line after a comprehensive review by Maine Yankee of the Plant's systems and equipment revealed a need to add pressure-relief capacity to the Plant's primary component cooling system. On August 18, 1996, while the Plant was in the restart process, Maine Yankee conducted a review of its electrical circuitry testing procedures pursuant to a generic NRC letter to nuclear-plant licensees that was intended to ensure that every feature of every safety system be routinely tested. During the expanded review, Maine Yankee found a deficiency in an electrical circuit of a safety system and therefore elected to conduct an intensified review of other safety-related circuits to resolve immediately any questions as to the adequacy of related testing procedures. The Plant returned to the 90% operating level on September 3, 1996.
On December 6, 1996, Maine Yankee took the Plant off-line to resolve cable-separation and other operational and design issues. On January 3, 1997, Maine Yankee announced that it would use the opportunity presented by that outage to inspect the Plant's 217 fuel assemblies, since daily monitoring had indicated evidence of a small number of defective fuel rods. As a result of the inspection, Maine Yankee determined that all of the assemblies manufactured by one supplier and currently in the reactor core (approximately one-third of the total) would have to be replaced before the Plant could be restarted. Maine Yankee will therefore keep the Plant off-line for refueling, which had previously been scheduled for late 1997. In addition, Maine Yankee will make use of the outage to inspect the Plant's steam generators, commencing approximately April 1, 1997, for deterioration beyond that which was repaired during the extended 1995 outage. Degradation of steam generators of the age and design of those in use in the Plant has been identified at other plants. If major repairs to, or replacement of, the steam generators were found to be necessary for continued operation of the Plant, Maine Yankee would review the economics of continued operation before incurring the substantial capital expenditures that would be required.
In January, the NRC announced that it had placed the Plant on its "watch list" in "Category 2", which includes plants that display "weaknesses that warrant increased NRC attention", but which are not severe enough to warrant a shut-down order. Plants in category 2 remain in that category "until the licensee demonstrates a period of improved performance." The Plant is one of fourteen nuclear units on the watch list announced that day by the NRC, which regulates slightly over 100 civilian nuclear power plants in the United States.
After year end, Maine Yankee and Entergy Nuclear, Inc. (Entergy), which is a subsidiary of Entergy Corporation, a Louisiana-based utility holding company and leading nuclear plant operator, entered into a contract under which Entergy is providing management services to Maine Yankee. At the same time, officials from Entergy assumed management positions, including President, at Maine Yankee.
While the Plant remains out of service, Maine Yankee must, in addition to replacing the fuel assemblies and conducting an intensive inspection of its steam generators, resolve the cable-separation issues and other known regulatory issues, as well as any additional issues that are discovered during the outage. The Company must obtain the approval of the NRC to restart the Plant, following a mandated NRC process that includes an NRC-approved restart plan and opportunities for public participation. The Company believes the Plant will be out of service at least until August 1997, but cannot predict when or whether all of the regulatory and operational issues will be satisfactorily resolved or what effect the total of the repairs and improvements to the Plant will have on the economics of operating the Plant.
The Company will incur significantly higher costs in 1997 for its share of inspection, repairs and refueling costs at Maine Yankee and will also need to purchase replacement power while the Plant is out of service. While the amount of higher costs is uncertain, Maine Yankee has indicated that it expects it operations and maintenance costs to increase by up to approximately $45 million in 1997, before refueling costs. The Company's share of such costs based on its power entitlement of approximately 38% would be up to approximately $17 million. In addition, the Company estimates its share of the refueling costs will amount to approximately $15 million, of which $10.4 million has been accrued as of December 31, 1996. The Company has been incurring incremental replacement-power costs of approximately $1 million per week while the plant has been out of service and expects such costs to continue at approximately the same rate until the plant returns to service.
The impact of these higher nuclear related costs on the Company's 1997 financial results will be significant and is likely to trigger the low earnings bandwidth provision of the ARP. Under the ARP, actual earnings for 1997 outside a bandwidth of 350 basis points, above or below a 10.68% rate of return allowance, triggers the profit sharing mechanism. A return below the low end of the range provides for additional revenue through rates equal to one-half of the difference between the actual earned rate of return and the 7.18% (10.68 - 3.50) low end of the bandwidth. While the Company believes that the profit sharing mechanism is likely to be triggered in 1997, it cannot predict the amount, if any, of additional revenues that may ultimately result.
Other Nuclear Issues
On December 4, 1996, the Board of Directors of Connecticut Yankee Atomic Power Company voted to permanently shut down the Connecticut Yankee plant, for economic reasons, and to decommission the unit. The Company has a 6% equity interest in Connecticut Yankee, totaling approximately $6.4 million at December 31, 1996. The plant did not operate after July 22, 1996, causing the Company to incur replacement power costs of approximately $1.5 million in 1996. The Company estimates its share of the cost of Connecticut Yankee's continued compliance with regulatory requirements, recovery of its plant investments, decommissioning and closing the plant to be approximately $45.8 million and has recorded a regulatory asset and a liability on its consolidated balance sheet. The Company is currently recovering through rates an amount adequate to recover these expenses.
The Company has a 2.5% ownership interest in Millstone Unit No. 3 which is operated by Northeast Utilities. This facility has been off-line since March 31, 1996 due to NRC concerns regarding license requirements and the Company cannot predict when it will return to service. Millstone Unit No. 3, along with two other units at the same site owned by Northeast Utilities, is on the NRC's "watch list" in "Category 3," which requires formal NRC action before a unit can be restarted. The Company estimates that it will incur approximately $300,000 to $500,000 in replacement power costs each month Millstone Unit No. 3 remains out of service. The Company incurred replacement power costs of $3.5 million in 1996.
Environmental Actions
The Company has been named by the Environmental Protection Agency (EPA) as a "potentially responsible party" (PRP) and has been incurring costs to determine the best method of cleaning up an Augusta, Maine, site formerly owned by a salvage company and identified by the EPA as containing soil contaminated by PCBs from equipment originally owned by the Company. The Company also has been named as a PRP at eleven former gas plant sites, six former waste oil sites, and two former pole treatment and storage locations. Refer to Note 4 to Consolidated Financial Statements, "Commitments and Contingencies - Legal and Environmental Matters," for a more detailed discussion of this matter.
Industry Restructuring and Strandable Costs
The Federal Energy Policy Act of 1992 accelerated planning by electric utilities, including the Company, for a transition to a more competitive industry. The functional areas in which competition will take place, the regulatory changes that will be implemented, and the resulting structure of both the industry and the Company are all uncertain, but regulatory steps have already been taken toward competition in generation and non-discriminatory transmission access. A departure from traditional regulation and industry restructuring, however, could have substantial impacts on the value of utility assets and on electric utilities' abilities to recover their costs through rates. In the absence of full recovery, utilities would find their above-market costs to be "stranded," or unrecoverable, in the new competitive setting.
In January, 1996, the Company filed its recommendations for an orderly transition to competition and adequate reimbursement of its potentially strandable costs with the MPUC. In December 1996, the MPUC issued its Report and Recommended Plan for Electric Utility Restructuring in Maine. The major elements of the MPUC plan, which are similar in most, but not all, respects to the Company's proposal include:
(1) By January 2000, investor owned utilities would transfer all generating assets to entities distinct from transmission and distribution (T&D) assets and obligations.
(2) By January 2006, the Company would be required to divest all generation assets (except Maine Yankee).
(3) By January 2000, investor-owned utilities would be required to transfer the rights to market power from all qualifying facilities contracts.
(4) Contracts between investor-owned utilities and qualifying facilities would remain with the T&D company.
(5) Beginning January 1, 2000, all customers would have the option to purchase power directly from power suppliers or from intermediaries such as load aggregators, power marketers or energy service companies.
(6) Standard-offer service would be provided to customers who do not choose a competitive power provider and who cannot obtain power in the market on reasonable terms.
(7) The MPUC would not regulate companies that produce or sell power once customers can purchase power in a competitive market.
(8) T&D companies would continue to be regulated. T&D companies would have exclusive service territories and an obligation to connect customers to the power grid.
(9) A "reasonable opportunity" to recover strandable costs would be achieved through the regulated rates of the T&D utilities. Amounts recovered could include costs of fulfilling obligations under contracts with NUGs, as well as investments (and returns thereon) and other obligations undertaken by the Company in fulfilling its legal duty to serve, with requirements for the Company to mitigate such costs where practicable.
(10) The MPUC recommended that the Legislature fund low-income assistance programs; otherwise, these programs would continue to be funded through T&D company rates.
(11) All companies selling power to retail customers in Maine would be required to include a minimum amount of renewable energy in their generation mix, and customers would continue to fund cost-effective energy efficiency programs through T&D rates.
The Company has substantial exposure to cost stranding relative to its size. In its January 1996 filing, the Company estimated its net-present-value strandable costs could be approximately $2 billion as of January 1, 1996. These costs represent the excess costs of purchased-power obligations and the Company's own generating costs over the market value of the power, and the costs of deferred charges and other regulatory assets. Of the $2 billion, approximately $1.3 billion is related to above-market costs of purchased-power obligations, approximately $200 million is related to estimated net above-market cost of the Company's own generation, and the remaining $500 million is related to deferred regulatory assets.
The MPUC also provided estimates of strandable costs for the Company, which they found to be within a wide range of a negative $445 million to a positive $965 million. These estimates were prepared using assumptions that differ from those used by the Company, particularly a starting date for measurement of January 1, 2000 versus a measurement starting date of January 1, 1996 utilized by the Company. The MPUC concluded that there is a high degree of uncertainty that surrounds stranded costs numbers, resulting from having to rely on projections and assumptions about future conditions. Given the inherent uncertainty and volatility of these projections, the Company believes that an annual estimation of stranded costs could serve to prevent significant over-or-under-collection beginning in the year 2000.
Estimated strandable costs are highly dependent on estimates of the future market for power. Higher market rates lower stranded cost exposure, while lower market rates increase it. In addition to market-related impacts, any estimate of the ultimate level of strandable costs depends on state and federal regulations; the extent, timing and form that competition for electric service will take; the ongoing level of the Company's costs of operations; regional and national economic conditions; growth of the Company's sales; timing of any changes that may occur from state and federal initiatives on restructuring; and the extent to which regulatory policies ultimately address recovery of strandable costs.
The estimated market rate for power is based on anticipated regional market conditions and future costs of producing power. The present value of future purchased-power obligations and the Company's generating costs reflects the underlying costs of those sources of generation in place today, with reductions for contract expirations and continuing depreciation. Deferred regulatory asset totals include the current uncollected balances and existing amortization schedules for purchased-power contract restructuring and buyouts negotiated by the Company to lessen the impact of these obligations, energy management costs, financing costs, and other regulatory promises. The Company expects its strandable-cost exposure to decline over time as the market price of power increases, non-utility generator (NUG) contracts expire, and regulatory assets are recovered.
Major cost stranding would have a material adverse effect on the Company's financial position. The Company believes it is entitled to recover substantially all of its potential strandable costs, but cannot predict when or if open electric energy competition will occur in its service territory, or how much it might ultimately be allowed to recover through state or federal regulation, the future market price of electricity, or the timing or implementation of any formal recommendations in any regulatory or legislative proceedings dealing with such issues.
The Company believes there are many uncertainties associated with any major restructuring of the electric utility industry in Maine. Among them are: the positions that will ultimately be taken by the Maine Legislature and the MPUC; the role and policies of the FERC in any restructuring involving the Company, the extent and effect of Congressional involvement; whether political consensus is attained; and the extent to which the Company will be permitted to recover its strandable costs.
The Company is pursuing efforts to mitigate its exposure to stranded costs. One method of mitigation that is being actively pursued is securitization of stranded costs including regulatory assets, above market NUG costs and above market company owned generation costs. Pursuant to a future legislative mandate and subject to determination by the MPUC, a portion of existing revenues related to stranded costs would be assigned by the Company for repayment of these costs. The property right created by this assignment could be used as security by a trust to sell bonds, the proceeds of which could be used by the Company to refinance existing obligations. Similarly a portion of existing revenues could also be dedicated directly to payment of above market non-utility power contract obligations, reducing the risks for the suppliers as well as for the Company. Mitigation from this mechanism would result from lower cost financing of stranded costs, enhanced credit worthiness of the utility, which should further reduce the Company's costs, and from increased availability of low cost funds to finance additional purchased power contract restructuring efforts. Any mitigation achieved would be passed on to residential and small commercial customers through lower rates. The Company cannot predict when or if legislative support for the use of securitization may occur.
Open-Access Transmission Service Ruling
On April 24, 1996, the Federal Energy Regulatory Commission (FERC) issued Order No. 888, which requires all public utilities that own, control or operate facilities used for transmitting electric energy in interstate commerce to file open access non-discriminatory transmission tariffs that offer both load-based, network and contract-based, point-to-point service, including ancillary service to eligible customers containing minimum terms and conditions of non-discriminatory service. This service must be comparable to the service they provide themselves at the wholesale level; in fact, these utilities must take wholesale transmission service they provide themselves under the filed tariffs. The order also permits public utilities and transmitting utilities the opportunity to recover legitimate, prudent and verifiable wholesale stranded costs associated with providing open access and certain other transmission services. It further requires public utilities to functionally separate transmission from generation marketing functions and communications. The intent of this order is to promote the transition of the electric utility industry to open competition. Order No. 888 also clarifies federal and state jurisdiction over transmission in interstate commerce and local distribution and provides for deference of certain issues to state recommendations.
On July 9, 1996, the Company and MEPCO submitted compliance filings to meet the new pro forma tariff non-price minimum terms and conditions of non-discriminatory transmission. Since July 9, 1996, the Company and MEPCO have been transmitting energy pursuant to their filed tariffs, subject to refund. FERC subsequently issued Order No. 888-A which generally reaffirms Order No. 888 and clarifies certain terms.
Also on April 24, 1996, FERC issued Order No. 889 which requires public utilities to functionally separate their wholesale power marketing and transmission operation functions and to obtain information about their transmission system for their own wholesale power transactions in the same way their competitors do through the Open Access Same-time Information System (OASIS). The rule also prescribed standards of conduct and protocols for obtaining the information. The standards of conduct are designed to prevent employees of a public utility engaged in marketing functions from obtaining preferential information. The Company participated in efforts to develop a regional OASIS, which was operational January 3, 1997. FERC subsequently approved a New England Power Pool-wide Open Access Tariff, subject to refund and issuance of further orders. The Company also participated in revising the New England Power Pool Agreement, which is pending FERC approval.
Competition and Economic Development
The Company faces competition in several aspects of its traditional business and anticipates that competition will continue to put pressure on both sales and the price the Company can charge for its product. Alternative fuels and recent modifications to regulations that had restricted competition from suppliers outside of the Company's service territory have expanded customers' energy options. As a result, the Company continues to pursue retention of its customer base. This increasingly competitive environment has resulted in the Company's entering into contracts with its wholesale customers, as well as with certain industrial, commercial, and residential customers, to provide their energy needs at prices and margins lower than the current averages.
Pursuant to the pricing-flexibility provisions of the ARP, the Company redesigned some rates to encourage off-peak usage and discourage switching to alternative fuels. These include water-heat and space-heat retention rates, Super-Saver rates, which discount off-peak usage, Diesel Deferral rates, Economic Development rates, and the Maine Made Incentive program, which target small businesses. In 1994, the Company lowered tariffs for its large general-service customers and executed separate five-year definitive agreements with 18 individual customers providing additional reductions. Approximately 40% of annual service area kilowatt-hour sales and 27% of annual revenues are covered under special tariffs allowed under the pricing flexibility provisions of the ARP. These reductions in rates were offered to customers after consideration of associated NUG cost reductions, savings from further NUG consolidations and other general cost reductions. Refer to Note 4 to Consolidated Financial Statements,"Commitments and Contingencies - Competition," for additional information.
Non-Utility Generators
In accordance with prior MPUC policy and the ARP, $113 million of buy-out or contract-restructuring costs incurred since January 1992 were included in Deferred Charges and Other Assets on the Company's balance sheet and will be amortized over their respective fuel savings periods. The Company restructured 40 contracts representing 316 megawatts of capacity that should result in approximately $301 million in fuel savings over the next five years.
The Company also restructured a purchased power contract with a 20 megawatt waste-to-energy facility, which is estimated to save the Company approximately $20 million over the next five years. Refer to Note 6 to Consolidated Financial Statements, "Capacity Arrangements - Non-Utility Generators," for more information.
On October 31, 1997, a contract with a major NUG from which the Company is obligated to purchase electricity at substantially above-market prices will expire. As a result, the Company expects annual operating income to increase by approximately $25 million. Two months of this benefit, or approximately $4 million, will be reflected in 1997 results.
Expansion Of Lines Of Business
The Company is also preparing for competition by expanding its business opportunities through subsidiaries that capitalize on core competencies. One such subsidiary, MaineCom Services, which was approved by the MPUC on July 13, 1995, is developing opportunities in expanding markets by arranging fiber-optic data service for bulk carriers, offering support for cable-TV or "super-cellular" personal-communication vendors, and providing other telecommunications consulting services. The Company invested $10.7 million in MaineCom during 1996 to develop an interchange network from Portland, Maine, to various points in New Hampshire, Massachusetts and Connecticut. In addition, the Company has subsidiaries or divisions that provide energy-efficiency services, utility consulting (domestic and international) and research, engineering and environmental services, management of rivers and recreational facilities, locating of underground utility facilities and infrared photography, real estate brokerage and management, modular housing, and credit and collections services. All subsidiaries utilize skills of former Company employees and compete for business with other companies.
In July 1996, the Company and Maine Electric Power Company, Inc. (MEPCO), a 78%-owned subsidiary of the Company, entered into option agreements with Maritimes and Northeast Pipeline, L.L.C. (M&N) in which the Company and MEPCO agreed to provide exclusive options to M&N to acquire property interests in certain transmission line rights of way to sections of M&N's proposed natural gas pipeline from the United States-Canada border at Woodland, Maine, to Dracut, Massachusetts. In November 1996, while the parties were still engaged in negotiating the terms of the proposed long-term arrangement, the options expired by their terms. Subsequent to the expiration the parties have met to discuss a long-term arrangement for use of the Company's and MEPCO's rights of way for the proposed pipeline, but the Company cannot predict whether final agreement on such an arrangement will be reached.
Expenses and Taxes
The Company's fuel expense, comprising the cost of fuel used for company generation and the energy portion of purchased power (the largest expense category), was 49% of total operating expense in 1996, 51% in 1995, and 54% in 1994. Purchased-power energy expense includes costs associated with purchases from NUGs, which amounted to 74% of this expense category in 1996. Fuel expense fluctuates with changes in the price of oil, the level of energy generated and purchased, and changes in the Company's own generation mix.
Through December 31, 1994, changes in fuel expense were provided rate treatment through a fuel clause. Under the ARP, effective January 1, 1995, fuel-expense recovery is subject to the annual index-based price change. Fuel cost decreases are generally retained by the Company. Fuel expense for MEPCO was fully recoverable through billing to MEPCO participants. See Note 3 to Consolidated Financial Statements, "Regulatory Matters - Open Access Transmission Service Ruling," for a discussion on FERC Order No. 888 and its effect on MEPCO's operations.
The extended outages and reduced operating level at Maine Yankee (see"Maine Yankee Regulatory Issues") resulted in significant increases in fuel expense, including purchased-power energy and purchased-power capacity expense, and affected the Company's generation mix in 1996 and 1995. The Company replaced this power through short-term agreements.
Purchased power expense in 1996 reflected savings of approximately $5.4 million related to a paper company's extended forced outage of its cogeneration facility due to a flood. Additional savings of approximately $6 million were achieved through a five-year capacity exchange arrangement with Northeast Utilities designed to reduce replacement power cost when either Maine Yankee or Northeast Utilities facilities are off-line. Although this agreement was suspended in 1995, Northeast Utilities owed the Company energy, which they delivered in 1996. The Company benefited by purchasing this power at rates lower than market rates. See Note 4 to Consolidated Financial Statements, "Commitments and Contingencies - Competition," for more information on this matter.
The Company's oil-fired generation decreased to 16.3% of the Company's net generation in 1996, compared to 21.6% in 1995 net generation, and 12.1% in 1994. The NUG component of the energy mix decreased from 36.8% in 1995, to 31.4% in 1996, as a result of the ongoing efforts to reform the Company's NUG contracts and an extended forced outage at one NUG facility. The average price of NUG energy of 8.3 cents per kilowatt-hour is significantly higher than the Company's own cost of generation, and much higher than the price of energy on today's open market. The Company continues to try to moderate the cost of non-utility generation by pursuing renegotiation of contracts, by supporting legislative bills that would promote that objective, and by other means such as strict contract-term enforcement.
Purchased-power capacity expense is the non-fuel operation, maintenance, and cost-of-capital expense associated with power purchases, primarily from the Company's share of the Yankee nuclear generating facilities. In 1996, purchased-power capacity expense increased by $15.2 million. Maine Yankee capacity expense decreased by $12.2 million in 1996 , due mainly to the 1995 $10-million steam-generator tube repair costs. 1996 costs increased primarily as a result of an accrual for the 1997 refueling outage that accounted for a year over year increase of $13 million. In addition, expense increased by $9.4 million resulting from the restructuring of a contract with a non-utility generator. This agreement significantly decreased the cost of purchased-power fuel resulting in a net savings in total purchased power costs.
The level of purchased-power capacity expense also fluctuates with the timing of the maintenance and refueling outages at the other Yankee nuclear generating facilities in which the Company has equity interests. The cost of capacity increases during refueling periods. In December 1996, the Board of Directors of Connecticut Yankee Atomic Power Company announced a permanent shutdown of the Connecticut Yankee plant for economic reasons and their intent to decommission the plant. The Company has a 6% equity interest in Connecticut Yankee, totaling approximately $6.4 million at December 31, 1996. Purchased power capacity expense in 1996, 1995 and 1994 includes $11.5 million, $11.5 million, and $10 million, respectively, of costs related to this facility. During 1992, Yankee Atomic Electric Company, in which the Company is a 9.5% equity owner, discontinued power generation and prepared a plan for decommissioning. Purchased-power capacity expense in 1996, 1995, and 1994 contained approximately $4.8 million, $3.9 million, and $5.2 million, respectively, of costs related to this facility. Refer to Note 6 to Consolidated Financial Statements, "Capacity Arrangements - Power Agreements," and "Other Nuclear Issues" above for a more detailed discussion.
The 1996 reduction in other operation and maintenance expense is attributed to the reversal of a reserve of $6.4 million established in 1995 for the Company's workers compensation regulatory asset for which recovery was not certain. In the June 1996 ARP decision, the MPUC approved recovery of this regulatory asset. Also in 1996, the Company increased the workers compensation obligation and charged the increase of $1.6 million to expense. As a result, a net year-over-year reduction of $11.2 million for workers compensation was recorded. The Company did incur an increase in distribution expenses of $4.1 million, mainly due to line-clearance activities. The Company has contractual obligations related to demand-side energy-management programs which increased expense by $2.8 million in 1996. Maintenance expense other than distribution increased $3.5 million, of which $1.4 million was for repairs at the Millstone Unit No. 3 nuclear facility.
The 1995 other operation-and-maintenance expense increase reflects significantly higher charges totaling approximately $27.7 million for amortization and cost of purchased-power contract buy-outs. Also reflected is a one-time charge of $5.6 million related to a Special Retirement Offer (SRO) to all employees aged 50 or more who had at least five years of continuous service. The goal of the SRO was to help the Company achieve financial savings and make the organizational changes it needed to be an effective competitor in the energy marketplace. Approximately 200 employees accepted the SRO.
The Company continued its reengineering effort that began in 1995 to analyze the financial controls and customer service sectors of the business. Employee teams have begun implementing solutions that are expected to yield improvements in work processes and result in cost savings. The Company is also continuing cost containment measures.
Interest expense decreased in 1996 by $1.4 million due to lower levels of Medium-Term Notes and the repurchase of $11.5 million of Series N General and Refunding Mortgage Bonds. Long-term debt interest expense includes $1 million of accelerated amortization of loss on reacquired debt, as specified in the 1996 ARP. In 1995, interest expense included a full year's interest costs on the Company's October 1994 note to the Finance Authority of Maine to finance the buy-out of a major NUG contract, and lower interest cost from a decrease in the amount of Medium-Term Notes outstanding. Short-term interest costs over the period 1994 through 1996 fluctuated with the levels of rates and outstanding balances of short-term debt.
In July 1996, the Company redeemed $14 million of its 8 7/8% Series Preferred Stock at par, under the mandatory and optional sinking-fund provisions of that series. This reduced dividends by approximately $700,000 in 1996. The Company reduced the level of Flexible Money Market Preferred Stock outstanding in 1995 by $5.5 million in anticipation of the 1999 sinking-fund requirement, thereby reducing dividends in 1995 by $300,000.
State and federal income taxes fluctuate with the level of pre-tax earnings and the regulatory treatment of taxes by the MPUC. A settlement with the Internal Revenue Service on audits for the years 1988-1991 provided a decrease to income tax expense of approximately $4.8 million in 1996. The significant increase in income-tax expense for 1995 is due to the impact of the loss from the write-off of deferred balances in accordance with the MPUC's ARP order in 1994. See Note 2 to Consolidated Financial Statements, "Income Taxes," for more information.
Liquidity and Capital Resources
The MPUC approved increases in electric retail rates of 1.26% and 2.43% in 1996 and 1995, respectively, that produced additional cash pursuant to the price cap mechanism in the ARP. Increases in rates under the ARP were based on increases in the related price index, the sharing mechanism and provisions for certain mandated costs. Prior rate increases were provided to fund costs of fuel, energy-management programs, operations, maintenance, systems improvements, and investments in generation needed to ensure the Company's continued ability to provide reliable electric service.
Approximately $141.7 million of cash was provided from net income after adding back non-cash items. Approximately $16.2 million of cash was used for fluctuations in working capital. Other operating activities, including the financing of deferred energy-management programs and the buy-out of NUG contracts, required cash resources.
The level of cash balances and activity in capital investment programs have required little investment-related activity during 1996 and 1995. The issuance and redemption of Medium-Term Notes and the purchase of 8 7/8% Series Preferred Stock used $24 million and $14 million, respectively, of cash during 1996. Dividends paid on common stock were $29.2 million, while preferred-stock dividends were $9.8 million.
Capital-investment activities, primarily construction expenditures, utilized $57.1 million in cash during 1996. Construction expenditures comprised approximately $6.3 million for generating projects, $3.0 million for transmission, $27.9 million for distribution, and $9.7 million for general facilities and other construction expenditures. The Company invested $12.1 million in subsidiaries in 1996, of which $10.7 million was in MaineCom Services.
The Company estimates its capital expenditures for the period 1997 through 2001 at approximately $302 million. Actual capital expenditures will depend upon the availability of capital and other resources, load forecasts, customer growth, and general business conditions. During the five-year period, the Company also anticipates incurring approximately $462 million for sinking funds, and debt and equity maturities.
The Company estimates that for the period 1997 through 2001, internally generated funds from operating activities should provide a substantial portion of the construction-program requirements. However, the availability at any particular time of internally generated funds for such requirements will depend on working-capital needs, market conditions, and other relevant factors.
Replacement power costs and increased operation, maintenance and refueling costs for Maine Yankee will have a significant negative effect on cash and liquidity in 1997. The Company has been incurring incremental replacement-power costs of approximately $1 million per week while the plant has been out of service and expects such costs to continue at approximately the same rate until the plant returns to service. Maine Yankee has indicated that it expects its operations and maintenance costs to increase by up to approximately $45 million, before refueling costs. The Company's share of such costs would be up to approximately $17 million. In addition, the Company estimates its share of the refueling costs will amount to approximately $15 million. Internally generated funds from operating activities will not be sufficient to meet these demands. The Company also plans to utilize its Medium-Term Note program and revolving credit facilities, as described below, for these cash requirements.
The Company's $150-million Medium-Term Note program was implemented to provide flexibility to meet financing needs and provide access to a broad range of debt maturities. As of December 31, 1996, $68 million of Medium-Term Notes were outstanding which, under the terms of the program, permits issuance of an additional $82 million of such notes. The Company is planning to seek the consent of its preferred stockholders to increase the capacity of the Medium-Term Note program from $150 million to $500 million at its annual meeting of stockholders on May 15, 1997, in order to increase its financing flexibility in anticipation of restructuring and increased competition. The Company cannot predict whether such consent will be obtained.
In 1996, the Company deposited approximately $29.6 million in cash with the Trustee under the Company's General and Refunding Mortgage Indenture in satisfaction of the renewal and replacement fund and other obligations under the Indenture. The total of such cash on deposit with the Trustee as of December 31, 1996, was approximately $59.5 million. Under the Indenture such cash may be applied at any time, at the direction of the Company, to the redemption of bonds outstanding under the Indenture at a price equal to the principal amount of the bonds being redeemed, without premium, plus accrued interest to the date fixed for redemption. Such cash may also be withdrawn by the Company by substitution of allocated property additions or available bonds.
To support its short-term capital requirements, on October 23, 1996 , the Company entered into a $125 million revolving credit facility with several banks, with The First National Bank of Boston and The Bank of New York acting as agents for the lenders. The credit facility has two tranches: a $75 million, 364-day revolving credit facility that matures on October 22, 1997, and a $50-million, 3-year revolving credit facility that matures on October 23, 1999. Both credit facilities require annual fees on the unused portion of the credit lines. The fees are based on the Company's credit ratings and allow for various borrowing options including LIBOR-priced, base-rate-priced and competitive-bid-priced loans. Access to commercial paper markets has been substantially reduced, if not precluded, as a result of downgrading of the Company's credit ratings. The amount of outstanding short-term borrowing will fluctuate with day-to-day operational needs, the timing of long-term financing, and market conditions. There was $7.5 million outstanding as of December 31, 1996, under this agreement.
Factors That May Affect Future Results
This management's discussion and analysis section contains forecast information items that are "forward-looking statements" as defined in the Private Securities Litigation Reform Act of 1995. All such forward-looking information is necessarily only estimated. There can be no assurance that actual results will not materially differ from expectations. Actual results have varied materially and unpredictably from past expectations.
Factors that could cause actual results to differ materially include, among other matters, electric utility restructuring, including the ongoing state and federal activities; future economic conditions; earnings-retention and dividend-payout policies; developments in the legislative, regulatory, and competitive environments in which the Company operates; and other circumstances that could affect anticipated revenues and costs, such as unscheduled maintenance or repair requirements and compliance with laws and regulations. Nuclear investments and obligations, which are subject to increased regulatory scrutiny, and the amount of expenditures and the timing of the return of the Maine Yankee generating plant to service, could have a material effect on the Company's financial position.
Item 8.
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
Page
Index to Financial Statements and Financial Statement Schedule
Financial Statements:
Management report on responsibility for financial reporting 43
Report of Independent Accountants 44
Consolidated Statement of Earnings for the three years ended December 31, 1996, 1995 and 1994 45
Consolidated Balance Sheet as of December 31, 1996 and 1995 46
Consolidated Statement of Cash Flows 48
Consolidated Statement of Capitalization and Interim Financing 50
Consolidated Statement of Changes in Common-Stock Investment 51
Notes to Consolidated Financial Statements 52
Financial Statement Schedule:
Schedule II - Valuation and Qualifying Accounts 101
Report of Management
The Management of Central Maine Power Company and its subsidiary is responsible for the consolidated financial statements and the related financial information appearing in this annual report. The financial statements are prepared in conformity with generally accepted accounting principles and include amounts based on informed estimates and judgments of management. The financial information included elsewhere in this report is consistent, where applicable, with the financial statements.
The Company maintains a system of internal accounting controls that is designed to provide reasonable assurance that the Company's assets are safeguarded, transactions are executed in accordance with management's authorization, and the financial records are reliable for preparing the financial statements. While no system of internal accounting controls can prevent the occurrence of errors or irregularities with absolute assurance, management's objective is to maintain a system of internal accounting controls that meets its goals in a cost-effective manner.
The Company has policies and procedures in place to support and document the internal accounting controls that are revised on a continuing basis. Internal auditors conduct reviews, provide ongoing assessments of the effectiveness of selective internal controls, and report their findings and recommendations for improvement to management.
The Board of Directors has established an Audit Committee, composed entirely of outside directors, which oversees the Company's financial reporting process on behalf of the Board of Directors. The Audit Committee meets periodically with management, internal auditors, and the independent public accountants to review accounting, auditing, internal accounting controls, and financial reporting matters. The internal auditors and the independent public accountants have full and free access to meet with the Audit Committee, with or without management present, to discuss auditing or financial reporting matters.
Coopers & Lybrand L.L.P., independent public accountants, has been retained to audit the Company's consolidated financial statements. The accompanying report of independent public accountants is based on their audit, conducted in accordance with generally accepted auditing standards, including a review of selected internal accounting controls and tests of accounting procedures and records.
David T. Flanagan David E. Marsh President and Chief Executive Officer Vice President, Corporate Services, Treasurer and Chief Financial Officer
REPORT OF INDEPENDENT ACCOUNTANTS
To the Directors and Stockholders Central Maine Power Company
We have audited the consolidated financial statements and the financial statement schedule of Central Maine Power Company and subsidiary listed in Item 8 and Item 14(a) of this Form 10-K. These financial statements and financial statements schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our 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 Central Maine Power Company and subsidiary as of December 31, 1996 and 1995, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 1996, in conformity with generally accepted accounting principles. In addition, in our opinion, the financial statement schedule referred to above, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information required to be included therein.
Coopers & Lybrand L.L.P. Portland, Maine January 23, 1997
Consolidated Financial Statements
Consolidated Statement of Earnings
The accompanying notes are an integral part of these financial statements.
Stockholders' Investment and Liabilities Capitalization (see separate statement) (Note 7) Common-stock investment $ 511,578 $ 490,005 Preferred stock 65,571 65,571 Redeemable preferred stock 53,528 67,528 Long-term obligations 587,987 622,251 Total Capitalization 1,218,664 1,245,355 Current liabilities and interim financing Interim financing (see separate statement) (Note 7) 32,500 34,000 Sinking-fund requirements (Note 7) 9,375 10,455 Accounts payable 93,197 108,170 Dividends payable 9,512 9,823 Accrued interest 11,610 12,648 Accrued income taxes (Note 2) - 3,668 Miscellaneous current liabilities 21,342 13,870 Total Current Liabilities and Interim Financing 177,536 192,634 Commitments and Contingencies (Notes 4 and 6) Reserves and deferred credits Accumulated deferred income taxes (Note 2) 357,994 351,868 Unamortized investment tax credits (Note 2) 31,988 32,452 Yankee Atomic purchased-power contract (Note 6) 16,463 21,396 Connecticut Yankee purchased-power contract (Note 6) 45,769 - Regulatory liabilities - deferred taxes (Note 2) 52,616 50,366 Other reserves and deferred credits (Note 5) 109,884 98,848 Total Reserves and Deferred Credits 614,714 554,930 Total Stockholders' Investment and Liabilities $2,010,914 $1,992,919
The accompanying notes are an integral part of these financial statements.
For purposes of the statement of cash flows, the Company considers all highly liquid instruments purchased having a maturity of three months or less to be cash equivalents.
The accompanying notes are an integral part of these financial statements.
Consolidated Statement of Capitalization and Interim Financing
The accompanying notes are an integral part of these financial statements.
Consolidated Statement of Changes in Common-Stock Investment
Notes to Consolidated Financial Statements
Note 1: Summary of Significant Accounting Policies
General Description
Central Maine Power Company (the Company) is an investor-owned public utility primarily engaged in the sale of electric energy at the wholesale and retail levels to residential, commercial, industrial, and other classes of customers in the State of Maine.
Financial Statements
The consolidated financial statements include the accounts of the Company and its 78%-owned subsidiary, Maine Electric Power Company, Inc. (MEPCO). The Company accounts for its investments in associated companies not subject to consolidation using the equity method. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Regulation
The rates, operations, accounting, and certain other practices of the Company and MEPCO are subject to the regulatory authority of the Maine Public Utilities Commission (MPUC) and the Federal Energy Regulatory Commission (FERC).
Electric Operating Revenues
Electric operating revenues include amounts billed to customers and estimates of unbilled sales and fuel costs. Through December 31, 1994, the Company's approved tariffs provided for the recovery of the cost of fuel used in Company generating facilities and purchased-power energy costs. The Company also collected interest on unbilled fuel and paid interest on fuel-related over-collections. Effective January 1, 1995, with the implementation of the Alternative Rate Plan (ARP), these costs are no longer subject to reconciliation through the annual fuel-cost adjustment. See Note 3, "Regulatory Matters - Alternative Rate Plan," for further information.
Depreciation
Depreciation of electric property is calculated using the straight-line method. The weighted average composite rate was 3.0% in each of 1996, 1995 and 1994.
Allowance for Funds Used During Construction (AFC)
An allowance for funds (including equity funds), a non-operating item, is capitalized as an element of the cost of construction. The debt component of AFC is classified as a reduction of interest expense, while the equity component, a non-cash item, is classified as other income. The average AFC rates applied to construction were 8.7% in 1996, 8.4% in 1995, and 8.9% in 1994.
Asset Valuation
The Company adopted Statement of Financial Accounting Standards No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of," effective January 1, 1996. The standard requires impairment losses on long-lived assets to be recognized when an asset's book value exceeds its expected future cash flows (undiscounted and without interest). The new standard also imposes stricter criteria for retention of regulatory-created assets by requiring that such assets be probable of future recovery at each balance sheet date. The Company's adoption of this standard in 1996 had no impact on accompanying financial statements. However, this may change in the future as changes are made in the current regulatory framework or as competitive factors influence wholesale and retail pricing in the electric utility industry.
Deferred Charges and Other Assets
The Company defers and amortizes certain costs in a manner consistent with authorized or probable ratemaking treatment. The Company capitalizes carrying costs as a part of certain deferred charges, principally energy-management costs, and classifies such carrying costs as other income. The following table depicts the components of deferred charges and other assets at December 31, 1996, and 1995:
(Dollars in thousands) 1996 1995 NUG contract buy-outs and restructuring (Note 6) $113,796 $126,485 Energy-management costs 35,986 36,224 Postretirement benefits (Note 5) 22,962 21,849 Financing costs 20,684 24,775 Environmental site clean-up costs (Note 4) 7,876 7,375 Non-operating property, net 7,176 7,486 Electric Lifeline Program 2,368 3,603 Other, including MEPCO 27,355 32,266 Total $238,203 $260,063
Certain costs are being amortized and recovered in rates over periods ranging from three to 30 years. Amortization expense for the next five years is shown below:
(Dollars in thousands) Amount 1997 $26,790 1998 26,053 1999 23,910 2000 22,807 2001 19,304
Recoverable Costs of Seabrook I and Abandoned Projects
The recoverable after-tax investments in Seabrook I and abandoned projects are reported as assets, pursuant to May 1985 and February 1991 MPUC rate orders. The Company is allowed a current return on these assets based on its authorized rate of return. In accordance with these rate orders, the deferred taxes related to these recoverable costs are amortized over periods of four to 10 years. As of December 31, 1996, substantially all deferred taxes related to Seabrook I have been amortized. The recoverable investments as of December 31, 1996, and 1995 are as follows:
December 31 Recovery (Dollars in thousands) 1996 1995 periods ending Recoverable costs of: Seabrook I $141,084 $141,084 2015 Other Projects 57,491 57,491 2001 198,575 198,575 Less: accumulated amortization 108,209 102,248 Less: related income taxes 815 1,200 Total Net Recoverable Investment $ 89,551 $ 95,127
Note 2: Income Taxes
The components of federal and state income-tax provisions (benefits) reflected in the Consolidated Statement of Earnings are as follow:
Year ended December 31 (Dollars in thousands) 1996 1995 1994 Federal: Current $ 21,682 $ 15,965 $(18,579) Deferred 5,751 2,278 2,175 Investment tax credits, net (464) (1,715) (2,512) Regulatory deferred (623) (2,619) 8,379 Total Federal Taxes 26,346 13,909 (10,537) State: Current $ 7,022 $ 3,777 $ (6,586) Deferred (10) 343 3,003 Regulatory deferred (1,336) (1,997) (23) Total State Taxes 5,676 2,123 (3,606) Total Federal and State Income Taxes $ 32,022 $ 16,032 $(14,143) Federal and state income taxes charged to: Operating expenses $ 30,125 $ 13,328 $ 28,300 Other income 1,897 2,704 (42,443) $ 32,022 $ 16,032 $(14,143)
Federal income tax, excluding federal regulatory deferred taxes, differs from the amount of tax computed by multiplying income before federal tax by the statutory federal rate. The following table reconciles the statutory federal rate to a rate determined by dividing the total federal income-tax expense by income before that expense:
*During 1995, the Company adjusted the deferred tax balances for certain normalized items (Note 3).
The Company and MEPCO record deferred income-tax expense in accordance with regulatory authority; they also defer investment and energy tax credits and amortize them over the estimated lives of the assets that generated the credits.
The Company recognizes deferred tax liabilities and assets for the expected future tax consequences of events that have been included in the financial statements or tax returns as required under Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes" (SFAS No. 109). Under this method, effective January 1, 1993, deferred tax liabilities and assets are determined based on the difference between the financial statement and tax basis of assets and liabilities using the enacted tax rates in effect in the year in which the differences are expected to reverse.
At-adoption adjustments to accumulated deferred taxes were required, as well as the recognition of a liability to ratepayers for deferred taxes established in excess of the amount calculated using income-tax rates applicable to future periods. Additionally, deferred taxes were recorded for the cumulative timing differences for which no deferred taxes had been recorded previously. Concurrently, the Company, in accordance with Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS No. 71), recorded a regulatory asset representing its expectations that, consistent with current and expected ratemaking, it will collect these additional taxes recorded through rates when they are paid in the future.
A valuation allowance has not been recorded at December 31, 1996, and 1995, as the Company expects that all deferred income tax assets will be realized in the future.
Accumulated deferred income taxes consisted of the following in 1996 and 1995: (Dollars in thousands) 1996 1995 Deferred tax assets resulting from: Investment tax credits, net $ 22,050 $ 22,370 Regulatory liabilities 17,919 13,882 Alternative minimum tax 10,241 23,850 All other 26,588 22,545 76,798 82,647 Deferred tax liabilities resulting from: Property 288,370 273,565 Abandoned plant 61,729 65,573 Regulatory assets 85,508 96,577 435,607 435,715 Accumulated deferred income taxes, end of year, net $358,809 $353,068 Accumulated deferred income taxes, recorded as: Accumulated deferred income taxes $357,994 $351,868 Recoverable costs of Seabrook 1 and abandoned projects, net 815 1,200 $358,809 $353,068
Note 3: Regulatory Matters
Alternative Rate Plan
In December 1994, the MPUC approved a stipulation signed by most of the parties to the Company's ARP proceeding. This follow-up proceeding to the Company's 1993 base-rate case was ordered by the MPUC in an effort to develop a five-year plan containing price-cap, profit-sharing, and pricing-flexibility components. Although the ARP is a major reform, the MPUC is continuing to regulate the Company's operations and prices, provide for continued recovery of deferred costs, and specify a range for its authorized rate of return. The ARP was adopted effective January 1, 1995.
The Company believes the ARP provides the benefits of needed pricing flexibility to set prices between defined floor and ceiling levels in three service categories: (1) existing customer classes, (2) new customer classes for optional targeted services, and (3) special-rate contracts. The Company believes that the added flexibility will position it more favorably to meet the competition from other energy sources. See Note 4 to Consolidated Financial Statements, "Commitments and Contingencies - Competition," for a discussion of actions taken by the Company under the ARP's pricing flexibility provisions.
The ARP also contains provisions to protect the Company and ratepayers against unforeseen adverse results from its operation. These include review by the MPUC if the Company's actual return on equity falls outside a designated range, a mid-period review of the ARP by the MPUC in 1997 (including possible modification or termination), and a "final" review by the MPUC in 1999 to determine whether or with what changes the ARP should continue in effect after 1999. The Company will submit its 1997 compliance filing and the mid-period review filing in March 1997. The mid-period review decision is expected from the MPUC by September 30, 1997.
The Company believes, as stated in the MPUC's order approving the ARP, that operation under the ARP continues to meet the criteria of SFAS No. 71. In its order, the MPUC reaffirmed the applicability of previous accounting orders allowing the Company to reflect amounts as deferred charges and regulatory assets. As a result, the Company will continue to apply the provisions of SFAS No. 71 to its accounting transactions and its future financial statements.
The ARP contains a mechanism that provides price caps on the Company's retail rates to increase annually on July 1, commencing July 1, 1995, by a percentage combining (1) a price index, (2) a productivity offset, (3) a sharing mechanism, and (4) flow-through items and mandated costs. The price cap applies to all of the Company's retail rates, including the Company's fuel-and-purchased power cost, which previously had been treated separately. Under the ARP, fuel expense is no longer subject to reconciliation or specific rate recovery, but is subject to the annual indexed price-cap changes.
A specified standard inflation index is the basis for each annual price-cap change. The inflation index is reduced by the sum of two productivity factors, a general productivity offset of 1.0%, (0.5% for 1995), and a second formula-based offset that started in 1996 intended to reflect the limited effect of inflation on the Company's purchased-power costs during the proposed five-year initial term of the ARP.
The sharing mechanism will adjust the subsequent year's July price-cap change in the event the Company's earnings are outside a range of 350 basis points above or below the Company's allowed return on equity, starting at the 10.55% allowed return (1995) and indexed annually for changes in capital costs. Outside that range, profits and losses would be shared equally by the Company and ratepayers in computing the price-cap adjustment. This feature commenced with the price-cap change of July 1, 1996, and reflected 1995 results.
The ARP also provides for partial flow-through to ratepayers of cost savings from non-utility generator contract buy-outs and restructuring, recovery of energy-management costs, penalties for failure to attain customer-service and energy-efficiency targets, and specific recovery of half the costs of the transition to Statement of Financial Accounting Standards No. 106, "Accounting for Postretirement Benefits Other Than Pensions" (SFAS No. 106), the remaining 50% to be recovered through the annual price-cap change. The ARP also generally defines mandated costs that would be recoverable by the Company notwithstanding the index-based price cap. To receive such treatment, a mandated cost's revenue requirement must exceed $3 million and have a disproportionate effect on the Company or the electric-power industry.
Effective July 1, 1995, the MPUC approved a 2.43% increase pursuant to the annual price-change provision in the ARP. The primary component of the increase was the inflation-index change of 2.92%, reduced by a productivity offset of 0.5%, and increased by .01% for flowthrough items and mandated costs. On June 28, 1996, the MPUC approved a 1.26% increase in rates under the ARP effective July 1, 1996. The components of the increase included the inflation-index of 2.55% and earnings sharing and mandated cost items of 0.64%, reduced by the productivity offset of 1.0% and sharing of contract restructuring and buyout savings of 0.93%.
The Company agreed in the ARP negotiations to record charges in 1994 reflecting the write-off of approximately $100 million ($60 million, net of tax, or $1.85 per share) which consisted of undercollected balance of fuel and purchased power costs, unrecovered energy-management costs, unrecovered unbilled ERAM revenues and unrecovered deferred charges related to the possible extension of the operating life of one of the Company's generating stations. The $100-million charge was included in "Other income (expense) - Other, net" on the Consolidated Statement of Earnings. The $40-million tax impact was included in "Other income (expense) - Income taxes." These charges, with the other provisions of the ARP, lessen the impact of future price increases for MPUC-mandated and fuel-related costs.
Restructuring
The Maine Legislature in 1995 took action by Legislative Resolve (Resolve) to develop recommendations for the MPUC on the future structure of the electric utility industry in Maine. The Resolve stated that the findings of the MPUC would have no legal effect, but that the MPUC's study would"...provide information to the Legislature in order to allow the Legislature to make informed decisions when it evaluates those plans"
In accordance with the Resolve, on December 31, 1996, the MPUC, pursuant to the mandate of the Maine Legislature, filed its Report and Recommended Plan for Utility Industry Restructuring (Restructuring Report).
The Company believes there are many uncertainties associated with any major restructuring of the electric utility industry in Maine. Among them are: the actions that will be ultimately taken by the legislature and the MPUC; the role of the FERC in any restructuring involving the Company and the ultimate positions it will take on relevant issues within its jurisdiction; to what extent the United States Congress will become involved in resolving or redefining the issues through legislative action and, if so, with what results; whether the necessary political consensus can be reached on the significant and complex issues involved in changing the long-standing structure of the electric-utility industry; and, particularly with respect to the Company, to what extent utilities will be permitted to recover strandable costs.
The Company has substantial exposure to cost stranding relative to its size. The Company estimated its net-present-value strandable costs could be approximately $2 billion as of January 1, 1996. These costs represent the excess costs of purchased-power obligations and the Company's own generating costs over the market value of the power, and the costs of deferred charges and other regulatory assets. Of the $2 billion, approximately $1.3 billion is related to above-market costs of purchased-power obligations, approximately $200 million is related to estimated net above-market cost of the Company's own generation, and the remaining $500 million is related to deferred regulatory assets.
Meeting the Requirements of SFAS No. 71
The Company continues to meet the requirements of SFAS No. 71, as described above. The standard provides specialized accounting for regulated enterprises, which requires recognition of assets and liabilities that enterprises in general could not record. Examples of regulatory assets include deferred income taxes associated with previously flowed through items, NUG buyout costs, losses on abandoned plants, deferral of postemployment benefit costs, and losses on debt refinancing. If an entity no longer meets the requirements of SFAS No. 71, then regulatory assets and liabilities must be written off.
The ARP provides incentive-based rates intended to recover the cost of service plus a rate of return on the Company's investment together with a sharing of the costs or earnings between ratepayers and the shareholders should the earnings be less than or exceed a target rate of return. The Company has received recognition from the MPUC that the rates implemented as a result of the ARP continue to provide specific recovery of costs deferred in prior periods.
The MPUC's Restructuring Report submitted to the Legislature in December 1996 recognizes that a reasonable opportunity to recover strandable costs is essential to a successful transition to competition, with incentives for the Company to mitigate such costs where practicable. The Company is actively pursuing securitization of regulatory assets, which would provide further assurance of their recoverability.
Open-Access Transmission Service Ruling
On April 24, 1996, FERC issued Order No. 888, which requires all public utilities that own, control or operate facilities used for transmitting electric energy in interstate commerce to file open access non-discriminatory transmission tariffs that offer both load-based, network and contract-based, point-to-point service, including ancillary service to eligible customers containing minimum terms and conditions of non-discriminatory service. This service must be comparable to the service they provide themselves at the wholesale level; in fact, these utilities must take wholesale transmission service they provide themselves under the filed tariffs. The order also permits public utilities and transmitting utilities the opportunity to recover legitimate, prudent and verifiable wholesale stranded costs associated with providing open access and certain transmission services. It further requires public utilities to functionally separate transmission from generation marketing functions and communications. The intent of this order is to promote the transition of the electric utility industry to open competition. Order No. 888 also clarifies federal and state jurisdiction over transmission in interstate commerce and local distribution and provides for deference of certain issues to state recommendations.
On July 9, 1996, the Company and MEPCO submitted its compliance filings to meet the new pro forma tariff non-price minimum terms and conditions of non-discriminatory transmission. Since July 9, 1996, the Company and MEPCO have been transmitting energy pursuant to their filed tariffs, subject to refund. FERC subsequently issued Order No. 888-A, which reaffirms Order No. 888 and clarifies certain terms.
Also on April 24, 1996, FERC issued Order No. 889 which requires public utilities to functionally separate their wholesale power marketing and transmission operation functions and to obtain information about their transmission system for their own wholesale power transactions in the same way their competitors do through the Open Access Same-time Information System (OASIS). The rule also prescribed standards of conduct and protocols for obtaining the information. The standards of conduct are designed to prevent employees of a public utility engaged in marketing functions from obtaining preferential information. The Company participated in efforts to develop a regional OASIS, which was operational January 3, 1997. FERC subsequently approved a New England Power Pool-wide Open Access Tariff, subject to refund and issuance of further orders. The Company also participated in revising the New England Power Pool Agreement, which is pending FERC approval.
Note 4: Commitments and Contingencies
Construction Program
The Company's plans for improving and expanding generating, transmission, distribution facilities, and power-supply sources are under continuing review. Actual construction expenditures will depend upon the availability of capital and other resources, load forecasts, customer growth, and general business conditions. The Company's current forecast of capital expenditures for the five-year period 1997 through 2001, are as follows:
(Dollars in millions) 1997 1998-2001 Total Type of Facilities: Generating projects $ 8 $ 33 $ 41 Transmission 3 14 17 Distribution 27 124 151 General facilities and other 18 75 93 Total Estimated Capital Expenditures $56 $246 $302
Competition
In September 1994, the Town of Madison's Department of Electric Works (Madison), a wholesale customer of the Company, began receiving power from Northeast Utilities (NU) as a result of a competitive bidding process available under the federal Energy Policy Act of 1992. Substantially all of the 45 megawatts involved supply the large paper-making facility of Madison Paper Industries (MPI) in Madison's service territory that had been served directly by the Company under a special service agreement with Madison during the preceding 12 years.
The MPUC approved the stipulation filed by the Company, Madison, and NU, whereby the related MPUC and FERC regulatory proceedings were deemed to be settled among the parties, and the Company withdrew its request for compensation for stranded costs. In return, NU agreed to pay the Company $8.4 million over a seven-year period, MPI agreed to pay the Company $1.4 million over a three-year period, a transmission rate was agreed upon for the Company's transmission service to Madison commencing September 1, 1994, and the parties agreed that Madison would be supplied by NU through 2003, with Madison having an option for an additional five years. In addition, NU and the Company agreed to a five-year capacity exchange arrangement designed to achieve significant replacement-power cost savings for the Company when the Company's largest source of generation, the Maine Yankee Plant, is off-line, and provides Maine Yankee power to NU when certain NU facilities are shut down. The agreement provides more economic benefit to the Company than if it had under-bid NU for Madison's business, but less than if Madison stayed on the Company's system at the former rates. The Company records income under this contract as the amounts are received.
Madison was the largest of the Company's three wholesale customers. The Company later reached agreement with its other two wholesale customers to continue to supply them at negotiated prices and margins that are lower than the previous averages. Subsequent to year end, these customers initiated a request for proposals to supply their energy needs after 1998.
During 1994, the Company engaged in discussions with its large general-service customers. Those customers have alternative energy options that the Company believed needed to be addressed by lowering its applicable tariffs. In response to those discussions, in November 1994, the Company filed revised tariff schedules lowering prices 15% for its two high-voltage transmission-level rate classes.
The Company then entered into five-year definitive agreements with 18 of these customers that lock-in non-cumulative rate reductions of 15% for the three years 1995 through 1997, 16% for 1998, and 18% for 1999, below the December 1, 1994, levels. These contracts also protect these customers from price increases that might otherwise be allowed under the ARP. The participating customers agreed to take electrical service from the Company for five years and not to switch fuels, install new self-generation equipment, or seek another supplier of electricity for existing electrical load during that period. New electrical load in excess of a stated minimum level could be served by other sources, but the Company could compete for that load.
The Company believes that without offering the competitive pricing provided in the agreements, a number of these customers would be likely to install additional self-generation or take other steps to decrease their electricity purchases from the Company. The revenue loss from such a usage shift could have been substantial.
The Company estimates that based on the rate reductions effective January 1, 1995, its gross revenues were approximately $27 million lower in 1995, and approximately $45 million lower in 1996, than would have been the case if these customers continued to pay full retail rates without reducing their purchases from the Company.
However, these rate reductions were negotiated giving consideration to important related cost savings. Electricity price changes affect the cost of some NUG power contracts. The reduction in rates to large customers reduced purchased-power costs by approximately $20 million as a result of linkage between retail tariffs and some contract prices.
Legal and Environmental Matters
The Company is a party in legal and administrative proceedings that arise in the normal course of business. In connection with one such proceeding, the Company has been named a potentially responsible party (PRP) and has been incurring costs to determine the best method of cleaning up an Augusta, Maine, site formerly owned by a salvage company and identified by the Environmental Protection Agency (EPA) as containing soil contaminated by polychlorinated biphenyls (PCBs) from equipment originally owned by the Company.
In 1995, the EPA approved a remedy to adjust the soil cleanup standard to 10 parts per million. The cleanup method using solvent extraction was found to be technically infeasable. On July 30, 1996, the EPA approved the off-site disposal of the contaminated soil to a EPA licensed secure landfill.
The Company believes that its share of the remaining costs of the cleanup under the approved remedy could total approximately $2.7 million to $4.2 million. This estimate is net of an agreed partial insurance recovery and the 1993 court-ordered contribution of 41% from Westinghouse Electric Corp., but does not reflect any possible contributions from other insurance carriers the Company has sued, or from any other parties. The Company has recorded an estimated liability of $2.7 million and an equal regulatory asset, reflecting an accounting order to defer such costs and the anticipated ratemaking recovery of such costs when ultimately paid. In addition, the Company has deferred, as a regulatory asset, $5.1 million of costs incurred through December 31, 1996.
The Company cannot predict with certainty the level and timing of the cleanup costs, the extent they will be covered by insurance, or their ratemaking treatment, but believes it should recover substantially all of such costs through insurance and rates.
Other Environmental Sites
The Company has been named as a PRP at eleven former manufactured gas plant sites, six former waste oil sites, and two former pole treatment and storage locations. The Company believes that its share of the investigation and cleanup and other costs associated with these sites could total approximately $0.9 million which was charged to income in 1996. The Company believes that the ultimate resolution of current legal and environmental proceedings will not have a material adverse effect on its financial condition.
Nuclear Insurance
The Price-Anderson Act (Act) is a federal statute providing, among other things, a limit on the maximum liability for damages resulting from a nuclear incident. The liability is provided for by existing private insurance and by retrospective assessments for costs in excess of that covered by insurance, up to $79.3 million for each reactor owned, with a maximum assessment of $10 million per reactor in any year. Based on the Company's indirect ownership in four nuclear-generation facilities (See Note 6, "Capacity Arrangements - Power Agreements") and its 2.5% ownership interest in the Millstone Unit No. 3 nuclear plant, the Company's retrospective premium could be as high as $6 million in any year, for a cumulative total of $47.6 million, exclusive of the effect of inflation indexing and a 5% surcharge in the event that total public liability claims from a nuclear incident should exceed the funds available to pay such claims.
In addition to the insurance required by the Act, the nuclear generating facilities referenced above carry additional nuclear property-damage insurance. This additional insurance is provided from commercial sources and from the nuclear electric-utility industry's insurance company through a combination of current premiums and retrospective premium adjustments. Based on current premiums and the Company's indirect and direct ownership in nuclear generating facilities, this adjustment could range up to approximately $7.7 million annually.
Note 5: Pension and Other Post-Employment Benefits
Pension Benefits
The Company has two separate non-contributory, defined-benefit plans that cover substantially all of its union and non-union employees. The Company's funding policy is to contribute amounts to the separate plans that are sufficient to meet the funding requirements set forth in the Employee Retirement Income Security Act (ERISA), plus such additional amounts as the Company may determine to be appropriate. Plan benefits under the non-union retirement plan are based on average final earnings, as defined within the plan, and length of employee service; benefits under the union plan are based on average career earnings and length of employee service.
During 1995, the Company offered a Special Retirement Offer (SRO) to qualifying employees. Approximately 200 employees accepted the offer. The $7-million cost of the SRO was included in pension expense. As part of the SRO, the plans were amended to add five years to age and five years to credited service for all plan participants for purposes of eligibility and early retirement discounts. Early Retirement Incentive Program (ERIP) expenses for 1994 relate to a 1991 ERIP reflected in accordance with an MPUC accounting order.
A summary of the components of net periodic pension cost for the non-union and union defined-benefit plans in 1996, 1995 and 1994 follows:
Assumptions used in accounting for the non-union and union defined-benefit plans in 1996, 1995, and 1994 are as follows:
1996 1995 1994 Weighted average discount rate 7.50% 7.25% 8.25% Rate of increase in future compensation levels 4.5% 4.5% 5.0% Expected long-term return on assets 8.5% 8.5% 8.5%
The following table sets forth the actuarial present value of pension-benefit obligations, the funded status of the plans, and the liabilities recognized on the Company's balance sheet at December 31, 1996, and 1995:
Savings Plan
The Company offers an employee savings plan to all employees which allows participants to invest from 2% to 15% of their salaries among several alternatives. An employer contribution equal to 60% of the first 5% of the employees' contributions is initially invested in Company common stock. The Company's contributions to the savings-plan trust were $1.7 million in 1996, $1.6 million in 1995, and $1.8 million in 1994.
Other Post-Employment Benefits
In addition to pension and savings-plan benefits, the Company provides certain health-care and life-insurance benefits for substantially all of its retired employees.
The MPUC approved a rulemaking on SFAS No. 106, effective July 20, 1993, that adopted the accrual method of accounting for the expected cost of such benefits during the employees' years of service, and authorized the establishment of a regulatory asset for the deferral of such costs until they are "phased-in" for ratemaking purposes. The effect of the change can be reflected in annual expenses over the active service life of employees or a period of 20 years, rather than in the year of adoption.
The MPUC prescribes the maximum amortization period of the average remaining service life of active employees or 20 years, whichever is longer, for the transition obligation. The Company is utilizing a 20 year amortization period. Segregation in an external fund is required for amounts collected in rates. The Company is proposing initial funding of $3 million annually. Until amounts are funded, no return on assets will be reflected in postretirement benefit cost.
As a result of the MPUC order, the Company records the cost of these benefits by charging expense in the period recovered through rates ($9.8 million in 1996, $6.7 million in 1995, and $5.5 million in 1994), with the excess over that amount of $1.1 million in 1996, $6.2 million in 1995 and $7.1 million in 1994, deferred for future recovery. The total amount defined as a regulatory asset as of December 31, 1996 was $23 million. Concurrent with the initial ARP price change, the Company began to phase in the cost of SFAS No. 106 over a three-year period, $3 million for the first year beginning July 1, 1995 and an additional $2.1 million for the year beginning July 1, 1996. The amounts deferred until that point are being amortized over the same period as the transition obligation. A summary of the components of net periodic postretirement benefit cost for the plan in 1996, 1995 and 1994 follows:
(Dollars in thousands) 1996 1995 1994 Service cost $ 1,347 $ 846 $ 1,472 Interest on accumulated postretirement benefit obligation 5,720 7,389 6,712 Special retirement offer - 200 - Amortization of transition obligation 4,080 4,606 4,606 Amortization of prior service cost 35 42 - Amortization of gain (329) (188) (171) Postretirement benefits expense 10,853 12,895 12,619 Deferred postretirement benefits expense 1,056 6,204 7,108 Postretirement Benefit Expense Recognized in the Statement of Earnings $ 9,797 $ 6,691 $ 5,511
The following table sets forth the accumulated postretirement benefit obligation, the funded status of the plan, and the liability recognized on the Company's balance sheet at December 31, 1996 and 1995:
(Dollars in thousands) 1996 1995 Accumulated postretirement benefit obligation: Retirees $ 51,815 $ 87,632 Fully eligible active plan participants 2,707 4,791 Other active plan participants 19,381 15,069 Total accumulated postretirement benefit obligation 73,903 107,492 Plan assets, at fair value 849 879 Accumulated postretirement benefits obligation in excess of plan assets 73,054 106,613 Unrecognized net gain (loss) 15,987 (2,511) Unrecognized prior service cost (5) (1,131) Unrecognized transition obligation (59,267) (78,303) Accrued Postretirement Benefit Cost Recognized in the Balance Sheet $ 29,769 $ 24,668
The assumed health-care cost-trend rates range from 5.7% to 6.8% for 1996, reducing to 5.0% overall over a period of 25 years. Rates range from 6.4% to 9.3% for 1995, reducing to 5.0% overall, over a period of 10 years. Rates range from 6.8% to 10.4% for 1994, reducing to 5.0% overall, over a period of 10 years. The effect of a one-percentage-point increase in the assumed health-care cost-trend rate for each future year would increase the aggregate of the service and interest-cost components of the net periodic postretirement benefit cost by $0.7 million and the accumulated postretirement benefit obligation by $8.9 million. Additional assumptions used in accounting for the postretirement benefit plan in 1996, 1995 and 1994 are as follows:
1996 1995 1994 Weighted-average discount rate 7.50% 7.25% 8.25% Rate of increase in future compensation levels 4.50% 4.50% 5.0%
The Company is exploring alternatives for mitigating the cost of postretirement benefits and for funding its obligations. These alternatives include mechanisms to fund the obligation prior to actual payment of benefits, plan-design changes to limit future expense increases, and additional cost-control and cost-sharing programs.
Effective September 1, 1996, the Company implemented a phase-out of the long-term care portion of its retiree medical plans. With the exception of one group of approximately 200 retirees, all benefits of this type will be eliminated by September 1, 2002. These changes decreased Plan liabilities by approximately $16 million, based on 1996 actuarial valuation results.
Note 6: Capacity Arrangements
Power Agreements
The Company, through certain equity interests, owns a portion of the generating capacity and energy production of four nuclear generating facilities (the Yankee companies), two of which have been permanently shut down, and is obligated to pay its proportionate share of costs, which include fuel, depreciation, operation-and-maintenance expenses, a return on invested capital, and the estimated cost of decommissioning the nuclear plants.
Pertinent data related to these power agreements as of December 31, 1996, are as follows:
(Dollars in thousands) Maine Yankee Vermont Connecticut Yankee Yankee Yankee* Atomic* Ownership share 38% 4% 6% 9.5% Contract expiration date 2008 2012 1998 2000 Capacity (MW) 879 531 -- -- Company's share of: Capacity (MW) 329 19 -- -- Estimated 1996 costs $ 79,282 $ 6,525 $ 12,355 $ 4,896 Long-term obligations and redeemable preferred stock $ 94,559 $ 6,950 $ 10,447 $ -- Estimated decommissioning obligation $118,586 $ 13,150 $ 45,769 $16,463 Accumulated decommissioning fund $ 61,254 $ 5,474 $ 12,269 $11,408 * See following for discussion on Connecticut Yankee and Yankee Atomic
Under the terms of its agreements, the Company pays its ownership share (or entitlement share) of estimated decommissioning expense to each of the Yankee companies and records such payments as a cost of purchased power. Effective August 16, 1988, Maine Yankee Atomic Power Company (Maine Yankee) began collecting $9.1 million annually for decommissioning. In 1994, Maine Yankee, pursuant to FERC authorization, increased its annual collection to $14.9 million and reduced its return on common equity to 10.65%, for a total increase in rates of approximately $3.4 million. The increase in decommissioning collection is based on the estimated cost of decommissioning the Maine Yankee Plant, assuming dismantling and removal, of $317 million (in 1993 dollars) based on a 1993 external engineering study. Accumulated decommissioning funds were $163.5 million as of December 31, 1996. The estimated cost of decommissioning nuclear plants is subject to change due to the evolving technology of decommissioning and the possibility of new legal requirements.
The Maine Yankee Plant, like other pressurized water reactors, experienced 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 tubes. During a refueling and maintenance shutdown in February 1995, Maine Yankee detected through new inspection methods that approximately 60% of the Plant's 17,000 steam generator tubes appeared to have defects.
Following a detailed analysis of safety, technical and financial considerations, Maine Yankee repaired the tubes by inserting and welding short reinforcing sleeves of an improved material in substantially all of the Plant's steam generator tubes, which was completed in December 1995. The Company's approximately $10-million share of the repair costs adversely affected the Company's 1995 earnings by $0.18 per share, net of taxes, in spite of significant cost-reduction measures implemented by both the Company and Maine Yankee. In addition, the Company's incremental replacement-power costs during the outage totaled approximately $29 million, or $0.52 per share, net of taxes, for 1995.
Also in December 1995, the Nuclear Regulatory Commission's (NRC) Office of the Inspector General (OIG) and its Office of Investigations (OI) initiated separate investigations of certain anonymous "whistleblower" allegations of wrongdoing by Maine Yankee and Yankee Atomic Electric Company (Yankee Atomic) in 1988 and 1989 in connection with operating license amendments. On May 9, 1996, the OIG, which was responsible for investigating only the actions of the NRC staff and not those of Maine Yankee or Yankee Atomic, issued its report on its investigation. The report found deficiencies in the NRC staff's review, documentation, and communications practices in connection with the license amendments, as well as "significant indications of possible licensee violations of NRC requirements and regulations." Any such violations by Maine Yankee are within the purview of the OI investigation, which, with related issues, is being reviewed by the United States Department of Justice. A separate internal investigation commissioned by the boards of directors of Maine Yankee and Yankee Atomic and conducted by an independent law firm noted several areas that could have been improved, including regulatory communications, definition of responsibilities between Maine Yankee and Yankee Atomic, and documentation and tracking of regulatory compliance, but found no wrongdoing by Maine Yankee or Yankee Atomic or any of their employees. Issues raised as a result of the anonymous allegations caused the NRC to limit the Plant to an operating level of approximately 90% of its full thermal capacity, pending resolution of those issues. The Company cannot predict the results of the investigations by the OI and Department of Justice.
On January 11, 1996, Maine Yankee began start-up operations and was up to a 90% generation level on January 24, 1996. The Plant operated substantially at that level until July 20, 1996, when it was taken off-line after a comprehensive review by Maine Yankee of the Plant's systems and equipment revealed a need to add pressure-relief capacity to the Plant's primary component cooling system. On August 18, 1996, while the Plant was in the restart process, Maine Yankee conducted a review of its electrical circuitry testing procedures pursuant to a generic NRC letter to nuclear-plant licensees that was intended to ensure that every feature of every safety system be routinely tested. During the expanded review, Maine Yankee found a deficiency in an electrical circuit of a safety system and therefore elected to conduct an intensified review of other safety-related circuits to resolve immediately any questions as to the adequacy of related testing procedures. The Plant returned to the 90% operating level on September 3, 1996.
On December 6, 1996, Maine Yankee took the Plant off-line to resolve cable-separation and associated issues. On January 3, 1997, Maine Yankee announced that it would use the opportunity presented by that outage to inspect the Plant's 217 fuel assemblies, since daily monitoring had indicated evidence of a small number of defective fuel rods. As a result of the inspection, Maine Yankee determined that all of the assemblies manufactured by one supplier and currently in the reactor core (approximately one-third of the total) have to be replaced. Maine Yankee will therefore keep the Plant off-line for refueling, which had previously been scheduled for late 1997. In addition, Maine Yankee will make use of the outage to inspect the Plant's steam generators for deterioration beyond that which was repaired during the extended 1995 outage. Degradation of steam generators of the age and design of those in use in the Plant has been identified at other plants.
In January 1997, the NRC announced that it had placed the Plant on its "watch list" in "Category 2", which includes plants that display "weaknesses that warrant increased NRC attention", but which are not severe enough to warrant a shut-down order. Plants in category 2 remain in that category "until the licensee demonstrates a period of improved performance." The Plant is one of fourteen nuclear units on the watch list announced that day by the NRC, which regulates slightly over 100 civilian nuclear power plants in the United States.
After year end, Maine Yankee and Entergy Nuclear, Inc. (Entergy), which is a subsidiary of Entergy Corporation, a Louisiana-based utility holding company and leading nuclear plant operator, entered into a contract under which Entergy is providing management services to Maine Yankee at the same time, officials from Entergy assumed management positions, including President, at Maine Yankee.
The Maine Yankee nuclear plant was shut down on December 6, 1996, for inspection and repairs. While the plant is out service, Maine Yankee must, in addition to replacing the fuel assemblies, conduct an intensive inspection of its steam generators, resolve cable-separation issues and other regulatory issues, and obtain the approval of the NRC to restart the plant. The Company believes the plant will be out of service at least until August 1997, but cannot predict when or whether all of the regulatory and operational issues will be satisfactorily resolved or what effect the repairs and improvements to the plant will have on the economics of operating the plant.
The Company will incur significantly higher costs in 1997 for its share of inspection, repairs and refueling costs at Maine Yankee and will also need to purchase replacement power while the plant is out of service. While the amount of higher costs is uncertain, Maine Yankee has indicated that it expects it operations and maintenance costs to increase by up to approximately $45 million in 1997, before refueling costs. The Company's share of such costs based on its power entitlement of approximately 38% would be up to approximately $17 million. In addition, the Company estimates its share of the refueling costs will amount to approximately $15 million, of which $10.4 million has been accrued as of December 31, 1996. The Company has been incurring incremental replacement-power costs of approximately $1 million per week while the plant has been out of service and expects such costs to continue at approximately the same rate until the plant returns to service.
The impact of these higher nuclear related costs on the Company's 1997 financial results will be significant and is likely to trigger the low earnings bandwidth provision of the ARP. Under the ARP actual earnings for 1997 outside a bandwidth of 350 basis points, above or below a 10.68% rate of return allowance, triggers the profit sharing mechanism. A return below the low end of the range provides for additional revenue through rates equal to one-half of the difference between the actual earned rate of return and the 7.18% (10.68 - 3.50) low end of the bandwidth. While the Company believes that the profit sharing mechanism is likely to be triggered in 1997, it cannot predict the amount, if any, of additional revenues that may ultimately result.
Condensed financial information on Maine Yankee Atomic Power Company is as follows:
(Dollars in thousands) 1996 1995 1994 Earnings: Operating revenues $185,661 $205,977 $173,857 Operating income 17,150 18,527 16,223 Net income 8,106 8,571 8,573 Earnings applicable to common stock 6,637 7,057 7,014 Company's Equity Share of Net Earnings $ 2,522 $ 2,682 $ 2,665 Investment: Net electric property and nuclear fuel $222,360 $242,399 $254,820 Current assets 44,979 34,799 38,950 Deferred charges and other assets 334,722 303,760 256,140 Total Assets 602,061 580,958 549,910 Less: Redeemable preferred stock 18,000 18,600 19,200 Long-term obligations 223,572 224,185 226,491 Current liabilities 34,265 30,904 29,210 Reserves and deferred credits 255,472 236,653 208,100 Net Assets $ 70,752 $ 70,616 $ 66,909 Company's Equity in Net Assets $ 26,886 $ 26,834 $ 25,425
In December 1996, the Board of Directors of Connecticut Yankee Atomic Power Company announced a permanent shutdown of the Connecticut Yankee plant in Haddam, Connecticut, and decided to decommission the plant for economic reasons. An economic analysis conducted by Connecticut Yankee estimates that the early closing of the Plant would save over $100 million (net present value) over its remaining license life to the year 2007, compared with the costs of continued operation. The Company has a 6% equity interest in Connecticut Yankee, totaling approximately $6.4 million at December 31, 1996. The plant did not operate after July 22, 1996. The Company estimates its share of the cost of Connecticut Yankee's continued compliance with regulatory requirements, recovery of its plant investments, decommissioning and closing the plant to be approximately $45.8 million and has recorded a regulatory asset and a liability on the consolidated balance sheet. The Company is currently recovering through rates an amount adequate to recover these expenses.
On February 26, 1992, the Board of Directors of Yankee Atomic Electric Company (Yankee Atomic) decided to permanently discontinue power operation at the Yankee Atomic Plant in Rowe, Massachusetts, and to decommission that facility. The Company relied on Yankee Atomic for less than 1% of the Company's system capacity. Its 9.5% equity investment in Yankee Atomic is approximately $2.2 million.
On March 18, 1993, the FERC approved a settlement agreement regarding the Yankee Atomic decommissioning plan, recovery of plant investment, and all issues with respect to prudence of the decision to discontinue operation. The Company has estimated its remaining share of the cost of Yankee Atomic's continued compliance with regulatory requirements, recovery of its plant investments, decommissioning and closing the plant, to be approximately $16.5 million. This estimate, which is subject to ongoing review and revision, has been recorded by the Company as a regulatory asset and a liability on the accompanying consolidated balance sheet. As part of the MPUC's decision in the Company's 1993 base-rate case, the Company's current share of costs related to the deactivation of Yankee Atomic is being recovered through rates.
The Company has approximately a 60% ownership interest in the jointly owned, Company-operated, 620-megawatt oil-fired W. F. Wyman Unit No. 4. The Company also has a 2.5% ownership interest in the Millstone Unit No. 3 nuclear plant operated by Northeast Utilities, and is entitled to approximately 29-megawatt share of that unit's capacity. The Company's share of the operating costs of these units is included in the appropriate expense categories in the Consolidated Statement of Earnings. The Company's plant in service, nuclear fuel, decommissioning fund, and related accumulated depreciation and amortization attributable to these units as of December 31, 1996, and 1995 were as follows:
Millstone Unit No. 3 has been out of service since April, 1996, due to NRC concerns regarding operating license requirements and the Company cannot predict when it will return to service. The Company estimates that it will incur approximately $300,000 to $500,000 in replacement power costs each month Millstone Unit No. 3 remains out of service. The Company incurred replacement power costs of $3.5 million in 1996.
Power-Pool Agreements
The New England Power Pool, of which the Company is a member, has contracted in its Hydro-Quebec Projects to purchase power from Hydro-Quebec. The contracts entitle the Company to 85.9 megawatts of capacity credit in the winter and 127.25 megawatts of capacity credit during the summer. The Company has entered into facilities-support agreements for its share of the related transmission facilities. The Company's share of the support responsibility and of associated benefits is approximately 7%.
The Company is making facilities-support payments on approximately $28.8 million, its remaining share of the construction cost for these transmission facilities incurred through December 31, 1996. These obligations are reflected on the Company's consolidated balance sheet as lease obligations with a corresponding charge to electric property.
Non-Utility Generators
The Company has entered into a number of long-term, non-cancelable contracts for the purchase of capacity and energy from non-utility generators (NUG). The agreements generally have terms of five to 30 years, with expiration dates ranging from 1997 to 2021. They require the Company to purchase the energy at specified prices per kilowatt-hour, which are often above market prices. As of December 31, 1996, facilities having 573 megawatts of capacity covered by these contracts were in-service. The costs of purchases under all of these contracts amounted to $313.4 million in 1996, $314.4 million in 1995, and $373.5 million in 1994.
During 1996, the Company reached agreement with three NUGs to buy out contracts or to give the Company options to restructure their contracts through lump-sum or periodic payments. In accordance with prior MPUC policy and the ARP, at December 31, 1996, $113 million of buy-out or restructuring costs incurred since January 1992 were included in Deferred Charges and Other Assets on the Company's balance sheet and are amortized over their respective fuel savings periods.
The Company's estimated contractual obligations with NUGs as of December 31, 1996, are as follows:
(Dollars in Amount millions) 1997 $ 331 1998 291 1999 295 2000 294 2001 268 2002 - 2015 2,369 $3,848
In early 1996, the Company entered into a restructuring agreement with Maine Energy Recovery Company (MERC), a 20 megawatt waste to energy facility located in Biddeford, Maine. The agreement provides for a significant reduction in energy rates for energy sold to the Company and extended the previous power contract five years. In addition, the Company will make capacity payments to CL Power Sales One.
Note 7: Capitalization and Interim Financing
Retained Earnings
Under terms of the most restrictive test in the Company's General and Refunding Mortgage Indenture and the Company's Articles of Incorporation, no dividend may be paid on the common stock of the Company if such dividend would reduce retained earnings below $29.6 million. At December 31, 1996, the Company's retained earnings were $72.5 million, of which $42.9 million were not so restricted.
Mortgage Bonds
Substantially all of the Company's electric-utility property and franchises are subject to the lien of the General and Refunding Mortgage.
The Company's outstanding Mortgage Bonds may be redeemed at established prices plus accrued interest to the date of redemption, subject to certain refunding limitations. Bonds may also be redeemed under certain conditions at their principal amount plus accrued interest by means of cash deposited with the trustee under certain provisions of the mortgage indenture. In 1996, the Company deposited approximately $29.6 million in cash with the Trustee under the Company's General and Refunding Mortgage Indenture in satisfaction of the renewal and replacement fund and other obligations under the Indenture. The total of such cash on deposit with the Trustee as of December 31, 1996, was approximately $59.5 million. Under the Indenture such cash may be applied at any time, at the direction of the Company, to the redemption of bonds outstanding under the Indenture at a price equal to the principal amount of the bonds being redeemed, without premium, plus accrued interest to the date fixed for redemption. Such cash may also be withdrawn by the Company by substitution of allocated property additions or available bonds.
Mortgage Bonds outstanding as of December 31, 1996, and 1995 were as follows:
(Dollars in thousands)
Limitations on Unsecured Indebtedness
The Company's Articles of Incorporation limit certain unsecured indebtedness that may be outstanding to 20% of capitalization, as defined; 20% of defined capitalization amounted to $219 million as of December 31, 1996. Unsecured indebtedness, as defined, amounted to $96 million as of December 31, 1996.
In May 1989, holders of the Company's preferred stock consented to the issuance of unsecured Medium-Term Notes in an aggregate principal amount of $150 million outstanding at any one time; the notes are therefore not subject to such limitations.
Medium-Term Notes
Under the terms of the Company's Medium-Term Note program, the Company may offer Medium-Term Notes up to an aggregate principal amount of $150 million. Maturities can range from nine months to 30 years; interest rates pertaining to such notes are established at the time of issuance. Interest on fixed-rate notes is payable on March 1 and September 1, while interest on floating-rate notes is payable on the dates indicated thereupon.
Medium-Term Notes outstanding as of December 31, 1996, and 1995 were as follows:
(Dollars in thousands) Maturity Interest rate 1996 1995 Series A: 2000 9.65% $ 5,000 $ 5,000 Series B: 1996-1998 4.92-7.98 23,000 57,000 Series C: 1997-2001 7.40-7.50 40,000 30,000 Total Medium-Term Notes $68,000 $92,000
Pollution-Control Facility and Other Notes
Pollution-control facility and other notes outstanding as of December 31, 1996, and 1995 were as follows:
(Dollars in thousands) Series Interest rate Maturity 1996 1995 Central Maine Power Company: Yarmouth Installment Notes 6 3/4% June 1, 2002 $10,250 $10,250 Yarmouth Installment Notes 6 3/4 December 1, 2003 1,000 1,000 Industrial Development Authority of the State of 7 3/8 May 1, 2014 11,000 11,000 New Hampshire Notes 7 3/8 May 1, 2014 8,500 8,500 Finance Authority of Maine 8.16 January 1, 2005 60,129 66,429 Maine Electric Power Company, Inc.: Promissory Notes Variable* July 1, 1996 - 1,730 Variable* November 1, 2000 820 Total Pollution-Control Facility and Other Notes $91,699 $98,909 *The average rate was 6.3% in 1996 and 6.7% in 1995.
The bonds issued by the Industrial Development Authority of the State of New Hampshire are supported by loan agreements between the Company and the Authority. The bonds are subject to redemption at the option of the Company at their principal amount plus accrued interest and premium, beginning in 2001.
In September 1994, the Finance Authority of Maine (FAME) approved the Company's application for funds to finance the contract buy-out of a NUG contract for a 32-megawatt wood fired generating plant in Fort Fairfield, Maine. On October 26, 1994, FAME issued $79.3 million of Taxable Electric Rate Stabilization Revenue Notes Series 1994A (FAME notes). FAME and the Company entered into a loan agreement under which the Company issued FAME a note for approximately $66.4 million, evidencing a loan in that amount. The proceeds of the loan, along with $13 million of the Company's own funds, were used to buy out the Fort Fairfield contract. Concurrently, the Company purchased all of the common stock of Aroostook Valley Electric Company (AVEC) for $2 million. On October 26, 1994, AVEC paid the former owners of the Fort Fairfield facility $2 million and took title to the facility. In connection with the FAME financing, AVEC granted FAME a mortgage on the facility. The remaining $12.9 million of FAME-notes proceeds was placed in a capital-reserve account. The amount in the capital-reserve account is equal to the highest amount of principal and interest on the FAME notes to accrue and come due in any year the FAME notes are outstanding. The amounts invested in the capital reserve account are initially invested in government securities designed to generate interest income at a rate equal to the interest on the FAME notes. Under the terms of the loan agreement, the Company is also responsible for or receives the benefit from the interest rate differential and investment gains and losses on the capital reserve account.
Capital Lease Obligations
The Company leases a portion of its buildings and equipment under lease arrangements, and accounts for certain transmission agreements as capital leases using periods expiring between 2006 and 2021. The net book value of property under capital leases was $33.1 million and $35.1 million at December 31, 1996, and 1995, respectively. Assets acquired under capital leases are recorded as electric property at the lower of fair-market value or the present value of future lease payments, in accordance with practices allowed by the MPUC, and are amortized over their contract terms. The related obligation is classified as other long-term debt. Under the terms of the lease agreements, executory costs are excluded from the minimum lease payments.
Estimated future minimum lease payments for the five years ending December 31, 2001, together with the present value of the minimum lease payments, are as follows:
(Dollars in thousands) Amount 1997 $ 5,619 1998 5,447 1999 5,276 2000 5,105 2001 4,934 Thereafter 56,298 Total minimum lease payments 82,679 Less: amounts representing interest 46,396 Present Value of Net Minimum Lease Payments $36,283
Sinking-Fund Requirements
Consolidated sinking-fund requirements for long-term obligations, including capital lease payments and maturing debt issues, for the five years ending December 31, 2001, are as follows:
(Dollars in thousands) Sinking fund Maturing debt Total 1997 $ 2,375 $ 25,000 $ 27,375 1998 9,212 178,000 187,212 1999 9,855 60,000 69,855 2000 10,520 80,000 90,520 2001 10,950 21,000 31,950
Operating Lease Obligations
The Company has a number of operating-lease agreements primarily involving computer and other office equipment, land, and telecommunication equipment. These leases are noncancelable and expire on various dates through 2007.
Following is a schedule by year of future minimum rental payments required under the operating leases that have initial or remaining noncancelable lease terms in excess of one year as of December 31, 1996:
(Dollars in thousands) Amount 1997 $4,277 1998 4,042 1999 3,278 2000 3,123 2001 3,099 Thereafter 1,936 $19,755
Rent expense under all operating leases was approximately $5 million, $5.7 million, and $7 million for the years ended December 31, 1996, 1995 and 1994, respectively.
Disclosure of Fair Value of Financial Instruments
The methods and assumptions used to estimate the fair value of each class of financial instruments for which it is practicable are discussed below. The carrying amounts of cash and temporary investments approximate fair value because of the short maturity of these investments. The fair value of redeemable preferred stock and pollution-control facility and other notes is based on quoted market prices as of December 31, 1996 and 1995. The fair value of long-term obligations is based on quoted market prices for the same or similar issues, or on the current rates offered to the Company based on the weighted average life of each class of instruments. The estimated fair values of the Company's financial instruments as of December 31, 1996, and 1995 are as follows:
Preferred Stock
Preferred-stock balances outstanding as of December 31, 1996, 1995, and 1994 were as follows:
*Total authorized $100 par value callable is 2,300,000 shares. Shares outstanding are classified as Not Subject to Mandatory Redemption and Subject to Mandatory Redemption.
Sinking-fund provisions for the 8 7/8% Series Preferred Stock require the Company to redeem all shares at par plus an amount equal to dividends accrued to the redemption date on the basis of 70,000 shares annually commencing on July, 1996. The Company also has the non-cumulative right to redeem up to an equal amount of the respective number of shares annually, beginning in 1996, at par plus an amount equal to dividends accrued to the redemption date. The sinking-fund requirement for the five-year period ending December 31, 2000 is $7.0 million annually beginning in 1996. The Company redeemed $14 million of these shares at par in 1996 pursuant to the mandatory and optional sinking-fund provisions.
Sinking-fund provisions for the Flexible Money Market Preferred Stock, Series A, 7.999%, require the Company to redeem all shares at par plus an amount equal to dividends accrued to the redemption date on the basis of 90,000 shares annually beginning in October 1999. The Company also has the non-cumulative right to redeem up to an equal number of shares annually beginning in 1999, at par plus an amount equal to dividends accrued to the redemption date. The sinking-fund requirement for the five-year period ending December 31, 2000, is $9 million annually beginning in 1999. In 1995, the Company purchased 54,725 shares on the open market that may be used to reduce the sinking-fund requirement in 1999.
Interim Financing and Credit Agreements
The Company uses funds obtained from short-term borrowing to provide initial financing for construction and other corporate purposes.
To support its short-term capital requirements, on October 23, 1996 , the Company entered into a $125 million revolving credit facility with several banks, with The First National Bank of Boston and The Bank of New York acting as agents for the lenders. The credit facility has two tranches which consist of: a $75 million 364-day revolving credit facility which matures on October 22, 1997 and a $50-million 3-year revolving credit facility which matures on October 23, 1999. Both credit facilities require annual fees on the unused portion of the credit lines which are based on the Company's credit ratings and allow for various borrowing options including LIBOR-priced, base-rate-priced and competitive-bid-priced loans. The amount of outstanding short-term borrowing will fluctuate with day-to-day operational needs, the timing of long-term financing, and market conditions. There was $7.5 million outstanding as of December 31, 1996, under this credit agreement.
Note 8: Quarterly Financial Data (Unaudited)
Quarterly revenue variability increased after January 1, 1995, when the ARP replaced MPUC rules prescribing different revenue allocations for energy sold in winter versus non-winter months. Twelve-month results are unaffected by this reporting change.
Unaudited, consolidated quarterly financial data pertaining to the results of operations are shown below.
*Earnings per share are computed using the weighted-average number of common shares outstanding during the applicable quarter.
Item 9.
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
Not applicable.
PART III
Item 10.
Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
See the information under the heading "Election of Directors" in the registrant's definitive proxy material for its annual meeting of shareholders to be held on May 15, 1997, and Item 4.1, Executive Officers of the Registrant, above, both of which are hereby incorporated herein by reference.
Item 11.
Item 11. EXECUTIVE COMPENSATION.
See the information under the heading "Board Committees, Meetings and Compensation" and the heading "Executive Compensation" in the registrant's definitive proxy material for its annual meeting of shareholders to be held on May 15, 1997, which is hereby incorporated herein by reference.
Item 12.
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
See the information under the heading "Security Ownership" in the registrant's definitive proxy material for its annual meeting of shareholders to be held on May 15, 1997, which is hereby incorporated herein by reference.
Item 13.
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
See the information under the heading, "Board Committees, Meetings and Compensation" in the registrant's definitive proxy material for its annual meeting of shareholders to be held on May 15, 1997, which is hereby incorporated herein by reference.
PART IV
Item 14.
Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
(a) List of documents filed as part of this report:
(1) Financial Statements and Supplementary Data See the Index to Financial Statements and Schedules under Item 8 in Part II hereof, where these documents are listed, on page 42. (2) Exhibits - see (c) below.
(b) Reports on Form 8-K. The Company filed the following reports on Form 8-K during the last quarter of 1996 and thereafter to date:
Date of Report Items Reported
December 4, 1996 Item 5
The Company reported on Maine Yankee Atomic Power Company's response to the NRC's Independent Safety Assessment.
The Board of Directors of Connecticut Yankee Atomic Power Company voted to permanently discontinue power operation at the Connecticut Yankee plant at Haddam, Connecticut ("CY Plant"), and to decommission the CY Plant, for reasons based on the economics of continuing to operate the unit.
Date of Report Items Reported
December 18, 1996 Item 5
On December 20, 1996, Maine Yankee Atomic Power Company announced that its President and Chief Executive Officer, Charles D. Frizzle, had submitted his registration to facilitate a broad restructuring effort.
On December 18, 1996, Moody's Investors Service placed the credit ratings of the Company under review for possible downgrade.
Date of Report Items Reported
December 31, 1996 Item 5
The Company reported that on December 31, 1996, the MPUC issued its Report and Recommended Plan on Electric Utility Industry Restructuring.
The Company reported the inspection of fuel assemblies and resolution of the cable-separation and associated issues at the Maine Yankee Atomic Power Company nuclear generating plant and that Maine Yankee and Entergy Corporation, a Louisiana-based utility holding company and nuclear plant operator, announced the signing of a memorandum of understanding for Entergy to provide management services to Maine Yankee.
Date of Report Items Reported
January 29, 1997 Item 5
On January 29, 1997, the NRC announced that it had placed the Plant on its "watch list," in "Category 2," which includes plants that display "weaknesses that warrant increased NRC attention," but which are not severe enough to warrant a shut-down order.
The Company reported on a Maine-based group which had announced its intention to start gathering signatures aimed at a new referendum to force a permanent shutdown of the Maine Yankee Atomic Power Company Plant.
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, in the City of Augusta, and State of Maine on the 27th day of March, 1997.
CENTRAL MAINE POWER COMPANY
By David E. Marsh Vice President, Corporate Services, Treasurer, and Chief Financial Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons in the capacities and on the dates indicated.
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO
SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR
ENDED DECEMBER 31, 1996
CENTRAL MAINE POWER COMPANY
File No. 1-5139
(Exact name of Registrant as specified in charter)
EXHIBITS
EXHIBIT INDEX
The following designated exhibits, as indicated below, are either filed herewith or have heretofore been filed with the Securities and Exchange Commission under the Securities Act of 1933, the Securities Exchange Act of 1934 or the Public Utility Holding Company Act of 1935 and are incorporated herein by reference to such filings. Reference is made to Item 8 of this Form 10-K for a listing of certain financial information and statements incorporated by reference herein.
Notes: (A) Amounts charged off as uncollectible after deducting customers' deposits and recoveries of accounts previously charged off. (B) Amounts transferred to capital accounts. (C) Principally payments for various injuries and damages and expenses in connection therewith. (D) Amounts charged to regulatory asset account.
Notes: (A) Amounts charged off as uncollectible after deducting customers' deposits and recoveries of accounts previously charged off. (B) Amounts charged to capital accounts. (C) Principally payments for various injuries and damages and expenses in connection therewith. (D) To adjust the estimated minimum liability balance for a change in clean-up method. (E) Amounts transferred to deferred credit account. (F) Reversal of reserve.
Notes: (A) Amounts charged off as uncollectible after deducting customers' deposits and recoveries of accounts previously charged off. (B) Amounts charged to capital accounts. (C) Principally payments for various injuries and damages and expenses in connection therewith. (D) Amounts charged to regulatory asset account. (E) Amounts paid, charged against the reserve.